NORTHERN OIL & GAS, INC.
10-Ks and 10-Qs
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UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
DC 20549
FORM
10-K
(Mark
One)
T
ANNUAL REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For
the fiscal year ended December 31, 2009
or
£
TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the
transition period from __________________ to __________________
Commission
File No. - 000-33999
__________________
NORTHERN
OIL AND GAS, INC.
(
Exact Name of Registrant as
Specified in Its Charter
)
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Nevada
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95-3848122
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|
(
State or Other Jurisdiction of
Incorporation or Organization
)
|
(I.R.S. Employer
Identification No.)
|
315
Manitoba Avenue – Suite 200, Wayzata, Minnesota 55391
(
Address of Principal Executive
Offices
) (
Zip Code
)
952-476-9800
(
Registrant’s Telephone Number,
Including Area Code
)
Securities
registered pursuant to Section 12(b) of the Act:
|
Title
of Each Class
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Name
of Each Exchange On Which Registered
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|
|
Common
Stock, $0.001 par value
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NYSE
Amex Equities Market
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|
Securities
registered pursuant to Section 12(g) of the Act:
|
None
|
|
(
Title of
Class
)
|
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Yes
£
No
T
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Act.
Yes
£
No
T
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
T
No
£
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
£
No
£
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405) is not contained herein, and will not be contained, to
the best of registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
T
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a small reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large
Accelerated Filer
£
Accelerated
Filer
T
Non-Accelerated
Filer
£
Smaller
Reporting Company
£
(Do
not check if a smaller reporting company)
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes
£
No
T
State the
aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of the
last business day of the registrant’s most recently completed second fiscal
quarter.
The
aggregate market value of the registrant’s voting and non-voting common equity
held by non-affiliates of the registrant on the last business day of the
registrant’s most recently completed second fiscal quarter (based on the closing
sale price as reported by the NYSE Amex Equities Market) was approximately
$192,730,733.
Indicate
the number of shares outstanding of each of the registrant’s classes of common
stock, as of the latest practicable date.
As of
March 1, 2010, the registrant had 43,911,044 shares of common stock issued and
outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the proxy statement related to the registrant’s 2010 Annual Meeting of
Stockholders are incorporated by reference into Part III of this
report.
CAUTIONARY
STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
We are
including the following discussion to inform our existing and potential security
holders generally 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.
From time
to time, our management or persons acting on our behalf may make forward-looking
statements to inform existing and potential security holders about our
company. All statements other than statements of historical facts
included in this report regarding our financial position, business strategy,
plans and objectives of management for future operations, industry conditions,
and indebtedness covenant compliance are forward-looking
statements. When
used in this report, forward-looking statements are generally accompanied by
terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,”
“anticipate,” “target,” “plan,” “intend,” “seek,” “goal,” “will,” “should,”
“may” or other words and similar expressions that convey the uncertainty of
future events or outcomes. Items contemplating or making assumptions
about, actual or potential future sales, market size, collaborations, and trends
or operating results also constitute such forward-looking
statements.
Forward-looking
statements involve inherent risks and uncertainties, and important factors (many
of which are beyond our company’s control) that could cause actual results to
differ materially from those set forth in the forward-looking statements,
including the following: general economic or industry conditions,
nationally and/or in the communities in which our company conducts business,
changes in the interest rate environment, legislation or regulatory
requirements, conditions of the securities markets, our ability to raise
capital, changes in accounting principles, policies or guidelines, financial or
political instability, acts of war or terrorism, other economic, competitive,
governmental, regulatory and technical factors affecting our company’s
operations, products, services and prices.
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. Accordingly, results actually
achieved may differ materially from expected results in these
statements. Forward-looking statements speak only as of the date they
are made. You should consider carefully the statements in “Item
1A. Risk Factors” and other sections of this report, which describe
factors that could cause our actual results to differ from those set forth in
the forward-looking statements. Our company does not undertake, and
specifically disclaims, any obligation to update any forward-looking statements
to reflect events or circumstances occurring after the date of such
statements.
Readers
are urged not to place undue reliance on these forward-looking statements, which
speak only as of the date of this report. We assume no obligation to
update any forward-looking statements in order to reflect any event or
circumstance that may arise after the date of this report, other than as may be
required by applicable law or regulation. Readers are urged to
carefully review and consider the various disclosures made by us in our reports
filed with the United States Securities and Exchange Commission (the “SEC”)
which attempt to advise interested parties of the risks and factors that may
affect our business, financial condition, results of operation and cash
flows. If one or more of these risks or uncertainties materialize, or
if the underlying assumptions prove incorrect, our actual results may vary
materially from those expected or projected.
NORTHERN
OIL AND GAS, INC.
TABLE
OF CONTENTS
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Page
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Part
I
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||
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Item 1.
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Business
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2
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Item
1A.
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Risk
Factors
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8
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Item
1B.
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Unresolved
Staff Comments
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17
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Item 2.
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Properties
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17
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Item 3.
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Legal
Proceedings
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21
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Item
4.
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Reserved
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21
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Part
II
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Item 5.
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Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
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21
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Item 6.
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Selected
Financial Data
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23
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Item 7.
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Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
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25
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Item 7A.
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Quantitative
and Qualitative Disclosures About Market Risk
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31
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Item 8.
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Financial
Statements and Supplementary Data
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32
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Item
9.
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Changes
in and Disagreements With Accountants on Accounting and Financial
Disclosure
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32
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Item 9A.
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Controls
and Procedures
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32
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Item 9B.
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Other
Information
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34
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Part
III
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||
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Item 10.
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Directors,
Executive Officers and Corporate Governance
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35
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Item 11.
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Executive
Compensation
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35
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Item 12.
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Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
|
36
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Item 13.
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Certain
Relationships and Related Transactions, and Director
Independence
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36
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Item 14.
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Principal
Accountant Fees and Services
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36
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Part
IV
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||
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Item 15.
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Exhibits
and Financial Statement Schedules
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37
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Signatures
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40 | |
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Index
to Financial Statements
|
F-1 | |
NORTHERN
OIL AND GAS, INC.
2009
ANNUAL REPORT ON FORM 10-K
Overview
Our
company took its present form on March 20, 2007, when Northern Oil and Gas, Inc.
(“Northern”), a Nevada corporation engaged in our company’s current business,
merged with and into our subsidiary, with Northern remaining as the surviving
corporation (the “Merger”). Northern then merged into us, and we were
the surviving corporation. We then changed our name to Northern Oil
and Gas, Inc. As a result of the Merger, Northern was deemed to be
the acquiring company for financial reporting purposes and the transaction has
been accounted for as a reverse merger. The financial statements
presented in our company’s December 31, 2006, Form 10-KSB report were the
historical financial statements of Kentex Petroleum, Inc., the predecessor
company. Additional material terms of the Merger are detailed in our
company’s Current Report on Form 8-K filed with the SEC on December 19,
2006. Following the Merger, our main business focus has been directed
to oil and gas exploration and development. Unless specifically
stated otherwise, our primary operations are now those formerly operated by
Northern as well as other business activities since March 2007.
On March
17, 2008 our company received an approval letter to begin trading on the
American Stock Exchange (the “AMEX”). Our common stock commenced
trading on the AMEX on March 26, 2008 under the symbol “NOG.” Our
common stock commenced trading on the floor of the NYSE on the NYSE Amex
Equities Market platform upon completion of NYSE Euronext’s acquisition of the
American Stock Exchange.
Business
We are a
growth-oriented independent energy company engaged in the acquisition,
exploration, exploitation and development of oil and natural gas properties, and
have focused our activities primarily on projects based in the Rocky Mountain
Region of the United States, specifically the Bakken and Three Forks/Sanish
formations within the Williston Basin. We believe that we are able to
create value via strategic acreage acquisitions and convert that value or
portion thereof into production by utilizing experienced industry partners
specializing in the specific areas of interest. We have targeted
specific prospects and began drilling for oil in the Williston Basin region in
the fourth fiscal quarter of 2007. As of March 1, 2010, we owned
working interests in 188 successful discoveries, consisting of 185 targeting the
Bakken/Three Forks formation and three targeting a Red River
structure.
As an
exploration company, our business strategy is to identify and exploit repeatable
and scalable resource plays that can be quickly developed and at low
costs. We also intend to take advantage of our expertise in
aggressive land acquisition to pursue exploration and development projects as a
non-operating working interest partner, participating in drilling activities
primarily on a heads-up basis proportionate to our working
interest. Our business does not depend upon any intellectual
property, licenses or other proprietary property unique to our company, but
instead revolves around our ability to acquire mineral rights and participate in
drilling activities by virtue of our ownership of such rights and through the
relationships we have developed with our operating partners. We
believe our competitive advantage lies in our ability to acquire property,
specifically in the Williston Basin, in a nimble and efficient
fashion.
We are
focused on maintaining a low overhead structure. We believe we
are in a position to most efficiently exploit and identify high production oil
and gas properties due to our unique non-operator model through which we are
able to diversify our risk and participate in the evolution of technology by the
collective expertise of those operators with which we partner. We
intend to continue to carefully pursue the acquisition of properties that fit
our profile.
2
Reserves
We
completed our initial reservoir engineering calculations in the first fiscal
quarter of 2008 and recently completed our most current reservoir engineering
calculation as of December 31, 2009. At year-end, we had completed
drilling on approximately 10% of our Bakken prospective acreage inventory
assuming 640-acre spacing units. The value of our reserves is
calculated by determining the present value of estimated future revenues to be
generated from the production of our proved reserves, net of estimated lease
operating expenses, production taxes and future development
costs. All of our proved reserves are located in North Dakota and
Montana.
The
tables below summarize our estimated proved reserves as of December 31, 2009
based upon reports prepared by Ryder Scott Company, LP (“Ryder Scott”), an
independent reservoir engineering firm. Ryder Scott is one of the
largest reservoir-evaluation consulting firms and evaluates oil and gas
properties and independently certifies petroleum reserves quantities for various
clients throughout the United States and internationally.
Ryder
Scott prepared two separate reserve reports valuing our proved reserves at
December 31, 2009. The reports value only our proved reserves and do
not value our probable reserves or our possible reserves. Both tables
account for straight-line pricing of crude oil and natural gas at constant
prices over the expected life of our wells. Our “SEC Pricing Proved
Reserves” were calculated using oil and gas price parameters established by
current SEC guidelines and Financial Accounting Standard Board
guidance. Our “Sensitivity Case Proved Reserves” were calculated
using higher assumed values for crude oil and natural gas selected at our
discretion to better reflect our current expectations because the SEC pricing
parameters are significantly lower than current market prices and our average
realized price per barrel at December 31, 2009.
SEC Pricing Proved
Reserves
(1)
|
Crude
Oil
(barrels)
|
Natural
Gas
(cubic
feet)
|
Total
(barrels of
oil equivalent)
(2)
|
Pre-Tax
PV10% Value
(3)
|
|||||||||||||
|
PDP
Properties
(4)
|
1,647,031 | 513,112 | 1,732,550 | $ | 37,784,555 | |||||||||||
|
PDNP
Properties
(5)
|
600,687 | 214,125 | 636,375 | $ | 12,795,237 | |||||||||||
|
PUD
Properties
(6)
|
3,567,861 | 1,033,686 | 3,740,141 | $ | 37,232,700 | |||||||||||
|
Total
Proved Properties:
|
5,815,579 | 1,760,923 | 6,109,066 | $ | 87,812,492 | |||||||||||
Sensitivity Case Proved
Reserves
(1)
|
Crude
Oil
(barrels)
|
Natural
Gas
(cubic
feet)
|
Total
(barrels of
oil equivalent)
(2)
|
Pre-Tax
PV10% Value
(3)
|
|||||||||||||
|
PDP
Properties
(4)
|
1,730,728 | 529,657 | 1,819,004 | $ | 54,303,781 | |||||||||||
|
PDNP
Properties
(5)
|
630,542 | 224,383 | 667,939 | $ | 19,378,670 | |||||||||||
|
PUD
Properties
(6)
|
7,447,783 | 3,508,210 | 8,032,485 | $ | 93,901,002 | |||||||||||
|
Total
Proved Properties:
|
9,809,053 | 4,262,250 | 10,519,428 | $ | 167,583,453 | |||||||||||
______________
|
(1)
|
The
SEC Pricing Proved Reserves table above values oil and gas reserve
quantities and related discounted future net cash flows as of December 31,
2009 assuming a constant realized price of $53.00 per barrel of crude oil
and a constant realized price of $3.93 per 1,000 cubic feet (Mcf) of
natural gas.
The
Sensitivity Case Proved Reserves table above values oil and gas reserve
quantities and related discounted future net cash flows as of December 31,
2009 assuming a constant realized price of $71.82 per barrel of crude oil
and a constant realized price of $5.07 per 1,000 cubic feet (Mcf) of
natural gas, which prices are consistent with prior SEC pricing
methodology.
The
Sensitivity Case Proved Reserves table is intended to illustrate reserve
sensitivities to the commodity prices. These sensitivity prices were
selected because they are consistent with the prior SEC methodology
utilizing year-end pricing. The “Sensitivity Case Proved Reserves”
should not be confused with “SEC Pricing Proved Reserves” as outlined
above and does not comply with SEC pricing assumptions, but does comply
with all other definitions.
The
values presented in both tables above were calculated by Ryder
Scott.
|
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(2)
|
Barrels
of oil equivalent (“BOE”) are computed based on a conversion ratio of one
BOE for each barrel of crude oil and one BOE for every 6,000 cubic feet
(i.e., 6 Mcf) of natural gas.
|
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(3)
|
Pre-tax
PV10% may be considered a non-GAAP financial measure as defined by the SEC
and is derived from the standardized measure of discounted future net cash
flows, which is the most directly comparable standardized financial
measure. Pre-tax PV10% is computed on the same basis as the
standardized measure of discounted future net cash flows but without
deducting future income taxes. We believe Pre-tax PV10% is a
useful measure for investors for evaluating the relative monetary
significance of our oil and natural gas properties. We further
believe investors may utilize our Pre-tax PV10% as a basis for comparison
of the relative size and value of our reserves to other companies because
many factors that are unique to each individual company impact the amount
of future income taxes to be paid. Our management uses this
measure when assessing the potential return on investment related to our
oil and gas properties and acquisitions. However, Pre-tax PV10%
is not a substitute for the standardized measure of discounted future net
cash flows. Our Pre-tax PV10% and the standardized measure of
discounted future net cash flows do not purport to present the fair value
of our oil and natural gas reserves.
|
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(4)
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“PDP”
consists of our proved developed producing reserves.
|
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(5)
|
“PDNP”
consists of our proved developed nonproducing reserves, awaiting
completion.
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(6)
|
“PUD”
consists of our proved undeveloped reserves present valued net of
development cost.
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3
Our
December 31, 2009 reserve report includes an assessment of proven undeveloped
locations, which includes approximately 93% of our undeveloped acreage.
Our current North Dakota and Montana acreage position will allow us to drill
approximately 162 net wells based on 640-acre spacing units with production from
a single prospect. With 320-acre spacing units we have the ability to
drill a total of approximately 578 net wells, including 255 net wells targeting
the Bakken formation, 255 net wells targeting the Three Forks formation and 68
net wells targeting the Red River formation.
The
tables above assume prices and costs discounted using an annual discount rate of
10% without future escalation, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization, or federal income
taxes. The “Pre-tax PV10%” values of our proved reserves presented in
the foregoing tables may be considered a non-GAAP financial measure as defined
by the SEC.
The following table reconciles the
Pre-tax PV10% value of our SEC Pricing Proved Reserves to the standardized
measure of discounted future net cash flows.
|
SEC
Pricing Proved Reserves
Standardized Measure
Reconciliation
|
||||
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Pre-tax
Present Value of estimated future net revenues (Pre-tax
PV10%)
|
$ | 87,812,492 | ||
|
Future
income taxes, discounted at 10%
|
(20,005,931 | ) | ||
|
Standardized
measure of discounted future net cash flows
|
$ | 67,806,561 | ||
The following table reconciles the Pre-tax PV10% value of our Sensitivity
Case Proved Reserves to the standardized measure of discounted future net cash
flows.
|
Sensitivity
Case Proved Reserves
Standardized Measure
Reconciliation
|
||||
|
Pre-tax
Present Value of estimated future net revenues (Pre-tax
PV10%)
|
$ | 167,583,453 | ||
|
Future
income taxes, discounted at 10%
|
(50,995,503 | ) | ||
|
Standardized
measure of discounted future net cash flows
|
$ | 116,587,950 | ||
Uncertainties
are inherent in estimating quantities of proved reserves, including many risk
factors beyond our control. Reserve engineering is a subjective
process of estimating subsurface accumulations of oil and natural gas that
cannot be measured in an exact manner. As a result, estimates of
proved reserves may vary depending upon the engineer valuing the
reserves. Further, our actual realized price for our crude oil and
natural gas is not likely to average the pricing parameters used to calculate
our proved reserves. As such, the oil and natural gas quantities and
the value of those commodities ultimately recovered from our properties will
vary from reserve estimates.
Additional
discussion of our proved reserves is set forth under the heading “Supplemental
Oil and Gas Information” to our financial statements included later in this
report.
Recent
Developments
During
2009, we continued to focus our operations on acquiring leaseholds and drilling
exploratory and developmental wells in the Rocky Mountain Region of the United
States, specifically the Williston Basin. We acquired an aggregate of
20,316 additional net mineral acres during 2009, primarily in Mountrail and Dunn
Counties of North Dakota but also in Burke, Divide, McKenzie, Williams and other
counties of North Dakota. As of December 31, 2009, we had
participated in the completion of 179 gross wells with a 100% success rate in
the Bakken and Three Forks formations. As of December 31, 2009, our
principal assets included approximately 104,000 net acres located in the
Williston Basin region of the northern United States and approximately 10,000
net acres located in Yates County, New York, as more fully described under the
heading “Properties – Leasehold Properties” in Item 2 of this
report.
During 2009, we continued to acquire interests in oil, gas and
mineral leases with the intention of increasing our acreage positions in desired
prospects. A complete discussion of our significant acquisitions during
the past fiscal year is included under the heading "Properties – Recent
Acreage Acquisitions" in Item 2 of this report.
Production
Methods
We primarily engage in oil and gas
exploration and production by participating on a “heads-up” basis alongside
third-party interests in wells drilled and completed in spacing units that
include our acreage. We typically depend on drilling partners to
propose, permit and initiate the drilling of wells. Prior to
commencing drilling, our partners are required to provide all owners of oil, gas
and mineral interests within the designated spacing unit the opportunity to
participate in the drilling costs and revenues of the well to the extent of
their pro-rata share of such interest within the spacing unit. In
2009, we participated in the drilling of all new wells that included any of our
acreage. We will assess each drilling opportunity on a case-by-case
basis going forward and participate in wells that we expect to meet our return
thresholds based upon our estimates of ultimate recoverable oil and gas,
expertise of the operator and completed well cost from each project, as well as
other factors. At the present time we expect to participate pursuant
to our working interest in substantially all, if not all, of the wells proposed
to us.
We do not manage our commodities
marketing activities internally, but our operating partners generally market and
sell oil and natural gas produced from wells in which we have an
interest. Our operating partners coordinate the transportation of our
oil production from our wells to appropriate pipelines pursuant to arrangements
that such partners negotiate and maintain with various parties purchasing the
production. We understand that our partners generally sell our
production to a variety of purchasers at prevailing market prices under
separately
4
negotiated short-term
contracts. The price at which production is sold generally is tied to
the spot market for crude oil. Williston Basin Light Sweet Crude from
the Bakken source rock is generally 41-42 API oil and is readily accepted into
the pipeline infrastructure. The weighted average differential
reported to us by our producers during the second half of 2009 was $8.57 per
barrel below New York Mercantile Exchange (NYMEX) pricing. This
differential represents the imbedded transportation costs in moving the oil from
wellhead to refinery.
Competition
The oil
and natural gas industry is intensely competitive, and we compete with numerous
other oil and gas exploration and production companies. Some of these
companies have substantially greater resources than we have. Not only
do they explore for and produce oil and natural gas, but also many carry on
midstream and refining operations and market petroleum and other products on a
regional, national or worldwide basis. The operations of other
companies may be able to pay more for exploratory prospects and productive oil
and natural gas properties. They may also have more resources to
define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit.
Our
larger or integrated competitors may have the resources to be better able to
absorb the burden of existing, and any changes to federal, state, and local laws
and regulations more easily than we can, which would adversely affect our
competitive position. Our ability to discover reserves and acquire
additional properties in the future will be dependent upon our ability and
resources to evaluate and select suitable properties and to consummate
transactions in this highly competitive environment. In addition, we
may be at a disadvantage in producing oil and natural gas properties and bidding
for exploratory prospects, because we have fewer financial and human resources
than other companies in our industry. Should a larger and better
financed company decide to directly compete with us, and be successful in its
efforts, our business could be adversely affected.
Marketing
and Customers
The
market for oil and natural gas that we will produce depends on factors beyond
our control, including the extent of domestic production and imports of oil and
natural gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and natural gas, the marketing of
competitive fuels and the effects of state and federal
regulation. The oil and gas industry also competes with other
industries in supplying the energy and fuel requirements of industrial,
commercial and individual consumers.
Our oil
production is expected to be sold at prices tied to the spot oil
markets. Our natural gas production is expected to be sold under
short-term contracts and priced based on first of the month index prices or on
daily spot market prices. We rely on our operating partners to market
and sell our production. Our operating partners involve a variety of
exploration and production companies, from large publicly-traded companies to
small, privately-owned companies. We do not believe the loss of any
single operator would have a material adverse effect on our company as a
whole.
We do not own any physical real estate,
but, instead, our acreage is comprised of leasehold interests subject to the
terms and provisions of lease agreements that provide our company the right to
drill and maintain wells in specific geographic areas. All lease
arrangements that comprise our acreage positions are established using
industry-standard terms that have been established and used in the oil and gas
industry for many years. Some of our leases may be acquired from
other parties that obtained the original leasehold interest prior to our
acquisition of the leasehold interest.
In
general, our lease agreements stipulate five year terms. Bonuses and
royalty rates are negotiated on a case-by-case basis consistent with industry
standard pricing. Once a well is drilled and production established,
the well is considered “held by production,” meaning the lease continues as long
as oil is being produced. Other locations within the drilling unit
created for a well may also be drilled at any time with no time limit as long as
the lease is held by production. Given the current pace of drilling
in the Bakken play at this time, we do not believe lease expiration issues will
materially affect our North Dakota position.
5
Governmental
Regulation and Environmental Matters
Our operations are subject to various
rules, regulations and limitations impacting the oil and natural gas exploration
and production industry as whole.
Our oil
and natural gas exploration, production and related operations, when developed,
are subject to extensive rules and regulations promulgated by federal, state,
tribal and local authorities and agencies. For example, North Dakota
and Montana require permits for drilling operations, drilling bonds and reports
concerning operations and impose other requirements relating to the exploration
and production of oil and natural gas. Such states may also have
statutes or regulations addressing conservation matters, including provisions
for the unitization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from wells, and the regulation of
spacing, plugging and abandonment of such wells. Failure to comply
with any such rules and regulations can result in substantial
penalties. The regulatory burden on the oil and gas industry will
most likely increase our cost of doing business and may affect our
profitability. Although we believe we are currently in substantial
compliance with all applicable laws and regulations, because such rules and
regulations are frequently amended or reinterpreted, we are unable to predict
the future cost or impact of complying with such laws. Significant
expenditures may be required to comply with governmental laws and regulations
and may have a material adverse effect on our financial condition and results of
operations.
Environmental
Matters
Our
operations and properties are subject to extensive and changing federal, state
and local laws and regulations relating to environmental protection, including
the generation, storage, handling, emission, transportation and discharge of
materials into the environment, and relating to safety and
health. The recent trend in environmental legislation and regulation
generally is toward stricter standards, and this trend will likely
continue. These laws and regulations may:
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require
the acquisition of a permit or other authorization before construction or
drilling commences and for certain other
activities;
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limit
or prohibit construction, drilling and other activities on certain lands
lying within wilderness and other protected areas;
and
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impose
substantial liabilities for pollution resulting from its
operations.
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The
permits required for our operations may be subject to revocation, modification
and renewal by issuing authorities. Governmental authorities have the
power to enforce their regulations, and violations are subject to fines or
injunctions, or both. In the opinion of management, we are in
substantial compliance with current applicable environmental laws and
regulations, and have no material commitments for capital expenditures to comply
with existing environmental requirements. Nevertheless, changes in
existing environmental laws and regulations or in interpretations thereof could
have a significant impact on our company, as well as the oil and natural gas
industry in general.
The
Comprehensive Environmental, Response, Compensation, and Liability Act
(“CERCLA”) and comparable state statutes impose strict, joint and several
liability on owners and operators of sites and on persons who disposed of or
arranged for the disposal of “hazardous substances” found at such
sites. It is not uncommon for the neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment. The
Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state
statutes govern the disposal of “solid waste” and “hazardous waste” and
authorize the imposition of substantial fines and penalties for
noncompliance. Although CERCLA currently excludes petroleum from its
definition of “hazardous substance,” state laws affecting our operations may
impose clean-up liability relating to petroleum and petroleum related
products. In addition, although RCRA classifies certain oil field
wastes as “non-hazardous,” such exploration and production wastes could be
reclassified as hazardous wastes thereby making such wastes subject to more
stringent handling and disposal requirements.
6
The
Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize
endangered or threatened animal, fish and plant species, nor destroy or modify
the critical habitat of such species. Under ESA, exploration and
production operations, as well as actions by federal agencies, may not
significantly impair or jeopardize the species or its habitat. ESA
provides for criminal penalties for willful violations of the
Act. Other statutes that provide protection to animal and plant
species and that may apply to our operations include, but are not necessarily
limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and
Management Act, the Migratory Bird Treaty Act and the National Historic
Preservation Act. Although we believe that our operations will be in
substantial compliance with such statutes, any change in these statutes or any
reclassification of a species as endangered could subject our company to
significant expenses to modify our operations or could force our company to
discontinue certain operations altogether.
Climate
Change
Significant
studies and research have been devoted to climate change and global warming, and
climate change has developed into a major political issue in the United States
and globally. Certain research suggests that greenhouse gas emissions
contribute to climate change and pose a threat to the
environment. Recent scientific research and political debate has
focused in part on carbon dioxide and methane incidental to oil and natural gas
exploration and production. Many states and the federal government
have enacted legislation directed at controlling greenhouse gas emissions, and
future legislation and regulation could impose additional restrictions or
requirements in connection with our drilling and production activities and favor
use of alternative energy sources, which could increase operating costs and
demand for oil products. As such, our business could be materially
adversely affected by domestic and international legislation targeted at
controlling climate change.
Employees
We
currently have eight full time employees. Our Chief Executive
Officer—Michael Reger—and our Chief Financial Officer—Ryan Gilbertson—are
responsible for all material policy-making decisions. They are
assisted in the implementation of our company’s business by our Vice President
of Operations and our General Counsel. All employees have entered
into written employment agreements. As drilling production activities
continue to increase, we may hire additional technical or administrative
personnel as appropriate. We do not expect a significant change in
the number of full time employees over the next 12 months, assuming our
currently-projected drilling plan. We are using and will continue to
use the services of independent consultants and contractors to perform various
professional services, particularly in the area of land services and reservoir
engineering. We believe that this use of third-party service
providers enhances our ability to contain general and administrative
expenses.
Office
Locations
Our
executive offices are located at 315 Manitoba Avenue, Suite 200, Wayzata,
Minnesota 55391. Our office space consists of 3,044 square feet
leased pursuant to a five-year office lease agreement that commenced in February
2008. We believe our current office space is sufficient to meet our
needs for the foreseeable future.
Financial
Information about Segments and Geographic Areas
We have
not segregated our operations into geographic areas given the fact that all of
our production activities occur within the Williston Basin.
Available
Information – Reports to Security Holders
Our
website address is
www.northernoil.com
. We
make available on this Website under “Investor Relations,” free of charge, our
annual reports on Form 10-K (formerly Form 10-KSB), quarterly reports on Form
10-Q (formerly Form 10-QSB), current reports on Form 8-K and amendments to those
reports as soon as reasonably practicable after we electronically file those
materials with, or furnish those materials to, the SEC. These filings
are also available to the public at the SEC’s Public Reference Room at 100 F
Street, NE, Room 1580, Washington, DC 20549. The public may obtain
information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. Electronic filings with the SEC are also available on
the SEC internet website at
www.sec.gov
.
We have
also posted to our website our Audit Committee Charter, Compensation Committee
Charter, Nominating Committee Charter and our Code of Business Conduct and
Ethics, in addition to all pertinent company contact information.
7
The
possibility of a global financial crisis may significantly impact our business
and financial condition for the foreseeable future.
The
credit crisis and related turmoil in the global financial system may adversely
impact our business and our financial condition, and we may face challenges if
conditions in the financial markets do not improve. Our ability to
access the capital markets may be restricted at a time when we would like, or
need, to raise financing, which could have a material negative impact on our
flexibility to react to changing economic and business
conditions. The economic situation could have a material negative
impact on operators upon whom we are dependent for drilling our wells, our
lenders or customers, causing them to fail to meet their obligations to
us. Additionally, market conditions could have a material negative
impact on our crude oil hedging arrangements if our counterparties are unable to
perform their obligations or seek bankruptcy protection. We believe
we have sufficient capital to fund our 2010 drilling
program. However, additional capital would be required in the event
that we accelerate our drilling program or that crude oil prices decline
substantially resulting in significantly lower revenues.
We
may be unable to obtain additional capital that we will require to implement our
business plan, which could restrict our ability to grow.
We expect
that our cash position, unused credit facility and revenues from oil and gas
sales will be sufficient to fund our 2010 drilling program. However,
those funds may not be sufficient to fund both our continuing operations and our
planned growth. We may require additional capital to continue to grow
our business via acquisitions beyond the initial phase of our current properties
and to further expand our exploration and development programs. We
may be unable to obtain additional capital if and when required.
Future
acquisitions and future exploration, development, production and marketing
activities, as well as our administrative requirements (such as salaries,
insurance expenses and general overhead expenses, as well as legal compliance
costs and accounting expenses) will require a substantial amount of additional
capital and cash flow.
We may
pursue sources of additional capital through various financing transactions or
arrangements, including joint venturing of projects, debt financing, equity
financing or other means. We may not be successful in identifying
suitable financing transactions in the time period required or at all, and we
may not obtain the capital we require by other means. If we do not
succeed in raising additional capital, our resources may not be sufficient to
fund our planned expansion of operations following 2010.
Any
additional capital raised through the sale of equity may dilute the ownership
percentage of our stockholders. Raising any such capital could also
result in a decrease in the fair market value of our equity securities because
our assets would be owned by a larger pool of outstanding equity. The
terms of securities we issue in future capital transactions may be more
favorable to our new investors, and may include preferences, superior voting
rights and the issuance of other derivative securities, and issuances of
incentive awards under equity employee incentive plans, which may have a further
dilutive effect.
Our
ability to obtain financing, if and when necessary, may be impaired by such
factors as the capital markets (both generally and in the oil and gas industry
in particular), our limited operating history, the location of our oil and
natural gas properties and prices of oil and natural gas on the commodities
markets (which will impact the amount of asset-based financing available to us)
and the departure of key employees. Further, if oil or natural gas
prices on the commodities markets decline, our revenues will likely decrease and
such decreased revenues may increase our requirements for capital. If
the amount of capital we are able to raise from financing activities, together
with our revenues from operations, is not sufficient to satisfy our capital
needs (even to the extent that we reduce our operations), we may be required to
cease our operations, divest our assets at unattractive prices or obtain
financing on unattractive terms.
8
We may
incur substantial costs in pursuing future capital financing, including
investment banking fees, legal fees, accounting fees, securities law compliance
fees, printing and distribution expenses and other costs. We may also
be required to recognize non-cash expenses in connection with certain securities
we may issue, which may adversely impact our
financial condition.
We
have a limited operating history, and may not be successful in developing
profitable business operations.
We have a
limited operating history. Our business operations must be considered
in light of the risks, expenses and difficulties frequently encountered in
establishing a business in the oil and natural gas industries. We
first generated revenues from operations in the fiscal year ended December 31,
2008, and have been primarily focused on exploratory drilling and fund raising
activities. There is nothing at this time on which to base an
assumption that our business operations will prove to be successful in the
long-term. Our future operating results will depend on many factors,
including:
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our
ability to raise adequate working capital;
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success
of our development and exploration;
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demand
for natural gas and oil;
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the
level of our competition;
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our
ability to attract and maintain key management and employees;
and
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our
ability to efficiently explore, develop and produce sufficient quantities
of marketable natural gas or oil in a highly competitive and speculative
environment while maintaining quality and controlling
costs.
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To
achieve profitable operations in the future, we must, alone or with others,
successfully manage the factors stated above, as well as continue to develop
ways to enhance our production efforts, when commenced. Despite our
best efforts, we may not be successful in our exploration or development
efforts, or obtain required regulatory approvals. There is a
possibility that some, or all, of our wells may never produce natural gas or
oil.
We
are highly dependent on Michael Reger, our Chief Executive Officer, Chairman and
Director, and Ryan Gilbertson, Chief Financial Officer and
Director. The loss of either of them, upon whose knowledge,
leadership and technical expertise we rely, would harm our ability to execute
our business plan.
Our
success depends heavily upon the continued contributions of Michael Reger and
Ryan Gilbertson, whose knowledge, leadership and technical expertise would be
difficult to replace, and on our ability to retain and attract experienced
engineers, geoscientists and other technical and professional
staff. If we were to lose their services, our ability to execute our
business plan would be harmed and we may be forced to cease operations until
such time as we could hire a suitable replacement for them. Mr. Reger
and Mr. Gilbertson have entered into employment agreements with our company,
however, they may terminate their employment with our company at any
time.
Our
lack of diversification will increase the risk of an investment in our company,
and our financial condition and results of operations may deteriorate if we fail
to diversify.
Our
business focus is on the oil and gas industry in a limited number of properties,
initially in Montana and North Dakota. Larger companies have the
ability to manage their risk by diversification. However, we will
lack diversification, in terms of both the nature and geographic scope of our
business. As a result, we will likely be impacted more acutely by
factors affecting our industry or the regions in which we operate than we would
if our business were more diversified, enhancing our risk profile. If
we do not diversify our operations, our financial condition and results of
operations could deteriorate.
9
Strategic
relationships upon which we may rely are subject to change, which may diminish
our ability to conduct our operations.
Our
ability to successfully acquire additional properties, to increase our reserves,
to participate in drilling opportunities and to identify and enter into
commercial arrangements with customers will depend on developing and maintaining
close working relationships with industry participants and our ability to select
and evaluate suitable properties and to consummate transactions in a highly
competitive environment. These realities are subject to change and
our inability to maintain close working relationships with industry participants
or continue to acquire suitable property may impair our ability to execute our
business plan.
To
continue to develop our business, we will endeavor to use the business
relationships of our management to enter into strategic relationships, which may
take the form of joint ventures with other private parties and contractual
arrangements with other oil and gas companies, including those that supply
equipment and other resources that we will use in our business. We
may not be able to establish these strategic relationships, or if established,
we may not be able to maintain them. In addition, the dynamics of our
relationships with strategic partners may require us to incur expenses or
undertake activities we would not otherwise be inclined to in order to fulfill
our obligations to these partners or maintain our relationships. If
our strategic relationships are not established or maintained, our business
prospects may be limited, which could diminish our ability to conduct our
operations.
As
a non-operator, our development of successful operations relies extensively on
third-parties who, if not successful, could have a material adverse affect on
our results of operation.
We have
only participated in wells operated by third-parties. Our current
ability to develop successful business operations depends on the success of our
consultants and drilling partners. As a result, we do not control the
timing or success of the development, exploitation, production and exploration
activities relating to our leasehold interests. If our consultants
and drilling partners are not successful in such activities relating to our
leasehold interests, or are unable or unwilling to perform, our financial
condition and results of operation would be materially adversely
affected.
Competition
in obtaining rights to explore and develop oil and gas reserves and to market
our production may impair our business.
The oil
and gas industry is highly competitive. Other oil and gas companies
may seek to acquire oil and gas leases and other properties and services we will
need to operate our business in the areas in which we expect to
operate. This competition is increasingly intense as prices of oil
and natural gas on the commodities markets have risen in recent
years. Additionally, other companies engaged in our line of business
may compete with us from time to time in obtaining capital from
investors. Competitors include larger companies which, in particular,
may have access to greater resources, may be more successful in the recruitment
and retention of qualified employees and may conduct their own refining and
petroleum marketing operations, which may give them a competitive
advantage. In addition, actual or potential competitors may be
strengthened through the acquisition of additional assets and
interests. If we are unable to compete effectively or respond
adequately to competitive pressures, our results of operation and financial
condition may be materially adversely affected.
We
may not be able to effectively manage our growth, which may harm our
profitability.
Our
strategy envisions the expansion of our business. If we fail to
effectively manage our growth, our financial results could be adversely
affected. Growth may place a strain on our management systems and
resources. We must continue to refine and expand our business
capabilities, our systems and processes and our access to financing
sources. As we grow, we must continue to hire, train, supervise and
manage new employees. We cannot assure that we will be able
to:
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meet
our capital needs;
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expand
our systems effectively or efficiently or in a timely
manner;
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allocate
our human resources optimally;
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identify
and hire qualified employees or retain valued employees;
or
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incorporate
effectively the components of any business that we may acquire in our
effort to achieve growth.
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If we are
unable to manage our growth, our operations and our financial results could be
adversely affected by inefficiency, which would diminish our
profitability.
Our
hedging activities could result in financial losses or could reduce our net
income, which may adversely affect your investment in our common
stock.
We
generally expect to enter into swap arrangements from time-to-time to hedge our
expected production depending on reserves and market
conditions. While intended to reduce the effects of volatile oil and
natural gas prices, such transactions may limit our potential gains and increase
our potential losses if oil and natural gas prices were to rise substantially
over the price established by the hedge. In addition, such
transactions may expose us to the risk of loss in certain circumstances,
including instances in which:
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our
production is less than expected;
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there
is a widening of price differentials between delivery points for our
production and the delivery point assumed in the hedge arrangement;
or
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the
counterparties to our hedging agreements fail to perform under the
contracts.
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Risks
Related To Our Industry
Crude
oil and natural gas prices are very volatile. A protracted period of
depressed oil and natural gas prices may adversely affect our business,
financial condition, results of operations or cash flows.
The oil
and gas markets are very volatile, and we cannot predict future oil and natural
gas prices. The price we receive for our oil and natural gas
production heavily influences our revenue, profitability, access to capital and
future rate of growth. The prices we receive for our production and
the levels of our production depend on numerous factors beyond our
control. These factors include, but are not limited to, the
following:
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changes
in global supply and demand for oil and gas;
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the
actions of the Organization of Petroleum Exporting
Countries;
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the
price and quantity of imports of foreign oil and gas;
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political
and economic conditions, including embargoes, in oil-producing countries
or affecting other oil-producing activity;
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the
level of global oil and gas exploration and production
activity;
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the
level of global oil and gas inventories;
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weather
conditions;
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technological
advances affecting energy consumption;
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domestic
and foreign governmental regulations;
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proximity and capacity of oil and gas pipelines and other transportation facilities; | |||
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| • | the price and availability of alternative fuels. | |||
Furthermore,
the recent worldwide financial and credit crisis has generally reduced the
availability of liquidity and credit to fund the continuation and expansion of
industrial business operations worldwide. The shortage of liquidity
and credit combined with recent substantial losses in worldwide equity markets
has lead to a worldwide economic recession. The slowdown in economic
activity caused by such recession has reduced worldwide demand for energy and
resulted in somewhat lower oil and natural gas prices.
Lower oil
and natural gas prices may not only decrease our revenues on a per unit basis
but also may reduce the amount of oil and natural gas that we can produce
economically and therefore potentially lower our reserve bookings. A
substantial or extended decline in oil or natural gas prices may result in
impairments of our proved oil and gas properties and may materially and
adversely affect our future business, financial condition, results of
operations, liquidity or ability to finance planned capital
expenditures. To the extent commodity prices received from production
are insufficient to fund planned capital expenditures, we will be required to
reduce spending or borrow to cover any such shortfall. Lower oil and
natural gas prices may also reduce the amount of our borrowing base under our
credit agreement, which is determined at the discretion of the lenders based on
the collateral value of our proved reserves that have been mortgaged to the
lenders, and is subject to regular redeterminations, as well as special
redeterminations described in the credit agreement.
Drilling
for and producing oil and natural gas are high risk activities with many
uncertainties.
Our
future success will depend on the success of our development, exploitation,
production and exploration activities. Our oil and natural gas
exploration and production activities are subject to numerous risks beyond our
control, including the risk that drilling will not result in commercially viable
oil or natural gas production. Our decisions to purchase, explore,
develop or otherwise exploit prospects or properties will depend in part on the
evaluation of data obtained through geophysical and geological analyses,
production data and engineering studies, the results of which are often
inconclusive or subject to varying interpretations. Our cost of
drilling, completing and operating wells is often uncertain before drilling
commences. Overruns in budgeted expenditures are common risks that
can make a particular project uneconomical. Further, many factors may
curtail, delay or cancel drilling, including the following:
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delays
imposed by or resulting from compliance with regulatory
requirements;
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pressure
or irregularities in geological formations;
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shortages
of or delays in obtaining qualified personnel or equipment, including
drilling rigs and CO2;
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equipment
failures or accidents; and
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adverse
weather conditions, such as freezing temperatures, hurricanes and
storms.
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The
presence of one or a combination of these factors at our properties could
adversely affect our business, financial condition or results of
operations.
Our
business of exploring for oil and gas is risky and may not be commercially
successful, and the advanced technologies we use cannot eliminate exploration
risk.
Our
future success will depend on the success of our exploratory drilling
program. Oil and gas exploration involves a high degree of
risk. These risks are more acute in the early stages of
exploration. Our ability to produce revenue and our resulting
financial performance are significantly affected by the prices we receive for
oil and natural gas produced from wells on our acreage. Especially in
recent years, the prices at which oil and natural gas trade in
12
the open
market have experienced significant volatility and will likely continue to
fluctuate in the foreseeable future due to a variety of influences including,
but not limited to, the following:
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domestic
and foreign demand for oil and natural gas by both refineries and end
users;
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the
introduction of alternative forms of fuel to replace or compete with oil
and natural gas;
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domestic
and foreign reserves and supply of oil and natural gas;
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competitive
measures implemented by our competitors and domestic and foreign
governmental bodies;
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political
climates in nations that traditionally produce and export significant
quantities of oil and natural gas (including military and other conflicts
in the Middle East and surrounding geographic region) and regulations and
tariffs imposed by exporting and importing nations;
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weather
conditions; and
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domestic
and foreign economic volatility and
stability.
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Our
expenditures on exploration may not result in new discoveries of oil or natural
gas in commercially viable quantities. Projecting the costs of
implementing an exploratory drilling program is difficult due to the inherent
uncertainties of drilling in unknown formations, the costs associated with
encountering various drilling conditions, such as over-pressured zones and tools
lost in the hole, and changes in drilling plans and locations as a result of
prior exploratory wells or additional seismic data and
interpretations thereof.
Even when
used and properly interpreted, three-dimensional (3-D) seismic data and
visualization techniques only assist geoscientists in identifying subsurface
structures and hydrocarbon indicators. Such data and techniques do
not allow the interpreter to know conclusively if hydrocarbons are present or
economically producible. In addition, the use of three-dimensional
(3-D) seismic data becomes less reliable when used at increasing
depths. We could incur losses as a result of expenditures on
unsuccessful wells. If exploration costs exceed our estimates, or if
our exploration efforts do not produce results which meet our expectations, our
exploration efforts may not be commercially successful, which could adversely
impact our ability to generate revenues from our operations.
We
may not be able to develop oil and gas reserves on an economically viable basis,
and our reserves and production may decline as a result.
If we
succeed in discovering oil and/or natural gas reserves, we cannot assure that
these reserves will be capable of production levels we project or in sufficient
quantities to be commercially viable. On a long-term basis, our
viability depends on our ability to find or acquire, develop and commercially
produce additional oil and natural gas reserves. Without the addition
of reserves through acquisition, exploration or development activities, our
reserves and production will decline over time as reserves are
produced. Our future reserves will depend not only on our ability to
develop then-existing properties, but also on our ability to identify and
acquire additional suitable producing properties or prospects, to find markets
for the oil and natural gas we develop and to effectively distribute our
production into our markets.
Future
oil and gas exploration may involve unprofitable efforts, not only from dry
wells, but from wells that are productive but do not produce sufficient net
revenues to return a profit after drilling, operating and other
costs. Completion of a well does not assure a profit on the
investment or recovery of drilling, completion and operating
costs. In addition, drilling hazards or environmental damage could
greatly increase the cost of operations, and various field operating conditions
may adversely affect the production from successful wells. These
conditions include delays in obtaining governmental approvals or consents,
shut-downs of connected wells resulting from extreme weather conditions,
problems in storage and distribution and adverse geological and mechanical
conditions. While we will endeavor to effectively manage these
conditions, we cannot be assured of doing so optimally, and we will not be able
to eliminate them completely in any case. Therefore, these conditions
could diminish our revenue and cash flow levels and result in the impairment of
our oil and natural gas interests.
13
Estimates
of oil and natural gas reserves that we make may be inaccurate and our actual
revenues may be lower than our financial projections.
We will
make estimates of oil and natural gas reserves, upon which we will base our
financial projections. We will make these reserve estimates using
various assumptions, including assumptions as to oil and natural gas prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds. Some of these assumptions are inherently subjective, and the
accuracy of our reserve estimates relies in part on the ability of our
management team, engineers and other advisors to make accurate
assumptions. Economic factors beyond our control, such as interest
rates, will also impact the value of our reserves.
Determining
the amount of oil and gas recoverable from various formations where we have
exploration and production activities involves great uncertainty. For
example, in 2006, the North Dakota Industrial Commission published an article
that identified three different estimates of generated oil recoverable from the
Bakken formation. An organic chemist estimated 50% of the reserves in
the Bakken formation to be technically recoverable, an oil company estimated a
recovery factor of 18%, and values presented in the North Dakota Industrial
Commission Oil and Gas Hearings ranged from 3 to 10%.
The
process of estimating oil and natural gas reserves is complex and will require
us to use significant decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data for each
property. As a result, our reserve estimates will be inherently
imprecise. Actual future production, oil and natural gas prices,
revenues, taxes, development expenditures, operating expenses and quantities of
recoverable oil and natural gas reserves may vary substantially from those we
estimate. If actual production results vary substantially from our
reserve estimates, this could materially reduce our revenues and result in the
impairment of our oil and natural gas interests.
Drilling
new wells could result in new liabilities, which could endanger our interests in
our properties and assets.
There are
risks associated with the drilling of oil and natural gas wells, including
encountering unexpected formations or pressures, premature declines of
reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among
others. The occurrence of any of these events could significantly
reduce our revenues or cause substantial losses, impairing our future operating
results. We may become subject to liability for pollution, blow-outs
or other hazards. We intend to obtain insurance with respect to these
hazards; however, such insurance has limitations on liability that may not be
sufficient to cover the full extent of such liabilities. The payment
of such liabilities could reduce the funds available to us or could, in an
extreme case, result in a total loss of our properties and
assets. Moreover, we may not be able to maintain adequate insurance
in the future at rates that are considered reasonable. Oil and
natural gas production operations are also subject to all the risks typically
associated with such operations, including premature decline of reservoirs and
the invasion of water into producing formations.
Decommissioning
costs are unknown and may be substantial. Unplanned costs could
divert resources from other projects.
We may
become responsible for costs associated with abandoning and reclaiming wells,
facilities and pipelines which we use for production of oil and natural gas
reserves. Abandonment and reclamation of these facilities and the
costs associated therewith is often referred to as
“decommissioning.” We accrue a liability for decommissioning costs
associated with our wells, but have not established any cash reserve account for
these potential costs in respect of any of our properties. If
decommissioning is required before economic depletion of our properties or if
our estimates of the costs of decommissioning exceed the value of the reserves
remaining at any particular time to cover such decommissioning costs, we may
have to draw on funds from other sources to satisfy such costs. The
use of other funds to satisfy such decommissioning costs could impair our
ability to focus capital investment in other areas of our business.
14
We
may have difficulty distributing our production, which could harm our financial
condition.
In order
to sell the oil and natural gas that we are able to produce, the operators of
our wells may have to make arrangements for storage and distribution to the
market. We will rely on local infrastructure and the availability of
transportation for storage and shipment of our products, but infrastructure
development and storage and transportation facilities may be insufficient for
our needs at commercially acceptable terms in the localities in which we
operate. This situation could be particularly problematic to the
extent that our operations are conducted in remote areas that are difficult to
access, such as areas that are distant from shipping and/or pipeline
facilities. These factors may affect our ability to explore and
develop properties and to store and transport our oil and natural gas production
and may increase our expenses.
Furthermore,
weather conditions or natural disasters, actions by companies doing business in
one or more of the areas in which we will operate, or labor disputes may impair
the distribution of oil and/or natural gas and in turn diminish our financial
condition or ability to maintain our operations.
Environmental
risks may adversely affect our business.
All
phases of the oil and gas business present environmental risks and hazards and
are subject to environmental regulation pursuant to a variety of federal, state
and municipal laws and regulations. Environmental legislation
provides for, among other things, restrictions and prohibitions on spills,
releases or emissions of various substances produced in association with oil and
gas operations. The legislation also requires that wells and facility
sites be operated, maintained, abandoned and reclaimed to the satisfaction of
applicable regulatory authorities. Compliance with such legislation
can require significant expenditures, and a breach may result in the imposition
of fines and penalties, some of which may be material. Environmental
legislation is evolving in a manner we expect may result in stricter standards
and enforcement, larger fines and liability and potentially increased capital
expenditures and operating costs. The discharge of oil, natural gas
or other pollutants into the air, soil or water may give rise to liabilities to
governments and third parties and may require us to incur costs to remedy such
discharge. The application of environmental laws to our business may
cause us to curtail our production or increase the costs of our production,
development or exploration activities.
Our
business will suffer if we cannot obtain or maintain necessary
licenses.
Our
operations will require licenses, permits and in some cases renewals of licenses
and permits from various governmental authorities. Our ability to
obtain, sustain or renew such licenses and permits on acceptable terms is
subject to change in regulations and policies and to the discretion of the
applicable governments, among other factors. Our inability to obtain,
or our loss of or denial of extension of, any of these licenses or permits could
hamper our ability to produce revenues from our operations.
Challenges
to our properties may impact our financial condition.
Title to
oil and gas interests is often not capable of conclusive determination without
incurring substantial expense. While we intend to make appropriate
inquiries into the title of properties and other development rights we acquire,
title defects may exist. In addition, we may be unable to obtain
adequate insurance for title defects, on a commercially reasonable basis or at
all. If title defects do exist, it is possible that we may lose all
or a portion of our right, title and interests in and to the properties to which
the title defects relate. If our property rights are reduced, our
ability to conduct our exploration, development and production activities may be
impaired. To mitigate title problems, common industry practice is to
obtain a Title Opinion from a qualified oil and gas attorney prior to the
drilling operations of a well.
We
will rely on technology to conduct our business, and our technology could become
ineffective or obsolete.
We rely
on technology, including geographic and seismic analysis techniques and economic
models, to develop our reserve estimates and to guide our exploration,
development and production activities. We will be required to
continually enhance and update our technology to maintain its efficacy and to
avoid obsolescence. The costs of doing so may be substantial and may
be higher than the costs that we anticipate for technology maintenance and
development. If we are unable to maintain the efficacy of our
technology, our ability to manage our business and to compete may be
impaired. Further, even if we are able to maintain technical
effectiveness, our technology may not be the most efficient means of reaching
our objectives, in which case we may incur higher operating costs than we would
were our technology more efficient.
15
Risks
Related to our Common Stock
The
market price of our common stock is, and is likely to continue to be, highly
volatile and subject to wide fluctuations.
The
market price of our common stock is likely to continue to be highly volatile and
could be subject to wide fluctuations in response to a number of factors, some
of which are beyond our control, including:
|
•
|
dilution
caused by our issuance of additional shares of common stock and other
forms of equity securities, which we expect to make in connection with
future capital financings to fund our operations and growth, to attract
and retain valuable personnel and in connection with future strategic
partnerships with other companies;
|
|
|
•
|
announcements
of new acquisitions, reserve discoveries or other business initiatives by
our competitors;
|
|
|
•
|
our
ability to take advantage of new acquisitions, reserve discoveries or
other business initiatives;
|
|
|
•
|
fluctuations
in revenue from our oil and gas business as new reserves come to
market;
|
|
|
•
|
changes
in the market for oil and natural gas commodities and/or in the capital
markets generally;
|
|
|
•
|
changes
in the demand for oil and natural gas, including changes resulting from
the introduction or expansion of alternative fuels;
|
|
|
•
|
quarterly
variations in our revenues and operating expenses;
|
|
|
•
|
changes
in the valuation of similarly situated companies, both in our industry and
in other industries;
|
|
|
•
|
changes
in analysts’ estimates affecting our company, our competitors and/or our
industry;
|
|
|
•
|
changes
in the accounting methods used in or otherwise affecting our
industry;
|
|
|
•
|
additions
and departures of key personnel;
|
|
|
•
|
announcements
of technological innovations or new products available to the oil and gas
industry;
|
|
|
•
|
announcements
by relevant governments pertaining to incentives for alternative energy
development programs;
|
|
|
•
|
fluctuations
in interest rates and the availability of capital in the capital markets;
and
|
|
|
•
|
significant
sales of our common stock, including sales by selling stockholders
following the registration of shares under a
prospectus.
|
Some of
these and other factors are largely beyond our control, and the impact of these
risks, singly or in the aggregate, may result in material adverse changes to the
market price of our common stock and/or our results of operations and financial
condition.
16
Our
operating results may fluctuate significantly, and these fluctuations may cause
the price of our common stock to decline.
Our
operating results will likely vary in the future primarily as the result of
fluctuations in our revenues and operating expenses, including the coming to
market of oil and natural gas reserves that we are able to discover
and
develop, expenses that we incur, the prices of oil and natural
gas in the commodities markets and other factors. If our results of
operations do not meet the expectations of current or potential investors, the
price of our common stock may decline.
Stockholders
will experience dilution upon the exercise of options and issuance of common
stock under our incentive plans.
As of
December 31, 2009, we had authorized the issuance of up to 2,000,000 shares of
common stock underlying options that may be granted, of which options for
1,660,000 shares of common stock had already been granted, and of those granted,
300,000 remain outstanding, pursuant to our 2006 Incentive Stock Option
Plan. On January 30, 2009, our Board of Directors also adopted the
2009 Equity Incentive Plan, pursuant to which we may issue up to 3,000,000
shares of our common stock either upon exercise of stock options granted under
such plan or through restricted stock awards under such plan. As of
December 31, 2009, we had issued 642,916 shares of common stock pursuant to our
2009 Equity Incentive Plan. No options have been issued under our
2009 Equity Incentive Plan. If the holders of outstanding options
exercise those options or our Compensation Committee determines to grant
additional restricted stock awards under our incentive plan, stockholders may
experience dilution in the net tangible book value of our common
stock. Further, the sale or availability for sale of the underlying
shares in the marketplace could depress our stock price.
We
do not expect to pay dividends in the foreseeable future.
We do not
intend to declare dividends for the foreseeable future, as we anticipate that we
will reinvest any future earnings in the development and growth of our
business. Therefore, investors will not receive any funds unless they
sell their common stock, and stockholders may be unable to sell their shares on
favorable terms or at all. Investors cannot be assured of a positive
return on investment or that they will not lose the entire amount of their
investment in our common stock.
None.
Leasehold
Properties
As of
December 31, 2009, our principal assets included approximately 104,000 net acres
located in the Williston Basin region of the northern United States and
approximately 10,000 net acres located in Yates County, New York, more fully
described as follows:
| ▪ |
Approximately
30,400 net acres located in Mountrail County, North Dakota, whithin and
surrounding to the north south and west of the Parshall Field currently
being developed by EOG Resources. Slawson Exploration Company, Inc.
(“Slawson”) and others to target the Bakken Shale;
|
| ▪ | Approximately 26,800 net acres located in Dunn County, North Dakota, in which we are targeting the Bakken Shale and Three Forks/Sanish formations; |
| ▪ | Approximately 10,000 net acres located in Burke and Divide Counties, North Dakota, targeting the Bakken Shale and Three Forks/Sanish formations near significant drilling activities by Continental Resources; |
| ▪ | Approximately 8,900 net acres located in McKenzie, Williams and Mercer Counties, North Dakota, in which we are targeting the Bakken Shale; |
| ▪ | Approximately 22,400 net acres located in Sheridan County, Montana, representing a stacked pay prospect over which we have significant proprietary 3-D seismic data; |
| ▪ | Approximately 5,500 net acres located in Roosevelt and Richland Counties, Montana, in which we are targeting the Bakken Shale; and |
| ▪ |
Approximately 10,000
net acres located in the "Finger Lakes" region of Yates County, New York,
in which we are targeting natural gas production from the Trenton/Black
River, Marcellus and Queenstown-Medina
formations.
|
17
We
believe the Bakken formation represents one of the most oil rich, rapidly
developing and exciting plays in the Continental United States. The
North Dakota Geological Survey currently estimates the reserves of the Bakken
formation to be approximately 300 billion barrels of oil in place. We
commenced drilling on the Bakken properties in late 2007 and increased drilling
activities quarter-over-quarter throughout 2008 and 2009.
Recent
Acreage Acquisitions
In 2009,
we acquired leasehold interests covering an aggregate of 20,316 net mineral
acres in our key prospect areas. The discussion that follows summarizes
these acquisitions.
On May
22, 2009, we entered into an agreement with Slawson pursuant to which we
acquired certain North Dakota Bakken assets from Windsor Bakken LLC as part of a
syndicate led by Slawson. In the transaction we acquired leases
covering 3,323 net mineral acres.
On
November 3, 2009, we acquired 24 high working interest sections comprising
approximately 11,274 net acres located in western McKenzie and Williams Counties
of North Dakota. We acquired a 50% participation interest in these
properties with Slawson and will participate in drilling on a heads-up
basis. These properties are proximal to several recent high-rate
producing wells. We expect to begin drilling these properties in
early 2011.
On
November 13, 2009, we entered into an agreement with Slawson pursuant to which
we acquired a 20% participation interest in Slawson’s Big Sky Project in
Richland County, Montana. The project area encompasses 11,586 net
acres of leases.
On
November 17, 2009, we entered into an Exploration and Development Agreement with
Area of Mutual Interest with Slawson pursuant to which we acquired a 30%
participation interest in Slawson’s Anvil Project in Williams County, North
Dakota and Roosevelt County, Montana. The project area encompasses
12,500 net acres of leases.
In
addition to acquiring acreage through large block acquisitions, we have
organically acquired approximately 5,289 net mineral acres in our key prospect
areas.
18
Developed
and Undeveloped Acreage
The
following table summarizes our estimated gross and net developed and undeveloped
acreage by county at December 31, 2009. Net acreage
represents our percentage ownership of gross acreage. The following
table does not include acreage in which our interest is limited to royalty and
overriding royalty interests.
|
Developed
Acreage
|
Undeveloped
Acreage
|
Total
Acreage
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
North
Dakota
|
44,076 | 7,433 | 396,685 | 68,084 | 440,761 | 75,516 | ||||||||||||||||||
|
Montana
|
1,046 | 479 | 32,514 | 27,459 | 33,560 | 27,938 | ||||||||||||||||||
|
New
York
|
0 | 0 | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
|
Total:
|
45,122 | 7,912 | 439,199 | 105,542 | 484,321 | 113,454 | ||||||||||||||||||
Production
History
The
following table presents information about our produced oil and gas volumes
during each fiscal quarter in 2009 and the year ended December 31,
2009. The table below does not provide any information for our fiscal
year ended December 31, 2007 because we did not commence drilling activities
until the fourth fiscal quarter of 2007 and did not receive payment or recognize
revenue from crude oil or natural gas sales in 2007. As of December
31, 2009, we were selling oil and natural gas from a total of 179 gross wells,
all of which are located within the Williston Basin. As of December
31, 2008, we were selling oil and natural gas from a total of 36 gross
wells. All data presented below is derived from accrued revenue and
production volumes for the relevant period indicated.
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
| Net Production: | ||||||||
|
Oil
(Bbl)
|
274,328 | 50,880 | ||||||
|
Natural
Gas (Mcf)
|
47,305 | 3,969 | ||||||
|
Barrel
of Oil Equivalent (Boe)
|
282,212 | 51,542 | ||||||
| Average Sales Prices: | ||||||||
|
Oil
(per Bbl)
|
$ | 60.45 | $ | 75.63 | ||||
|
Effect
of Oil Hedges on Average Price (per Bbl)
|
$ | (3.60 | ) | $ | 15.31 | |||
|
Oil
Net of Hedging (per Bbl)
|
$ | 56.85 | $ | 90.94 | ||||
|
Natural
Gas (per Mcf)
|
$ | 3.81 | $ | 8.19 | ||||
|
Effect
of Natural Gas Hedges on Average Price (per Mcf)
|
-- | -- | ||||||
| Natural Gas Net of Hedging (per Mcf) | $ | 3.81 | $ | 8.19 | ||||
| Average Production Costs: | ||||||||
|
Oil
(per Bbl)
|
$ | 2.67 | $ | 1.37 | ||||
|
Natural
Gas (per Mcf)
|
$ | 0.19 | $ | 0.32 | ||||
|
Barrel
of Oil Equivalent (BOE)
|
$ | 2.63 | $ | 1.38 | ||||
19
Depletion
of oil and natural gas properties
Our depletion expense is driven by many
factors including certain exploration costs involved in the development of
producing reserves, production levels and estimates of proved reserve quantities
and future developmental costs. The following table presents our
depletion expenses during 2008 and 2009.
|
Year
Ended December 31,
|
||||
|
2009
|
2008
(adjusted)
|
|||
|
Depletion
of oil and natural gas properties
|
$ 4,250,983
|
$
677,915 *
|
||
* See
Note 2 to the financial statements accompanying this report.
Productive
Oil Wells
The
following table summarizes gross and net productive oil wells by state at
December 31, 2009, 2008 and 2007. A net well represents our
percentage ownership of a gross well. No wells have been permitted or
drilled on any of our Yates County, New York acreage. The following
table does not include wells in which our interest is limited to royalty and
overriding royalty interests. The following table also does not
include wells which were awaiting completion, in the process of completion or
awaiting flowback subsequent to fracture stimulation.
|
Year
Ended December 31,
|
||||||||||||||||||||||||
|
2009
|
2008
|
2007
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
North
Dakota
|
170 | 8.17 | 34 | 1.54 | 1 | 0.06 | ||||||||||||||||||
|
Montana
|
9 | 1.02 | 2 | 0.50 | 1 | 0.10 | ||||||||||||||||||
|
Total
|
179 | 9.19 | 36 | 2.04 | 2 | 0.16 | ||||||||||||||||||
Dry
Holes
As of
December 31, 2009, we have participated in the completion of 179 gross wells
with a 100% success rate in the Bakken and Three Forks formations. In
the second quarter of 2007, we participated in the Teigen Trust #9-13 with a
6.25% working interest, a well identified, proposed and drilled by Kodiak Oil
and Gas, Inc. The well was intended to target the Red River
formation, but produced a dry hole. This is the only dry hole in our
company’s history.
Research
and Development
We do not
anticipate performing any significant product research and development under our
plan of operation.
Reserves
We
completed our most recent reservoir engineering calculation as of December 31,
2009. Tables summarizing the results of our most recent reserve
report are included under the heading “Business – Reserves” in Item 1 of this
report. A complete discussion of our proved reserves is set forth in
“Supplemental Oil and Gas Information” to our financial statements included
later in this report.
Delivery
Commitments
We do not currently have any delivery
commitments for product obtained from our wells.
20
As of
March 8, 2010, our company was a party to one litigation claim arising in the
ordinary course of business and seeking the quieting of title for a leasehold
interest acquired from a third party. To the knowledge of management,
no federal, state or local governmental agency is presently contemplating any
proceeding against our company. No director, executive officer or
affiliate of our company or owner of record or beneficially of more than five
percent of our company’s common stock is a party adverse to our company or has a
material interest adverse to our company in any
proceeding.
On or
about December 19, 2008, we instituted a FINRA dispute resolution matter against
UBS Financial Services, Inc. (“UBS”) relating to certain unauthorized trades
conducted by UBS in connection with our commodities hedging account at that
institution. The matter related to UBS’s improper attribution of an
unauthorized long trade to our hedging account. Ultimately UBS
liquidated the contracts at a loss without any instruction from our
company. The matter was presented to a FINRA arbitration board in
September 2009. On November 12, 2009, FINRA issued an Award in favor
of our company directing UBS to pay us compensatory damages in the amount of
$875,352, the entire loss in dispute, plus interest at the statutory rate of 10%
per annum from and including October 13, 2008, through and including October 1,
2009, for a total award of $960,018.
Our
management believes that all litigation matters in which we are involved are not
likely to have a material adverse effect on our financial position, cash flows
or results of operations.
Market
Information
Our
common stock was listed on the OTC Bulletin Board of the National Association of
Securities Dealers (“NASD”) on January 19, 2006, under the symbol “KNTX”, but
there was no active trading prior to approximately December
2006. There was no established public trading market for our common
stock prior to April 13, 2007. Effective April 13, 2007, after the
Merger and our name change, our trading symbol was changed to
“NOGS.OB.” Our common stock commenced trading on the AMEX on March
26, 2008 under the symbol “NOG.”
The high and low sales
prices for shares of common stock of our company for each quarter during 2008
and 2009 are set forth below.
|
Sales
Price
|
||||||||
|
2009
|
High
|
Low
|
||||||
|
First
Quarter
|
$ | 4.24 | $ | 2.01 | ||||
|
Second
Quarter
|
8.89 | 3.40 | ||||||
|
Third
Quarter
|
8.44 | 4.74 | ||||||
|
Fourth
Quarter
|
12.66 | 7.65 | ||||||
|
Sales
Price
|
||||||||
|
2008
|
High
|
Low
|
||||||
|
First
Quarter
|
$ | 7.30 | $ | 5.65 | ||||
|
Second
Quarter
|
16.40 | 6.95 | ||||||
|
Third
Quarter
|
14.00 | 5.14 | ||||||
|
Fourth
Quarter
|
8.13 | 2.05 | ||||||
The
closing price for our common stock on the NYSE Amex Equities Market on March 1,
2010 was $12.60 per share.
21
Comparison
Chart
The
following information in this Item 5 of this Annual Report on Form 10-K is
not deemed to be “soliciting material” or to be “filed” with the SEC or subject
to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to
the liabilities of Section 18 of the Securities Exchange Act of 1934, and
will not be
deemed to
be incorporated by reference into any filing under the Securities Act of 1933 or
the Securities Exchange Act of 1934, except to the extent we specifically
incorporate it by reference into such a filing.
The
following graph compares the 32-month cumulative total shareholder returns since
completion of our reverse merger on April 13, 2007 of Northern Oil and Gas,
Inc., and the cumulative total returns of Standard & Poor’s Composite
500 Index and the Amex Oil Index for the same period. This graph
assumes $100 was invested in the stock or the Index on April 13, 2007 and also
assumes the reinvestment of dividends. We have not included any graph
for any period prior to April 13, 2007, because there was no active trading in
our common stock prior to April 13, 2007 and, as such, data is not available for
any period prior to such date.
The
following table sets forth the total returns utilized to generate the foregoing
graph.
|
4/13/2007
|
12/31/2007
|
12/31/2008
|
12/31/2009
|
|||||||||||||
|
Northern
Oil and Gas, Inc.
|
$ | 100.00 | $ | 173.75 | $ | 65.00 | $ | 296.00 | ||||||||
|
Standard
& Poor’s Composite 500 Index
|
100.00 | 104.82 | 66.04 | 83.52 | ||||||||||||
|
Amex
Oil Index
|
100.00 | 125.65 | 92.74 | 99.77 | ||||||||||||
Holders
As of
March 1, 2010, we had 43,911,044 shares outstanding of our common stock, held by
approximately 405 shareholders of record. The number of record
holders does not necessarily bear any relationship to the number of beneficial
owners of our common stock.
22
Dividends
The
payment of dividends is subject to the discretion of our Board of Directors and
will depend, among other things, upon our earnings, our capital requirements,
our financial condition, and other relevant factors. We have not paid
or declared any dividends upon our common stock since our inception and, by
reason of our present financial status and our contemplated financial
requirements and do not anticipate paying any dividends upon our common stock in
the foreseeable future. We intend to reinvest any earnings in the
development and expansion of our business. Any cash dividends in the
future to common stockholders will be payable when, as and if declared
by
our Board
of Directors or our Compensation Committee, based upon either the Board’s or the
Committee’s assessment of:
|
▪
|
our
financial condition and
performance;
|
|
▪
|
earnings;
|
|
▪
|
need
for funds;
|
|
▪
|
capital
requirements;
|
|
▪
|
prior
claims of preferred stock to the extent issued and outstanding;
and
|
|
▪
|
other
factors, including income tax consequences, restrictions and any
applicable laws.
|
There can
be no assurance, therefore, that any dividends on the common stock will ever be
paid.
Recent
Sales of Unregistered Securities; Use of Proceeds from Registered
Securities
On
November 16, 2009, we issued 12,533 shares of unregistered common stock to
Missouri River Royalty Corporation as partial consideration for our acquisition
of leases covering approximately 46 net mineral acres in North Dakota and
related pre-paid drilling expenses. These shares were issued pursuant
to an agreement originally entered into on October 1, 2008. On
December 18, 2009, we issued 66,472 shares of unregistered common stock to
certain parties controlling mineral rights as partial consideration for our
acquisition of leases covering approximately 1,084 net mineral acres in North
Dakota.
The
foregoing transactions were approved by our board of directors. None
of the foregoing shares of our common stock were issued for cash consideration
and, as such, we did not receive any proceed from the issuance of the foregoing
securities. All of the foregoing shares were issued pursuant to the
exemption from registration provided in Section 4(2) of the Act. In
each instance, the recipients of the shares were afforded an opportunity for
effective access to files and records of our company that contained the relevant
information needed to make its investment decision, including our company’s
financial statements and reports filed pursuant to the Exchange
Act. We reasonably believe that each recipient, immediately prior to
issuing the shares, had such knowledge and experience in financial and business
matters that it was capable of evaluating the merits and risks of its
investment. Each recipient had the opportunity to speak with our
officers and directors on several occasions prior to their investment
decision.
The
financial statement information set forth below is derived from our balance
sheets as of December 31, 2009, 2008, and 2007, and the related statements of
operations, stockholders’ equity, and cash flows for the years ended December
31, 2009, 2008, and 2007 and for the period from inception [October 5, 2006]
through December 31, 2006 included elsewhere in this
report. Financial statement information for the year ended December
31, 2005 and the balance sheet information at December 31, 2006 and 2005
are derived from audited financial statements presented in our December 31, 2006
Form 10-KSB report and not included in this report, which financial statements
were the historical financial statements of Kentex Petroleum, Inc, our company
prior to the acquisition of Northern on March 20, 2007.
23
|
Year
Ended December 31, 2009
|
Year
Ended December 31, 2008,
Adjusted
|
Year
Ended December 31, 2007
|
From
Inception on October 5, 2006 through December 31, 2006
|
Year
Ended December 31, 2005
|
||||||||||||||||
|
Statements
of Income Information:
|
||||||||||||||||||||
|
Revenues
|
|
|
||||||||||||||||||
|
Oil
and Gas Sales
|
$ | 15,171,824 | $ | 3,542,994 | -- | -- | -- | |||||||||||||
|
Gain
(Loss) on Settled Derivatives
|
(624,541 | ) | 778,885 | -- | -- | -- | ||||||||||||||
|
Mark-to-Market
of Derivative Instruments
|
(363,414 | ) | ||||||||||||||||||
|
Other
Revenue
|
37,630 | -- | -- | -- | --- | |||||||||||||||
|
Total
Revenues
|
$ | 14,221,499 | $ | 4,321,879 | -- | -- | -- | |||||||||||||
|
Operating
Expenses
|
||||||||||||||||||||
|
Production
Expenses
|
$ | 754,976 | $ | 70,954 | -- | -- | -- | |||||||||||||
|
Production
Taxes
|
1,300,373 | 203,182 | -- | -- | -- | |||||||||||||||
|
General
and Administrative Expense
|
2,452,823 | 1,985,914 | $ | 1,754,826 | $ | 76,374 | $ | 12,267 | ||||||||||||
|
Share
Based Compensation
|
1,233,507 | 105,375 | 2,754,917 | -- | -- | |||||||||||||||
|
Depletion
Oil and Gas Properties
|
4,250,983 | 677,915 | -- | -- | -- | |||||||||||||||
|
Depreciation
and Amortization
|
91,794 | 67,060 | 3,446 | -- | -- | |||||||||||||||
|
Accretion
of Discount on Asset Retirement Obligations
|
8,082 | 1,030 | -- | -- | -- | |||||||||||||||
|
Total
Expenses
|
$ | 10,092,538 | $ | 3,111,430 | $ | 4,513,189 | $ | 76,374 | $ | 12,267 | ||||||||||
|
Income
(Loss) from Operations
|
$ | 4,128,961 | $ | 1,210,449 | $ | (4,513,189 | ) | $ | ( 76,374 | ) | $ | ( 12,267 | ) | |||||||
|
Other
Income
|
135,991 | 383,891 | 207,896 | 267 | 25,000- | |||||||||||||||
|
Income
(Loss) Before Income Taxes
|
$ | 4,264,952 | $ | 1,594,340 | $ | ( 4,305,293 | ) | $ | ( 76,107 | ) | $ | ( 12,733 | ) | |||||||
|
Income
Tax Provision (Benefit)
|
1,466,000 | (830,000 | ) | -- | -- | -- | ||||||||||||||
|
Net
Income (Loss)
|
$ | 2,798,952 | $ | 2,424,340 | $ | ( 4,305,293 | ) | $ | ( 76,107 | ) | $ | ( 12,733 | ) | |||||||
|
Net
Income (Loss) Per Common Share – Basic
|
0.08 | 0.08 | (0.18 | ) | (0.01 | ) | (0.01 | ) | ||||||||||||
|
Net
Income (Loss) Per Common Share – Diluted
|
0.08 | 0.07 | (0.18 | ) | (0.01 | ) | (0.01 | ) | ||||||||||||
|
Weighted
Average Shares Outstanding – Basic
|
36,705,267 | 31,920,747 | 23,667,119 | 18,000,000 | 2,357,998 | |||||||||||||||
|
Weighted
Average Shares Outstanding - Diluted
|
36,877,070 | 32,653,552 | 23,667,119 | 18,000,000 | 2,357,998 | |||||||||||||||
|
Balance
Sheet Information:
|
||||||||||||||||||||
|
Total
Assets
|
$ | 135,594,968 | $ | 54,520,399 | $ | 18,131,464 | $ | 1,105,935 | -- | |||||||||||
|
Total
Liabilities
|
$ | 12,035,518 | $ | 4,991,336 | $ | 224,247 | $ | 1,143,067 | $ | 30,811 | ||||||||||
|
Stockholder’s
Equity (Deficit)
|
$ | 123,559,450 | $ | 49,529,063 | $ | 17,907,217 | $ | ( 37,132 | ) | $ | ( 30,811 | ) | ||||||||
|
Statement
of Cashflow Information:
|
||||||||||||||||||||
|
Net
cash used provided by (used for) operating activities
|
$ | 9,812,910 | $ | 2,506,492 | $ | ( 491,509 | ) | $ | ( 38,532 | ) | -- | |||||||||
|
Net
cash used provided by (used for) investing activities
|
$ | (71,848,701 | ) | $ | (40,357,962 | ) | $ | ( 5,078,758 | ) | $ | ( 255,000 | ) | -- | |||||||
|
Net
cash used provided by (used for) financing activities
|
$ | 67,488,447 | $ | 28,519,526 | $ | 14,832,992 | $ | 1,143,467 | -- | |||||||||||
24
In the
third quarter of 2009, we changed our method of accounting for drilling costs
from the accrual of drilling costs at the time drilling commenced for a well to
recording the costs when amounts are invoiced by operators. Recording
drilling costs when the invoices are received from operators is deemed
preferable as it better represents our actual drilling costs. The
recording of drilling costs in this method also is consistent with other
companies in the oil and gas industry. The change decreased Depletion
Expense by $512,794, increased Income Tax Provision by $206,000, and increased
Net Income by $306,794 or $0.01 per share on a diluted basis for the
nine
months ended September 30, 2009. The effect of the change on the
three months ended September 30, 2009 was to decrease Depletion Expense by
$261,870, increase Income Tax Provision by $105,000 and to Increase Net Income
by $156,870 or $0.00 per share on a diluted basis.
The
following discussion should be read in conjunction with the “Selected Financial
Data” in Item 6 and the Financial Statements and Accompanying Notes appearing
elsewhere in this report.
A discussion of our past financial
results before March 20, 2007 is not pertinent to the business plan of our
company on a going forward basis, due to the change in our business which
occurred upon consummation of the merger on March 20, 2007.
Overview
and Outlook
We are an
oil and gas exploration and production company. Our properties are
located in Montana, North Dakota and New York. Our corporate strategy
is to build shareholder value through the development and acquisition of oil and
gas assets that exhibit economically producible hydrocarbons.
As of
March 1, 2010, we controlled the rights to mineral leases covering approximately
119,720 net acres of land. Our goal is to continue to explore for and
develop hydrocarbons within the mineral leases we control as well as continue to
expand our acreage position should opportunities present
themselves. In order to accomplish our objectives we will need to
achieve the following;
|
▪
|
Continue
to develop our substantial inventory of high quality core Bakken acreage
with results consistent with those
to-date;
|
|
▪
|
Retain
and attract talented personnel;
|
|
▪
|
Continue
to be a low-cost producer of hydrocarbons;
and
|
|
▪
|
Continue
to manage our financial obligations to access the appropriate capital
needed to develop our position of primarily undrilled
acreage.
|
25
The
following table sets forth selected operating data for the periods
indicated. Production volumes and average sales prices are derived
from accrued accounting data for the relevant period indicated.
|
Year
End December 31,
|
||||||||||||
|
2009
|
2008
Adjusted
|
2007
|
||||||||||
|
Net
Production:
|
||||||||||||
|
Oil
(Bbl)
|
274,328 | 50,880 | - | |||||||||
|
Natural
Gas (Mcf)
|
47,305 | 3,969 | - | |||||||||
|
Net
Sales:
|
||||||||||||
|
Oil
Sales
|
$ | 14,977,556 | $ | 3,510,596 | - | |||||||
|
Natural
Gas
|
194,268 | 32,397 | - | |||||||||
|
Gain
(Loss) on Settled Derivatives
|
(624,541 | ) | 778,885 | - | ||||||||
|
Mark-to-Market
on Derivative Instruments
|
(363,414 | ) | - | - | ||||||||
|
Other
Revenues
|
37,630 | - | - | |||||||||
|
Total
Revenues
|
$ | 14,221,499 | $ | 4,321,879 | - | |||||||
|
Average
Sales Prices:
|
||||||||||||
|
Oil
(per Bbl)
|
$ | 60.45 | $ | 75.63 | - | |||||||
|
Effect
of Oil Hedges on Average Price (per Bbl)
|
$ | (3.60 | ) | $ | 15.31 | - | ||||||
|
Oil
Net of Hedging (per Bbl)
|
$ | 56.85 | $ | 90.94 | - | |||||||
|
Natural
Gas (per Mcf)
|
$ | 3.81 | $ | 8.19 | - | |||||||
|
Effect
of Natural Gas Hedges on Average Price (per Mcf)
|
- | - | - | |||||||||
|
Natural
gas net of hedging (per Mcf)
|
$ | 3.81 | $ | 8.19 | - | |||||||
|
Operating
Expenses:
|
||||||||||||
|
Production
Expenses
|
$ | 754,976 | $ | 70,954 | - | |||||||
|
Production
Taxes
|
$ | 1,300,373 | $ | 203,182 | - | |||||||
|
General
and Administrative Expense (Including Share Based
Compensation)
|
$ | 3,686,330 | $ | 2,091,289 | $ | 4,509,743 | ||||||
|
Depletion
of Oil and Gas Properties*
|
$ | 4,250,983 | $ | 677,915 | - | |||||||
* See
Note 2 to the financial statements accompanying this report.
Results
of Operations for the periods ended December 31, 2008 and December 31,
2009.
During
2008 and 2009 we significantly increased our drilling activities, generated
income and achieved net earnings for both the 2008 and 2009 fiscal
years. To-date, we have developed approximately seven percent of our
total drillable acreage inventory (assuming one well per 640-acre spacing unit)
and we expect to continue to add substantial volumes of production on a
quarter-over-quarter basis going forward into the foreseeable
future.
As of
December 31, 2009, we had established production from 179 gross (9.19 net)
wells in which we hold working interests, 36 gross (2.04 net) wells of which had
established production as of December 31, 2008. Our production at
December 31, 2009 approximated 1,508 barrels of oil per day, compared to
approximately 460 barrels of oil per day as of December 31, 2008. Our
production increased to 1,986 barrels of oil per day as of March 1,
2010.
We
drilled with a 100% success rate in 2008 and 2009 with 176 Bakken or Three Forks
wells completed or completing. We also had three successful Red River
discoveries at December 31, 2009. As of March 1, 2010, we expect to
participate in the drilling of approximately 200 gross (15 net) wells in
2010.
Our
revenues, costs and net income increased in 2009 compared to 2008 as we
continued our development plans and significantly increased our
production. Revenues for the twelve-month period ended December 31,
2009 were $14,221,499, compared to $4,321,879 for the twelve-month period ended
December 31, 2008 primarily due to increases in production.
26
Adjusted
total cash and non-cash expenses (including production expenses, production
taxes, general and administrative expenses, director fees, depletion expenses,
depreciation and amortization expenses) for the twelve
month period
ended December 31, 2009 were $10,092,538 and for the twelve-month period ended
December 31, 2008 were $3,111,430. Of this amount in 2009,
approximately $1,233,507 consisted of non-cash expense related to the issuance
of restricted stock and an additional $4,250,983 consisted of non-cash depletion
expenses. Depletion expenses for the twelve-month period ended
December 31, 2008 were $677,915.
We had
net income of $2,798,952 (representing approximately $0.08 per basic share) for
the twelve-month period ended December 31, 2009 compared to adjusted net income
of $2,424,340 (representing approximately $0.08 per basic share) for the
twelve-month period ended December 31, 2008.
Results
of Operations for the periods ended December 31, 2007 and December 31,
2008.
Our first
successful well commenced drilling in the fourth quarter of 2007, and we did not
realize revenue from that well until the first quarter of
2008. During 2008 we significantly increased our drilling activities
compared to 2007, generated income and achieved net earnings in the third and
fourth quarters of 2008 and for the 2008 fiscal year as a whole. Our
production at December 31, 2008 approximated 460 barrels of oil per
day. This compares to approximately 100 barrels of oil per day as of
December 31, 2007.
Revenues
for the twelve-month period ended December 31, 2008 were $4,321,879, compared to
no revenues for the twelve-month period ended December 31, 2007. Our
expenses in fiscal years 2006 and 2007 consisted principally of general and
administrative costs. Our costs increased moderately as we proceeded
with our development plans in 2008. Total expenses for the
twelve-month period ended December 31, 2008 were $3,111,430 and for the
twelve-month period ended December 31, 2007 were $4,513,189. We had
net income of $2,424,340 (representing approximately $0.08 per basic share) for
the twelve-month period ended December 31, 2008, compared to a net loss of
$4,305,293 for the twelve-month period ended December 31, 2007.
Operation
Plan
We expect to
drill approximately 15 net wells in 2010 with drilling capital expenditures
approximating $67.5 million. The 2010 wells are expected to target both
the Bakken and Three Forks formations. Drilling capital expenditures are
expected to increase in 2010 compared to previously published guidance due to
the continued success of longer laterals and additional fractional stimulation
stages. We currently expect to drill wells during 2010 at an average
completed cost of $4.5 million per well. Based on evolving conditions in
the field, we expect to deploy approximately $10 million towards further
strategic acreage acquisitions during 2010. We expect to fund all 2010
commitments using cash-on-hand, cash flow and our currently undrawn credit
facility.
Our
future financial results will depend primarily on: (i) the ability to continue
to source and screen potential projects; (ii) the ability to discover commercial
quantities of oil and gas; (iii) the market price for oil and gas; and (iv) the
ability to fully implement our exploration and development program, which is
dependent on the availability of capital resources. There can be no
assurance that we will be successful in any of these respects, that the prices
of oil and gas prevailing at the time of production will be at a level allowing
for profitable production, or that we will be able to obtain additional funding
if necessary.
Liquidity
and Capital Resources
Liquidity
is a measure of a company’s ability to meet potential cash
requirements. We have historically met our capital requirements
through the issuance of common stock and by short term borrowings. In
the future, we anticipate we will be able to provide the necessary liquidity by
the revenues generated from the sales of our oil and gas reserves in our
existing properties, however, if we do not generate sufficient sales revenues we
will continue to finance our operations through equity and/or debt
financings.
The
following table summarizes total current assets, total current liabilities and
working capital at December 31, 2009.
|
Current
Assets $ 42,017,813
|
|
Current
Liabilities
$ 8,910,256
|
|
Working
Capital $ 33,107,557
|
27
CIT
Capital USA, Inc. Credit Facility
On February 27, 2009, we completed the
closing of a revolving credit facility with CIT that provides up to a maximum
principal amount of $25 million of working capital for exploration and
production operations (the
“Credit Facility”). The borrowing
base of funds available under the Credit Facility will be redetermined
semi-annually based upon the net present value, discounted at 10% per annum, of
the future net revenues expected to accrue from our interests in proved reserves
estimated to be produced from our oil and gas properties. $16 million
of financing is currently available under the Credit Facility. An
additional $9 million of financing could become available upon subsequent
borrowing base redeterminations based on the deployment of funds from the Credit
Facility. The Credit Facility terminates on February 27,
2012. As of December 31, 2009, we had no borrowings outstanding under
the Credit Facility.
We have
the option to designate the reference rate of interest for each specific
borrowing under the Credit Facility as amounts are
advanced. Borrowings based upon the London interbank offering rate
(LIBOR) will be outstanding for a period of one, three or six months (as
designated by us) and bear interest at a rate equal to 5.50% over the one-month,
three-month or six-month LIBOR rate to be no less than 2.50%. Any
borrowings not designated as being based upon LIBOR will have no specified term
and generally will bear interest at a rate equal to 4.50% over the greater of
(a) the current three-month LIBOR rate plus 1.0% or (b) the current prime rate
as published by JP Morgan Chase Bank, N.A. We have the option to
designate either pricing mechanism. Payments are due under the Credit
Facility in arrears, in the case of a loan based on LIBOR on the last day of the
specified loan period and in the case of all other loans on the last day of each
March, June, September and December. All outstanding principal is due
and payable upon termination of the Credit Facility.
The
applicable interest rate increases under the Credit Facility and the lenders may
accelerate payments under the Credit Facility, or call all obligations due under
certain circumstances, upon an event of default. The Credit Facility
references various events constituting a default on the Credit Facility,
including, but not limited to, failure to pay interest on any loan under the
Credit Facility, any material violation of any representation or warranty under
the Credit Agreement in connection with the Credit Facility, failure to observe
or perform certain covenants, conditions or agreements under the Credit
Facility, a change in control of our company, default under any other material
indebtedness we might have, bankruptcy and similar proceedings and failure to
pay disbursements from lines of credit issued under the Credit
Facility.
The
Credit Facility requires that we enter into a swap agreement with Macquarie Bank
Limited (“Macquarie”) to hedge production over the 36-month term of the Credit
Facility. We have strategically entered into constant priced swap
arrangements with Macquarie since inception of the Credit Facility to hedge our
expected production. A full discussion of our current swap
arrangements is set forth in “Quantitative and Qualitative Disclosures about
Market Risk – Commodity Price Risk” in Item 7A of this report.
All of
our obligations under the Credit Facility and the swap agreements with Macquarie
are secured by a first priority security interest in any and all of our assets
pursuant to the terms of a Guaranty and Collateral Agreement and perfected by a
mortgage, notice of pledge and security and similar documents.
28
Follow-On
Equity Offerings
On June 30, 2009, we completed a
follow-on equity offering pursuant to which we sold 2.25 million shares of
common stock to various institutional investors for $6.00 per share, resulting
in gross proceeds of $13.5 million. Net proceeds to our company
following deduction of agency fees and expenses were approximately $12.7 million
and were used to repay outstanding borrowings under our Credit Facility,
primarily including borrowings incurred in connection with our acquisition of
North Dakota Bakken assets from Windsor Bakken LLC. C.K. Cooper &
Company acted as lead placement agent for the offering.
On November 4, 2009, we completed an
additional follow-on equity offering pursuant to which we sold 6.5 million
shares of common stock to various institutional investors for $9.12 per share,
resulting in gross proceeds of $59.3 million. Net proceeds to our
company following deduction of agency fees and expenses were approximately $56.3
and were used to repay outstanding borrowings under our Credit Facility, pursue
acquisition opportunities and for other working capital
purposes. Canaccord Adams Inc. acted as lead placement agent for the
offering. FIG Partners, LLC acted as co-placement agent for the
offering.
Satisfaction
of Our Cash Obligations for the Next 12 Months
With the
addition of equity capital during 2009 and our Credit Facility, we believe we
have sufficient capital to meet our drilling commitments and expected general
and administrative expenses for the next twelve months at a
minimum. Nonetheless, any strategic acquisition of assets may require
us to access the capital markets at some point in 2010. We may also
choose to access the equity capital markets rather than our Credit Facility or
other debt instruments to fund accelerated or continued drilling at the
discretion of management and depending on prevailing market
conditions. We will evaluate any potential opportunities for
acquisitions as they arise. Given our non-leveraged asset base and
anticipated growing cash flows, we believe we are in a position to take
advantage of any appropriately priced sales that may occur. However,
there can be no assurance that any additional capital will be available to us on
favorable terms or at all.
Over the
next 24 months it is possible that our existing capital, the Credit Facility and
anticipated funds from operations may not be sufficient to sustain continued
acreage acquisition. Consequently, we may seek additional capital in
the future to fund growth and expansion through additional equity or debt
financing or credit facilities. No assurance can be made that such
financing would be available, and if available it may take either the form of
debt or equity. In either case, the financing could have a negative
impact on our financial condition and our stockholders.
Though we
achieved profitability in 2008 and remained profitable throughout 2009, our
prospects must be considered in light of the risks, expenses and difficulties
frequently encountered by companies in their early stage of operations,
particularly companies in the oil and gas exploration industry. Such
risks include, but are not limited to, an evolving and unpredictable business
model and the management of growth. To address these risks we must,
among other things, implement and successfully execute our business and
marketing strategy, continue to develop and upgrade technology and products,
respond to competitive developments, and attract, retain and motivate qualified
personnel. There can be no assurance that we will be successful in
addressing such risks, and the failure to do so can have a material adverse
effect on our business prospects, financial condition and results of
operations.
Effects
of Inflation and Pricing
The oil
and gas industry is very cyclical and the demand for goods and services of oil
field companies, suppliers and others associated with the industry put extreme
pressure on the economic stability and pricing structure within the
industry. Typically, as prices for oil and natural gas increase, so
do all associated costs. Conversely, in a period of declining prices,
associated cost declines are likely to lag and may not adjust downward in
proportion. Material changes in prices also impact our current
revenue stream, estimates of future reserves, borrowing base calculations of
bank loans, impairment assessments of oil and gas properties, and values of
properties in purchase and sale transactions. Material changes in
prices can impact the value of oil and gas companies and their ability to raise
capital, borrow money and retain personnel. While we do not currently
expect business costs to materially increase, higher prices for oil and natural
gas could result in increases in the costs of materials, services and
personnel.
29
Contractual Obligations and Commitments
As of
December 31, 2009, we did not have any material long-term debt obligations,
capital lease obligations, operating lease obligations or purchase obligations
requiring future payments other than our office lease that expires on January
31, 2013, and outstanding promissory notes issued to our executive
officers. The following table illustrates our contractual obligations
as of December 31, 2009.
|
Payment
due by Period
|
||||||||||||||||||||
|
Contractual
Obligations
|
Total
|
Less
than 1 year
|
1-3
years
|
3-5
years
|
More
than 5 years
|
|||||||||||||||
|
Office
Lease
(1)
|
$ | 462,474 | $ | 148,151 | $ | 314,323 | $ | -- | $ | -- | ||||||||||
|
Note
Payable to Michael L. Reger
(2)
|
$ | 250,000 | $ | -- | $ | 250,000 | $ | -- | $ | -- | ||||||||||
|
Note
Payable to Ryan R. Gilbertson
(2)
|
$ | 250,000 | $ | -- | $ | 250,000 | $ | -- | $ | -- | ||||||||||
|
Automobile
Leases
(3)
|
$ | 61,116 | $ | 41,372 | $ | 19,744 | $ | -- | $ | -- | ||||||||||
| $ | 1,023,590 | $ | 189,523 | $ | 834,067 | $ | -- | $ | -- | |||||||||||
_________________
|
(1)
|
Our
office lease commenced on February 1, 2008 and continues for a period of
five years.
|
|
(2)
|
In
February 2009, our Audit Committee and the Compensation Committee approved
the issuance of $250,000 principal amount non-negotiable, unsecured
subordinated promissory notes to both Michael Reger – our Chief Executive
Officer – and Ryan Gilbertson – our Chief Financial Officer – in lieu of
paying cash bonuses earned in 2008. The notes bear interest at
a rate of 12% per annum and are subordinate to any secured debt of our
company. Our Credit Facility now limits our ability to make
interest and principal payments on the notes. All unpaid
principal and interest on the notes are due and payable in full in a
single lump sum on March 8, 2013.
|
|
(3)
|
In
July 2007, we entered into automobile leases for vehicles utilized by two
of our employees, which expire in July, 2010. In September 2008
we entered into automobile leases for vehicles utilized by two additional
employees, which expire in September,
2011.
|
Product
Research and Development
We do not
anticipate performing any significant product research and development given our
current plan of operation.
Expected
Purchase or Sale of Any Significant Equipment
We do not
anticipate the purchase or sale of any plant or significant equipment as such
items are not required by us at this time or anticipated to be needed in the
next twelve months.
Critical
Accounting Policies
Note 2 to the Financial Statements and
Accompanying Notes appearing elsewhere in this report describe various
accounting policies critical to an understanding of our financial
condition.
30
Off-Balance
Sheet Arrangements
We
currently do not have any off-balance sheet arrangements that have or are
reasonably likely to have a current or future effect on our financial condition,
changes in financial condition, revenues or expenses, results of operations,
liquidity, capital expenditures or capital resources that is material to
investors.
Commodity
Price Risk
The price
we receive for our oil and natural gas production heavily influences our
revenue, profitability, access to capital and future rate of
growth. Crude oil and natural gas are commodities and, therefore,
their prices are subject to wide fluctuations in response to relatively minor
changes in supply and demand. Historically, the markets for oil and
gas have been volatile, and these markets will likely continue to be volatile in
the future. The prices we receive for our production depend on
numerous factors beyond our control. Our revenue during 2009
generally would have increased or decreased along with any increases or
decreases in crude oil or natural gas prices, but the exact impact on our income
is indeterminable given the variety of expenses associated with producing and
selling oil that also increase and decrease along with oil prices.
We have
previously entered into derivative contracts to achieve a more predictable cash
flow by reducing our exposure to oil and natural gas price
volatility. On November 1, 2009, due to the volatility of price
differentials in the Williston Basin, we de-designated all derivatives that were
previously classified as cash flow hedges and in addition, we have elected not
to designate any subsequent derivative contracts as accounting
hedges. As such, all derivative positions are carried at their fair
value on the balance sheet and are marked-to-market at the end of each
period. Any realized and unrealized gains or losses are recorded as
gain (loss) on derivatives net, as an increase or decrease in revenues on the
Statement of Operations rather than as a component of other comprehensive income
(loss) or other Income (expense). We had the following swap
arrangements outstanding as of December 31, 2009:
|
Dates
|
Volumes
(bbl/month)
|
Price
|
||||||
|
January 2010 – December 2010
|
3,000 | $ | 51.25 | |||||
|
January
2011 – December 2011
|
2,000 | $ | 51.25 | |||||
|
January
2012 – February 2012
|
1,500 | $ | 51.25 | |||||
|
Dates
|
Volumes
(bbl/month)
|
Price
|
||||||
|
January
2010 – December 2010
|
1,500 | $ | 66.15 | |||||
|
January
2011 – December 2011
|
1,500 | $ | 66.15 | |||||
|
Dates
|
Volumes
(bbl/month)
|
Price
|
||||||
|
January
2010 – December 2010
|
7,000 | $ | 82.60 | |||||
|
January
2011 – December 2011
|
4,000 | $ | 82.60 | |||||
|
Dates
|
Volumes
(bbl/month)
|
Price
|
||||||
|
January
2010 – December 2010
|
3,000 | $ | 84.25 | |||||
|
January
2011 – December 2011
|
1,500 | $ | 84.25 | |||||
Interest
Rate Risk
We did
not have outstanding any borrowings under our credit facilities or other
obligations that would subject us to significant interest rate risk at December
31, 2009. Our Credit Facility entered into with CIT on February 27,
2009, will, however, subject us to interest rate risk on borrowings under that
facility.
Our
Credit Facility with CIT allows us to fix the interest rate of borrowings under
our Credit Facility for all or a portion of the principal balance for a period
up to six months. To the extent the interest rate is fixed, interest
rate changes affect the instrument’s fair market value but do not impact results
of operations or cash flows. Conversely, for the portion of our
borrowings that has a floating interest rate, interest rate changes will not
affect the fair market value but will impact future results of operations and
cash flows.
31
Our
Financial Statements required by this item are included on the pages immediately
following the Index to Financial Statements appearing on page F-1.
None.
Evaluation
of Disclosure Controls and Procedures
We
maintain a system of disclosure controls and procedures that is designed to
ensure that information required to be disclosed in our Exchange Act reports is
recorded, processed, summarized and reported within the time periods specified
in the SEC’s rules and forms, and that such information is accumulated and
communicated to our management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate, to allow timely decisions regarding required
disclosures.
As of
December 31, 2009, our management, including our Chief Executive Officer and
Chief Financial Officer, had evaluated the effectiveness of the design and
operation of our disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) pursuant to Rule 13a-15(b) under the
Exchange Act. Based upon and as of the date of the evaluation, our
Chief Executive Officer and Chief Financial Officer concluded that information
required to be disclosed is recorded, processed, summarized and reported within
the specified periods and is accumulated and communicated to management,
including our Chief Executive Officer and Chief Financial Officer, to allow for
timely decisions regarding required disclosure of material information required
to be included in our periodic SEC reports. Based on the foregoing,
our management determined that our disclosure controls and procedures were
effective as of December 31, 2009.
Management’s
Annual Report on Internal Control over Financial Reporting
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Exchange Act
Rule 13a-15(f). The design of any system of controls is based in
part upon certain assumptions about the likelihood of future events, and there
can be no assurance that any design will succeed in achieving its stated goals
under all potential future conditions, regardless of how remote. All
internal
control systems, no matter how well designed, have inherent
limitations. Because of its inherent limitations, internal control
over financial reporting may not prevent or detect
misstatements. Projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation.
We
carried out an evaluation, under the supervision and with the participation of
our Chief Executive Officer and Chief Financial Officer, of the effectiveness of
our internal controls over financial reporting as of December 31,
2009. In making this assessment, our management used the criteria set
forth by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO) in “Internal Control-Integrated Framework.” Based on this
assessment, management believes that, as of December 31, 2009, our internal
control over financial reporting was effective based on those
criteria. There have been no changes in internal control over
financial reporting since December 31, 2009, that has materially affected or is
reasonably likely to materially affect our internal control over financial
reporting.
The
effectiveness of our internal control over financial reporting as of
December 31, 2009 has been audited by Mantyla McReynolds LLC, an
independent registered public accounting firm, as stated in their report which
is included herein on the following page.
32
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Stockholders
Northern
Oil and Gas, Inc.:
We have
audited Northern Oil and Gas, Inc.’s (the Company) internal control over
financial reporting as of December 31, 2009, based on criteria established in
Internal Control—Integrated
Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company’s management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting
included in the accompanying Management’s Annual Report on Internal Control Over
Financial Reporting (Item 9A). Our responsibility is to express an opinion on
the Company’s internal control over financial reporting based on our
audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit of internal control over financial reporting included
obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing and evaluating
the design and operating effectiveness of internal control based on the assessed
risk. Our audit also included performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2009, based on criteria
established in
Internal
Control—Integrated Framework
issued by COSO.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the balance sheets of Northern Oil and Gas,
Inc. as of December 31, 2009 and 2008, and the related statements of operations,
stockholders’ equity, and cash flows for each of the years in the three-year
period ended December 31, 2009, and our report dated March 8, 2010 expressed an
unqualified opinion on those financial statements.
Mantyla
McReynolds LLC
Salt Lake
City, Utah
March 8,
2010
33
None.
34
We are
incorporating by reference information in Items 10 through 14 below from the
definitive proxy statement for our 2010 Annual Meeting of Stockholders, which we
intend to file with the SEC not later than 120 days subsequent to December
31, 2009.
Executive
Officers of the Registrant
Pursuant
to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3)
to Form 10-K, the following information is included in Part I of this annual
report. The following are our executive officers as of March 1,
2010.
|
Name
|
Age
|
Positions
|
||
|
Michael
L. Reger
|
33
|
Chairman,
Chief Executive Officer and Secretary
|
||
|
Ryan
R. Gilbertson
|
33
|
Director
and Chief Financial Officer
|
Michael L. Reger
has served
as our Chief Executive Officer, Secretary and a Director since March
2007. Mr. Reger has been primarily involved in the acquisition of
oil, gas and mineral rights for his entire professional life and is a director
of Reger Oil based in Billings, Montana. Mr. Reger holds a Bachelor
of Arts in Finance and an MBA in Finance/Management from the University of St.
Thomas in St. Paul, Minnesota. The Reger family has a history of
acreage acquisition in the Williston Basin dating to 1952.
Ryan R. Gilbertson
has served
as our Chief Financial Officer and a Director since March 2007. Mr.
Gilbertson’s last position prior to co-founding Northern was at Piper Jaffray in
Minneapolis from March 2004 to August 2006. Prior to Piper Jaffray,
Ryan was a portfolio manager at Telluride Asset Management, a multi-strategy
hedge fund based in Wayzata, Minnesota. Ryan holds a BA from Gustavus
Adolphus College in International Business/Finance.
The remaining information required by
this Item is incorporated by reference to the definitive proxy statement for our
2010 Annual Meeting of Stockholders, which we intend to file with the SEC not
later than 120 days subsequent to December 31, 2009.
We have adopted a Code of Business
Conduct and Ethics that applies to our chief executive officer, chief financial
officer and persons performing similar functions. A copy is available
on our website at
www.northernoil.com
. We
intend to post on our website any amendments to, or waivers from, our Code of
Business Conduct and Ethics pursuant to the rules of the SEC and NYSE Amex
Equity Market.
The
information required by this Item is incorporated by reference to the definitive
proxy statement for our 2010 Annual Meeting of Stockholders, which we intend to
file with the SEC not later than 120 days subsequent to December 31,
2009.
35
Securities
Authorized for Issuance under Equity Compensation Plans
The
following table provides information with respect to our common shares issuable
under our equity compensation plans as of December 31, 2009:
|
Plan
Category
|
Number
of securities to be issued upon exercise of outstanding options, warrants
and rights
(a)
|
Weighted-average
exercise price of outstanding options, warrants and rights
(b)
|
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in column
(a))
(c)
|
|||||||||
|
Equity
compensation plans approved by security holders
|
||||||||||||
|
2006
Incentive Stock Option Plan
|
300,000 | $ | 5.18 | 340,000 | ||||||||
|
2009
Equity Incentive Plan
|
- | - | 2,357,084 | |||||||||
|
Equity
compensation plans not approved by security holders
|
||||||||||||
|
None
|
- | - | - | |||||||||
|
Total
|
300,000 | $ | 5.18 | 2,697,084 | ||||||||
The
remaining information required by this Item is incorporated by reference to the
definitive proxy statement for our 2010 Annual Meeting of Stockholders, which we
intend to file with the SEC not later than 120 days subsequent to December
31, 2009.
The
information required by this Item is incorporated by reference to the definitive
proxy statement for our 2010 Annual Meeting of Stockholders, which we intend to
file with the SEC not later than 120 days subsequent to December 31,
2009.
The
information required by this Item is incorporated by reference to the definitive
proxy statement for our 2010 Annual Meeting of Stockholders, which we intend to
file with the SEC not later than 120 days subsequent to December 31,
2009.
36
(a) Documents
filed as Part of this Report:
|
1.
|
Financial
Statements
|
See Index
to Financial Statements on page F-1.
|
2.
|
Financial
Statement Schedules
|
All
schedules are omitted because they are either not applicable or required
information is shown in the financial statements or notes thereto.
(b) Exhibits:
Unless
otherwise indicated, all documents incorporated by reference into this report
are filed with the SEC pursuant to the Securities Exchange Act of 1934, as
amended, under file number 000-33999.
|
Exhibit
No.
|
Description
|
Reference
|
|
3.1
|
Composite
Articles of Incorporation of Northern Oil and Gas, Inc.
|
Incorporated
by reference to Exhibit 3.1 to our company’s Annual Report on Form 10-K/A
(Amendment No. 3) filed with the SEC on June 24,
2009
|
|
3.2
|
Amended
and Restated Bylaws of Northern Oil and Gas, Inc.
|
Incorporated
by reference to Exhibit 99.2 to the Registrant’s Current Report on Form
8-K filed with the SEC on December 6, 2007 (File
No. 000-30955)
|
|
4.1
|
Specimen
Stock Certificate of Northern Oil and Gas, Inc.
|
Incorporated
by reference to Exhibit 2.2 to the Registration Statement on Form SB-2
filed with the SEC on June 11, 2007, as amended (File
No. 333-143648)
|
|
10.1
|
Form
of Warrant
|
Incorporated
by reference to Exhibit 10.2 to the current report on Form 8-K filed with
the SEC on September 14, 2007 (File
No. 000-30955)
|
|
10.2*
|
Amended
and Restated Employment Agreement by and between Northern Oil and Gas,
Inc. and Michael L. Reger, dated January 30, 2009
|
Incorporated
by reference to Exhibit 10.2 to the Registrant’s Current Report on Form
8-K filed with the SEC on February 2, 2009 (File
No. 000-30955)
|
|
10.3*
|
Amended
and Restated Employment Agreement by and between Northern Oil and Gas,
Inc. and Ryan R. Gilbertson, dated January 30, 2009
|
Incorporated
by reference to Exhibit 10.3 to the Registrant’s Current Report on Form
8-K filed with the SEC on February 2, 2009 (File
No. 000-30955)
|
|
10.4
|
Irrevocable
Proxy Provided by Joseph A. Geraci II, Kimerlie Geraci, Lantern Advisers,
LLC, Isles Capital, LLC and Mill City Ventures, LP, dated February 21,
2008
|
Incorporated
by reference to Exhibit 10.1 to the Registrant’s Current Report on Form
8-K filed with the SEC on March 19, 2008 (File
No. 000-30955)
|
|
10.5
|
Agreement
by and between Northern Oil and Gas, Inc. and Deephaven MCF Acquisition
LLC dated April 14, 2008
|
Incorporated
by reference to Exhibit 10.1 to the Registrant’s Current Report on Form
8-K filed with the SEC on April 16, 2008 (File
No. 000-30955)
|
|
10.6
|
Second
Amendment to Agreement by and between Northern Oil and Gas, Inc. and
Deephaven MCF Acquisition LLC dated April 14, 2008
|
Incorporated
by reference to Exhibit 10.1 to the Registrant’s Current Report on Form
8-K filed with the SEC on September 29, 2008 (File
No. 000-30955)
|
37
|
Exhibit
No.
|
Description
|
Reference
|
|
10.7
|
Registration
Rights Agreement By and Among Northern Oil and Gas, Inc. and Deephaven MCF
Acquisition LLC dated April 14, 2008
|
Incorporated
by reference to Exhibit 10.2 to the Registrant’s Current Report on Form
8-K filed with the SEC on April 16, 2008 (File
No. 000-30955)
|
|
10.8
|
Lease
Purchase Agreement By and Between Northern Oil and Gas, Inc. and Woodstone
Resources, L.L.C.
|
Incorporated
by reference to Exhibit 10.1 to the Registrant’s Current Report on Form
8-K filed with the SEC on June 17, 2008 (File
No. 000-30955)
|
|
10.9*
|
Northern
Oil and Gas, Inc. 2009 Equity Compensation Plan
|
Incorporated
by reference to Exhibit 10.1 to the Registrant’s Current Report on Form
8-K filed with the SEC on February 2, 2009 (File
No. 000-30955)
|
|
10.10
|
Credit
Agreement dated as of February 27, 2009 among Northern Oil and Gas, Inc.,
as Borrower, CIT Capital USA Inc., as Administrative Agent, and The
Lenders Party Hereto
|
Incorporated
by reference to Exhibit 10.1 to the Registrant’s Current Report on Form
8-K filed with the SEC on March 2, 2009 (File
No. 000-30955)
|
|
10.11
|
Form
of Note Under that Certain Credit Agreement dated as of February 27, 2009
among Northern Oil and Gas, Inc., as Borrower, CIT Capital USA Inc., as
Administrative Agent, and The Lenders Party Hereto
|
Incorporated
by reference to Exhibit 10.2 to the Registrant’s Current Report on Form
8-K filed with the SEC on March 2, 2009 (File
No. 000-30955)
|
|
10.12
|
Guaranty
and Collateral Agreement dated as of February 27, 2009 made by Northern
Oil and Gas, Inc. in favor of CIT Capital USA Inc., as Administrative
Agent
|
Incorporated
by reference to Exhibit 10.3 to the Registrant’s Current Report on Form
8-K filed with the SEC on March 2, 2009 (File
No. 000-30955)
|
|
10.13
|
Guaranty
and Collateral Agreement dated as of February 27, 2009 made by Northern
Oil and Gas, Inc. in favor of CIT Capital USA Inc., as Administrative
Agent
|
Incorporated
by reference to Exhibit 10.4 to the Registrant’s Current Report on Form
8-K filed with the SEC on March 2, 2009 (File
No. 000-30955)
|
|
10.14
|
Warrant
to Purchase Shares of Northern Oil and Gas, Inc. Common Stock Issued to
CIT Group/Equity Investments, Inc. on February 27, 2009
|
Incorporated
by reference to Exhibit 10.5 to the Registrant’s Current Report on Form
8-K filed with the SEC on March 2, 2009 (File
No. 000-30955)
|
|
10.15*
|
Northern
Oil and Gas, Inc. 2009 Equity Incentive Plan
|
Incorporated
by reference to Exhibit 10.1 to the Registrant’s Current Registration
Statement on Form S-8 filed with the SEC on July 16, 2009 (File
No. 333-160602)
|
|
10.16
|
Exploration
and Development Agreement dated effective as of April 1, 2009 by and
between Slawson Exploration Company, Inc. and Northern Oil and Gas,
Inc.
|
Incorporated
by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K
filed with the SEC on May 29, 2009
|
|
10.17
|
First
Amendment to Credit Agreement dated as of May 22, 2009 among Northern Oil
and Gas, Inc., CIT Capital USA Inc., and the Lenders party
thereto
|
Incorporated
by reference to Exhibit 10.1 to the Registrant’s Current Report on Form
8-K filed with the SEC on May 29, 2009
|
|
10.18*
|
Form
of Promissory Note issued to Michael L. Reger and Ryan R.
Gilbertson
|
Filed
herewith
|
|
10.19*
|
Form
of Restricted Stock Agreement issued under the Northern Oil and Gas, Inc.
2009 Equity Incentive Plan
|
Filed
herewith
|
38
|
Exhibit No.
|
Description | Reference |
|
18.1
|
Letter
from Mantyla McReynolds, LLC Regarding Change in Accounting
Principles
|
Incorporated
by reference to Exhibit 18.1 to the Registrant’s Current Report on Form
10-Q filed with the SEC on October 27, 2009
|
|
23.1
|
Consent
of Independent Registered Public Accounting Firm Mantyla McReynolds
LLC
|
Filed
herewith
|
|
23.2
|
Consent
of Ryder Scott Company, LP
|
Filed
herewith
|
|
31.1
|
Certification
of the Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a)
under the Securities Exchange Act of 1934, as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
|
Filed
herewith
|
|
31.2
|
Certification
of the Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)
under the Securities Exchange Act of 1934, as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
|
Filed
herewith
|
|
32.1
|
Certification
of the Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
|
Filed
herewith
|
|
99.1
|
Report
of Ryder Scott Company, LP.
|
Filed
herewith
|
|
|
* Management
contract or compensatory plan or arrangement required to be filed as an
exhibit to this report.
|
39
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
NORTHERN
OIL AND GAS, INC.
|
Date:
|
March
8, 2010
|
By:
|
/s/
Michael L. Reger
|
|
|
Michael
L. Reger
|
||||
|
Chief
Executive Officer
|
POWER
OF ATTORNEY
Each
person whose signature appears below constitutes and appoints, Michael L. Reger
and Ryan R. Gilbertson, or either of them, his true and lawful attorney-in-fact
and agent, acting alone, with full power of substitution and resubstitution, for
him and in his name, place and stead, in any and all capacities, to sign any and
all amendments (including post-effective amendments) to this Annual Report on
Form 10-K and to file the same, with all exhibits thereto, and other documents
in connection wherewith, with the Commission, granting unto said
attorney-in-fact and agent, each acting alone, full power and authority to do
and perform each and every act and thing requisite and necessary to be done in
and about the premises, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all said attorney-in-fact
and agent, acting alone, or his substitute or substitutes, may lawfully do or
cause to be done by virtue hereof.
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacity and on the dates indicated:
|
Signature
|
Title
|
Date
|
||
|
/s/
Michael L. Reger
|
Chief
Executive Officer, Director and Secretary
|
March
8, 2010
|
||
|
Michael
L. Reger
|
||||
|
/s/
Ryan R. Gilbertson
Ryan
R. Gilbertson
|
Chief
Financial Officer, Principal Financial Officer, Principal Accounting
Officer, Director
|
March
8, 2010
|
||
|
/s/
Loren J. O’Toole
|
Director
|
March
8, 2010
|
||
|
Loren
J. O’Toole
|
||||
|
/s/
Carter Stewart
|
Director
|
March
8, 2010
|
||
|
Carter
Stewart
|
||||
|
/s/
Jack King
|
Director
|
March
8, 2010
|
||
|
Jack
King
|
||||
|
/s/
Robert Grabb
|
Director
|
March
8, 2010
|
||
|
Robert
Grabb
|
||||
|
/s/
Lisa Bromiley Meier
|
Director
|
March
8, 2010
|
||
|
Lisa
Bromiley Meier
|
40
NORTHERN
OIL AND GAS, INC.
INDEX
TO FINANCIAL STATEMENTS
|
Page
|
|
|
Report
of Independent Registered Public Accounting Firm
|
F-2
|
|
Balance
Sheets as of December 31, 2009 and 2008
|
F-3
|
|
Statements
of Operations for the Years Ended December 31, 2009, December 31, 2008 and
December 31, 2007
|
F-4
|
|
Statements
of Stockholders’ Equity for the Years Ended December 31, 2009, December
31, 2008 and December 31, 2007
|
F-5
|
|
Statements
of Cash Flows for the Years Ended December 31, 2009, December 31, 2008 and
December 31, 2007
|
F-6
|
|
Notes
to the Financial Statements
|
F-7
|
F-1
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Stockholders
Northern
Oil and Gas, Inc.:
We have
audited the accompanying balance sheets of Northern Oil and Gas, Inc. (the
Company) as of December 31, 2009 and 2008, and the related statements of
operations, stockholders’ equity, and cash flows for each of the years in the
three-year period ended December 31, 2009. These financial statements are the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our
opinion, the financial statements referred to above present fairly, in all
material respects, the financial position of the Company as of December 31, 2009
and 2008, and the results of their operations and their cash flows for each of
the years in the three-year period ended December 31, 2009 in conformity with
accounting principles generally accepted in the United States of
America.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company’s internal control over financial
reporting as of December 31, 2009, based on criteria established in
Internal Control—Integrated
Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated March 8, 2010 expressed an
unqualified opinion on the effectiveness of the Company’s internal control over
financial reporting.
As
discussed in Note 2 to the financial statements, the Company has elected to
change its method of accounting for accrued drilling costs in 2009.
Mantyla
McReynolds LLC
Salt Lake
City, Utah
March 8,
2010
F-2
|
BALANCE
SHEETS
|
||||||||||||||
|
DECEMBER
31, 2009 AND 2008
|
||||||||||||||
|
ASSETS
|
||||||||||||||
| Year Ended December 31, | ||||||||||||||
| 2009 | 2008 | |||||||||||||
| Adjusted* | ||||||||||||||
| CURRENT ASSETS | ||||||||||||||
| Cash and Cash Equivalents | $ 6,233,372 | $ 780,716 | ||||||||||||
| Trade Receivables |
7,025,011
|
2,028,941
|
||||||||||||
| Other Receivables | - | 874,453 | ||||||||||||
| Prepaid Drilling Costs |
1,454,034
|
4,549
|
||||||||||||
| Prepaid Expenses |
143,606
|
71,554
|
||||||||||||
| Other Current Assets |
201,314
|
- | ||||||||||||
| Short - Term Investments |
24,903,476
|
- | ||||||||||||
|
Deferred Tax
Asset
|
2,057,000
|
1,390,000
|
||||||||||||
| Total Current Assets | 42,017,813 | 5,150,213 | ||||||||||||
|
PROPERTY
AND EQUIPMENT
|
||||||||||||||
|
Oil
and Natural Gas Properties, Full Cost Method
(including unevaluated cost of
|
||||||||||||||
|
$53,862,529
at 12/31/09 and $35,990,267 at 12/31/2008)
|
96,801,626
|
47,260,838
|
||||||||||||
|
Other
Property and Equipment
|
439,656
|
408,400
|
||||||||||||
|
Total
Property and Equipment
|
97,241,282
|
47,669,238
|
||||||||||||
|
Less
- Accumulated Depreciation and Depletion
|
5,091,198
|
748,421
|
||||||||||||
|
Total
Property and Equipment, Net
|
92,150,084
|
46,920,817
|
||||||||||||
|
LONG
- TERM INVESTMENTS
|
-
|
2,416,369
|
||||||||||||
|
DEBT
ISSUANCE COSTS
|
1,427,071
|
-
|
||||||||||||
|
DEFERRED
TAX ASSET
|
-
|
33,000
|
||||||||||||
|
Total
Assets
|
$ 135,594,968
|
$
54,520,399
|
||||||||||||
|
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||||||||||
|
CURRENT
LIABILITIES
|
||||||||||||||
|
Accounts
Payable
|
$ 6,419,534
|
$ 1,934,810
|
||||||||||||
|
Line
of Credit
|
834,492
|
1,650,720
|
||||||||||||
|
Accrued
Expenses
|
316,977
|
1,270,075
|
||||||||||||
|
Derivative
Liability
|
1,320,679
|
-
|
||||||||||||
|
Other
Liabilities
|
18,574
|
18,574
|
||||||||||||
|
Total
Current Liabilities
|
8,910,256
|
4,874,179
|
||||||||||||
|
LONG-TERM
LIABILITIES
|
||||||||||||||
|
Revolving
Line of Credit
|
-
|
-
|
||||||||||||
|
Derivative
Liability
|
1,459,374
|
-
|
||||||||||||
|
Subordinated
Notes
|
500,000
|
-
|
||||||||||||
|
Other
Noncurrent Liabilities
|
243,888
|
117,157
|
||||||||||||
|
Total
Long-Term Liabilities
|
2,203,262
|
117,157
|
||||||||||||
|
|
||||||||||||||
|
DEFERRED
TAX LIABILITY
|
922,000
|
-
|
||||||||||||
|
Total
Liabilities
|
12,035,518
|
4,991,336
|
||||||||||||
|
STOCKHOLDERS'
EQUITY
|
||||||||||||||
|
Common
Stock, Par Value $.001; 100,000,000 Authorized, 43,911,044
|
||||||||||||||
|
Outstanding
(2008 – 34,120,103 Shares Outstanding)
|
43,912
|
34,121
|
||||||||||||
|
Additional
Paid-In Capital
|
124,884,266
|
51,692,776
|
||||||||||||
|
Retained
Earnings (Accumulated Deficit)
|
841,892
|
(1,957,060)
|
||||||||||||
|
Accumulated
Other Comprehensive Income (Loss)
|
(2,210,620)
|
(240,774)
|
||||||||||||
|
Total
Stockholders' Equity
|
123,559,450
|
49,529,063
|
||||||||||||
|
Total
Liabilities and Stockholders' Equity
|
$ 135,594,968
|
$
54,520,399
|
||||||||||||
|
*
See Note 2
|
||||||||||||||
|
The
accompanying notes are an integral part of these financial
statements.
|
||||||||||||||
F-3
|
STATEMENTS
OF OPERATIONS
|
|||||||||||||||
|
FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007
|
|||||||||||||||
|
Year
Ended December 31,
|
|||||||||||||||
|
2009
|
2008
|
2007
|
|||||||||||||
|
Adjusted
*
|
|||||||||||||||
|
REVENUES
|
|||||||||||||||
|
Oil
and Gas Sales
|
$
15,171,824
|
$ 3,542,994
|
$ -
|
||||||||||||
|
Gain
(Loss) on Settled Derivatives
|
(624,541)
|
778,885
|
-
|
||||||||||||
|
Mark-to-Market
of Derivative Instruments
|
(363,414)
|
||||||||||||||
|
Other
Revenue
|
37,630
|
-
|
-
|
||||||||||||
|
14,221,499
|
4,321,879
|
-
|
|||||||||||||
|
OPERATING
EXPENSES
|
|||||||||||||||
|
Production
Expenses
|
754,976
|
70,954
|
-
|
||||||||||||
|
Production
Taxes
|
1,300,373
|
203,182
|
-
|
||||||||||||
|
General
and Administrative Expense
|
2,452,823
|
1,985,914
|
1,754,826
|
||||||||||||
|
Share
Based Compensation
|
1,233,507
|
105,375
|
2,754,917
|
||||||||||||
|
Depletion
of Oil and Gas Properties
|
4,250,983
|
677,915
|
-
|
||||||||||||
|
Depreciation
and Amortization
|
91,794
|
67,060
|
3,446
|
||||||||||||
|
Accretion
of Discount on Asset Retirement Obligations
|
8,082
|
1,030
|
-
|
||||||||||||
|
Total
Expenses
|
10,092,538
|
3,111,430
|
4,513,189
|
||||||||||||
|
INCOME
(LOSS) FROM OPERATIONS
|
4,128,961
|
1,210,449
|
(4,513,189)
|
||||||||||||
|
OTHER
INCOME
|
135,991
|
383,891
|
207,896
|
||||||||||||
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
4,264,952
|
1,594,340
|
(4,305,293)
|
||||||||||||
|
INCOME
TAX PROVISION (BENEFIT)
|
1,466,000
|
(830,000)
|
-
|
||||||||||||
|
NET
INCOME (LOSS)
|
$ 2,798,952
|
$ 2,424,340
|
$
(4,305,293)
|
||||||||||||
|
Net
Income (Loss) Per Common Share - Basic
|
$ 0.08
|
$ 0.08
|
$ (0.18)
|
||||||||||||
|
Net
Income (Loss) Per Common Share - Diluted
|
$ 0.08
|
$ 0.07
|
$ (0.18)
|
||||||||||||
|
Weighted
Average Shares Outstanding – Basic
|
36,705,267
|
31,920,747
|
23,667,119
|
||||||||||||
|
Weighted
Average Shares Outstanding - Diluted
|
36,877,070
|
32,653,552
|
23,667,119
|
||||||||||||
|
*See
Note 2
|
|||||||||||||||
|
The
accompanying notes are an integral part of these financial
statements.
|
|||||||||||||||
F-4
|
STATEMENT
OF STOCKHOLDERS' EQUITY (DEFICIT)
|
|||||||||||||||||||
|
FOR
THE YEARS ENDED
DECEMBER
31, 2009, 2008, AND 2007
|
|||||||||||||||||||
|
Accumulated
|
|||||||||||||||||||
|
Other
|
Retained
|
Total
|
|||||||||||||||||
|
Additional
|
Stock
|
Comprehensive
|
Earnings
|
Stockholders'
|
|||||||||||||||
|
Common
Stock
|
Paid-In
|
Subscriptions
|
Income
|
(Accumulated
|
Equity
|
||||||||||||||
|
Shares
|
Amount
|
Capital
|
Receivable
|
(Loss)
|
Deficit)
|
(Deficit)
|
|||||||||||||
|
Balance
– December 31, 2006
|
18,000,000
|
$ 1,800
|
$ 38,575
|
$ (1,400)
|
$ -
|
$ (76,107)
|
$ (37,132)
|
||||||||||||
|
Payment
on Stock Subscriptions Receivable
|
-
|
-
|
-
|
1,400
|
-
|
-
|
1,400
|
||||||||||||
|
Sale
of 2,501,573 Common Shares for $1.05 Per Share
|
2,501,573
|
250
|
2,626,402
|
-
|
-
|
-
|
2,626,652
|
||||||||||||
|
Private
Placement Costs
|
-
|
-
|
(9,933)
|
-
|
-
|
-
|
(9,933)
|
||||||||||||
|
Issued
400,000 Common Shares to Montana Oil and
|
|||||||||||||||||||
|
Gas,
Inc. for Leasehold Interest
|
400,000
|
40
|
419,960
|
-
|
-
|
-
|
420,000
|
||||||||||||
|
Issued
271,440 Shares to Southfork Exploration, LLC
|
|||||||||||||||||||
|
for
Leasehold Interest
|
271,440
|
27
|
284,985
|
-
|
-
|
-
|
285,012
|
||||||||||||
|
Balance
Immediately Prior to Reverse Acquisition
|
|||||||||||||||||||
|
with
Kentex
|
21,173,013
|
2,117
|
3,359,989
|
-
|
-
|
(76,107)
|
3,285,999
|
||||||||||||
|
Reverse
Acquisition with Kentex:
|
|||||||||||||||||||
|
Recapitalization
of NOG with Kentex Common
|
|||||||||||||||||||
|
Stock
Issued in the Acquisition (Par Value
|
|||||||||||||||||||
|
Changed
to $.001 Per Share)
|
-
|
19,056
|
(19,056)
|
-
|
-
|
-
|
-
|
||||||||||||
|
Acquisition
of Kentex
|
1,491,110
|
1,491
|
(1,491)
|
-
|
-
|
-
|
-
|
||||||||||||
|
Legal
Fees
|
-
|
-
|
(25,000)
|
-
|
-
|
-
|
(25,000)
|
||||||||||||
|
Introduction
Fee
|
-
|
-
|
(12,500)
|
-
|
-
|
-
|
(12,500)
|
||||||||||||
|
Payment
to Kentex Stockholders
|
-
|
-
|
(377,500)
|
-
|
-
|
-
|
(377,500)
|
||||||||||||
|
Other
Professional Fees
|
-
|
-
|
(36,062)
|
-
|
-
|
-
|
(36,062)
|
||||||||||||
|
Totals
of Reverse Acquisition
|
1,491,110
|
20,547
|
(471,609)
|
-
|
-
|
-
|
(451,062)
|
||||||||||||
|
Balance
Immediately After Reverse Acquisition
|
|||||||||||||||||||
|
with
Kentex
|
22,664,123
|
22,664
|
2,888,380
|
-
|
-
|
(76,107)
|
2,834,937
|
||||||||||||
|
Issued
173,500 Shares for Consulting Fees
|
|||||||||||||||||||
|
(Value
between $4.75 and $5.18 per Common Share)
|
173,500
|
174
|
855,556
|
-
|
-
|
-
|
855,730
|
||||||||||||
|
Compensation
Related Stock Option Grants
|
-
|
-
|
2,366,417
|
-
|
-
|
-
|
2,366,417
|
||||||||||||
|
Sale
of 4,545,455 Common Shares for $3.30 Per Share
|
4,545,455
|
4,545
|
14,995,457
|
-
|
-
|
-
|
15,000,002
|
||||||||||||
|
(unit
placement)
|
|||||||||||||||||||
|
Private
Placement Costs net of Warrants Granted to Agent
|
-
|
-
|
(1,191,000)
|
-
|
-
|
-
|
(1,191,000)
|
||||||||||||
|
Issued
390,000 Common Shares for Leasehold Interest
|
390,000
|
390
|
1,957,410
|
-
|
-
|
-
|
1,957,800
|
||||||||||||
|
Issued
75,000 Shares as Compensation
|
75,000
|
75
|
388,425
|
-
|
-
|
-
|
388,500
|
||||||||||||
|
Repurchase
of 152,156 Common Shares
|
(152,156)
|
(152)
|
(1,049,724)
|
-
|
-
|
-
|
(1,049,876)
|
||||||||||||
|
Issued
Pursuant to Exercise of Options
|
1,000,000
|
1,000
|
1,049,000
|
-
|
-
|
-
|
1,050,000
|
||||||||||||
|
Net
Income (Loss)
|
-
|
-
|
-
|
-
|
-
|
(4,305,293)
|
(4,305,293)
|
||||||||||||
|
Balance
– December 31, 2007
|
28,695,922
|
$
28,696
|
$
22,259,921
|
$
-
|
$ -
|
$
(4,381,400)
|
$
17,907,217
|
||||||||||||
|
Issued
7,500 Common Shares for services
|
7,500
|
8
|
49,867
|
-
|
-
|
-
|
49,875
|
||||||||||||
|
Issued
318,495 Common Shares for Leasehold Interest
|
318,495
|
319
|
2,084,053
|
-
|
-
|
-
|
2,084,372
|
||||||||||||
|
(Value
between $2.30 and $11.98 per Common Share)
|
|||||||||||||||||||
|
Issued
20,000 Common Shares of Restricted Stock for employee
services
|
20,000
|
20
|
(20)
|
-
|
-
|
-
|
-
|
||||||||||||
|
Listing
Fee Paid to American Stock Exchange
|
-
|
-
|
(65,000)
|
-
|
-
|
-
|
(65,000)
|
||||||||||||
|
Issued
Pursuant to Exercise of Options
|
260,000
|
260
|
933,540
|
-
|
-
|
-
|
933,800
|
||||||||||||
|
Issued
Pursuant to Exercise of Warrants
|
4,818,186
|
4,818
|
25,977,244
|
-
|
-
|
-
|
25,982,062
|
||||||||||||
|
Warrant
Exercise Costs
|
-
|
-
|
(77,204)
|
-
|
-
|
-
|
(77,204)
|
||||||||||||
|
Stock
Grant Compensation
|
-
|
-
|
105,375
|
-
|
-
|
-
|
105,375
|
||||||||||||
|
Unrealized
Losses on Auction Rate Securities
|
-
|
-
|
-
|
-
|
(240,774)
|
-
|
(240,774)
|
||||||||||||
|
Income
Tax Benefit from Options Exercised
|
-
|
-
|
425,000
|
-
|
-
|
-
|
425,000
|
||||||||||||
|
Net
Income - As Adjusted
|
-
|
-
|
-
|
-
|
2,424,340
|
2,424,340
|
|||||||||||||
|
Balance
– December 31, 2008
|
34,120,103
|
$
34,121
|
$
51,692,776
|
$
-
|
$ (240,774)
|
$
(1,957,060)
|
$
49,529,063
|
||||||||||||
|
Warrants
Issued Included for Debt Issuance Costs
|
-
|
-
|
221,153
|
-
|
-
|
-
|
221,153
|
||||||||||||
|
Stock
Grant Compensation
|
-
|
-
|
366,690
|
-
|
-
|
-
|
366,690
|
||||||||||||
|
Net
Change in Cash Flow Hedge Derivatives
|
-
|
-
|
-
|
-
|
(1,483,639)
|
-
|
(1,483,639)
|
||||||||||||
|
Unrealized
Gain on Short-Term Investments
|
-
|
-
|
-
|
-
|
(486,207)
|
-
|
(486,207)
|
||||||||||||
|
Issued
180,000 shares as Debt Insurance Costs
|
180,000
|
180
|
475,020
|
-
|
-
|
-
|
475,200
|
||||||||||||
|
Issued
283,670 Shares as Compensation/Director Fees
|
|||||||||||||||||||
|
(Value
between $2.84 and $9.70 per Common Share)
|
283,670
|
284
|
2,092,695
|
-
|
-
|
-
|
2,092,979
|
||||||||||||
|
Sale
of 2,250,000 Common Shares for $6.00 Per Share
|
2,250,000
|
2,250
|
13,497,750
|
-
|
-
|
-
|
13,500,000
|
||||||||||||
|
Sale
of 6,500,000 Common Shares for $9.12 Per Share
|
6,500,000
|
6,500
|
59,273,500
|
-
|
-
|
-
|
59,280,000
|
||||||||||||
|
Issued
128,097 Common Shares for Leasehold Interest
|
|||||||||||||||||||
|
(Value
between $4.25 and $11.46 per Common Share)
|
128,097
|
128
|
1,115,610
|
-
|
-
|
-
|
1,115,738
|
||||||||||||
|
Repurchase
of 2,084 Common Shares
|
(2,084)
|
(2)
|
(20,213)
|
-
|
-
|
-
|
(20,215)
|
||||||||||||
|
Costs
of Capital Raise
|
-
|
-
|
(3,785,264)
|
-
|
-
|
-
|
(3,785,264)
|
||||||||||||
|
Issued
361,330 Common Shares of Restricted Stock
|
361,330
|
361
|
(361)
|
-
|
-
|
-
|
-
|
||||||||||||
|
Repurchase
of 52,061 Common Shares
|
(52,061)
|
(52)
|
(517,948)
|
-
|
-
|
-
|
(518,000)
|
||||||||||||
|
Issued
Pursuant to Exercise of Options
|
100,000
|
100
|
517,900
|
-
|
-
|
-
|
518,000
|
||||||||||||
|
Share
Adjustment Related to Kentex Transaction
|
41,989
|
42
|
(42)
|
-
|
-
|
-
|
-
|
||||||||||||
|
Income
Tax Provision for Share Based Compensation
|
-
|
-
|
(45,000)
|
-
|
-
|
-
|
(45,000)
|
||||||||||||
|
Net
Income
|
-
|
-
|
-
|
-
|
-
|
2,798,952
|
2,798,952
|
||||||||||||
|
Balance
- December 31, 2009
|
43,911,044
|
$
43,912
|
$
124,884,266
|
$
-
|
$
(2,210,620)
|
$ 841,892
|
$
123,559,450
|
||||||||||||
|
The
accompanying notes are an integral part of these financial
statements.
|
|||||||||||||||||||
F-5
|
STATEMENTS
OF CASH FLOWS
|
|||||||||||
|
FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007
|
|||||||||||
|
Year
Ended December 31,
|
|||||||||||
|
2009
|
2008
|
2007
|
|||||||||
|
Adjusted
*
|
|||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
|||||||||||
|
Net
Income (Loss)
|
$ 2,798,952
|
$ 2,424,340
|
$
(4,305,293)
|
||||||||
|
Adjustments
to Reconcile Net Income (Loss) to Net Cash Provided
by (Used for) Operating Activities:
|
|||||||||||
|
Depletion
of Oil and Gas Properties
|
4,250,983
|
677,915
|
-
|
||||||||
|
Depreciation
and Amortization
|
91,794
|
67,060
|
3,446
|
||||||||
| Amortization of Debt Issuance Costs | 459,343 | ||||||||||
|
Accretion
of Discount on Asset Retirement Obligations
|
8,082
|
1,030
|
-
|
||||||||
|
Income
Tax Provision (Benefit)
|
1,466,000
|
(830,000)
|
-
|
||||||||
|
Issuance
of Stock for Consulting Fees
|
-
|
49,875
|
855,730
|
||||||||
|
Loss
on Sale of Available for Sale Securities
|
-
|
381
|
-
|
||||||||
|
Market
Value adjustment of Derivative Instruments
|
363,414
|
(95,148)
|
-
|
||||||||
|
Lease
Incentives Received
|
-
|
91,320
|
|||||||||
|
Amortization
of Deferred Rent
|
(18,573)
|
(17,026)
|
-
|
||||||||
|
Share
- Based Compensation Expense
|
1,213,292
|
105,375
|
2,754,917
|
||||||||
|
Changes
in Working Capital and Other Items:
|
|||||||||||
|
Increase
in Trade Receivables
|
(4,996,070)
|
(2,028,941)
|
-
|
||||||||
|
Increase
(Decrease) in Other Receivables
|
874,453
|
(874,453)
|
-
|
||||||||
|
Increase
in Prepaid Expenses
|
(72,052)
|
(45,874)
|
(24,556)
|
||||||||
|
Increase
in Other Current Assets
|
(158,334)
|
-
|
-
|
||||||||
|
Increase
in Accounts Payable
|
4,484,724
|
1,821,556
|
113,254
|
||||||||
|
Increase
(Decrease) in Accrued Expenses
|
(953,098)
|
1,159,082
|
110,993
|
||||||||
|
Net
Cash Provided By (Used For) Operating Activities
|
9,812,910
|
2,506,492
|
(491,509)
|
||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
|||||||||||
|
Purchases
of Office Equipment and Furniture
|
(31,256)
|
(363,631)
|
(44,769)
|
||||||||
|
Decrease
(Increase) in Prepaid Drilling Costs
|
(1,449,485)
|
359,741
|
(364,290)
|
||||||||
|
Proceeds
from Sale of Oil and Gas Properties
|
-
|
468,609
|
-
|
||||||||
|
Purchase
of Available for Sale Securities
|
(24,106,294)
|
(3,800,524)
|
-
|
||||||||
|
Proceeds
from Sale of Available for Sale Securities
|
800,000
|
975,000
|
-
|
||||||||
|
Increase
in Oil and Gas Properties
|
(47,061,666)
|
(37,997,157)
|
(4,669,699)
|
||||||||
|
Net
Cash Used For Investing Activities
|
(71,848,701)
|
(40,357,962)
|
(5,078,758)
|
||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
|||||||||||
|
Increase
in Margin Loan
|
-
|
1,650,720
|
-
|
||||||||
|
Payments
on Line of Credit
|
(816,228)
|
-
|
-
|
||||||||
|
Advances
on Revolving Credit Facility
|
29,750,000
|
-
|
-
|
||||||||
|
Repayments
on Revolving Credit Facility
|
(29,750,000)
|
-
|
-
|
||||||||
|
Repayments
of Convertible Notes Payable (Related Party)
|
-
|
-
|
(165,000)
|
||||||||
|
Cash
Paid for Listing Fee
|
-
|
(65,000)
|
-
|
||||||||
|
Proceeds
from Derivatives
|
-
|
95,148
|
-
|
||||||||
|
Increase
in Subordinated Notes, net
|
500,000
|
-
|
|||||||||
|
Debt
Issuance Costs Paid
|
(1,190,061)
|
-
|
-
|
||||||||
|
Proceeds
from the Issuance of Common Stock - Net of Issuance Costs
|
68,994,736
|
25,904,858
|
14,997,992
|
||||||||
|
Proceeds
from Exercise of Stock Options
|
-
|
933,800
|
-
|
||||||||
|
Net
Cash Provided by Financing Activities
|
67,488,447
|
28,519,526
|
14,832,992
|
||||||||
|
NET
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
5,452,656
|
(9,331,944)
|
9,262,725
|
||||||||
|
CASH
AND CASH EQUIVALENTS – BEGINNING OF PERIOD
|
780,716
|
10,112,660
|
849,935
|
||||||||
|
CASH
AND CASH EQUIVALENTS – END OF PERIOD
|
$ 6,233,372
|
$ 780,716
|
$
10,112,660
|
||||||||
|
Supplemental
Disclosure of Cash Flow Information
|
|||||||||||
|
Cash
Paid During the Period for Interest
|
$
624,717
|
$ -
|
$ -
|
||||||||
|
Cash
Paid During the Period for Income Taxes
|
$ -
|
$ -
|
$ -
|
||||||||
|
Non-Cash
Financing and Investing Activities:
|
|||||||||||
|
Purchase
of Oil and Gas Properties through Issuance of Common Stock
|
$ 1,115,738
|
$
2,084,372
|
$
2,662,812
|
||||||||
|
Payment
of Consulting Fees through Issuance of Common Stock
|
$
-
|
$
49,875
|
$
855,730
|
||||||||
|
Payment
of Compensation through Issuance of Common Stock
|
$ 1,213,292
|
$ -
|
$ 388,500
|
||||||||
|
Capitalized
Asset Retirement Obligations
|
$ 137,222
|
$
60,407
|
$ -
|
||||||||
|
Cashless
Exercise of Stock Options
|
$ 518,000
|
$ -
|
$ 1,050,000
|
||||||||
|
Fair
Value of Warrants Issued for Debt Issuance Costs
|
$ 221,153
|
$ -
|
$ -
|
||||||||
|
Payment
of Debt Issuance Costs through Issuance of Common Stock
|
$ 475,200
|
$ -
|
$ -
|
||||||||
|
*
See Note 2
|
|||||||||||
|
The
accompanying notes are an integral part of these financial
statements.
|
|||||||||||
F-6
NORTHERN
OIL AND GAS, INC.
NOTES
TO FINANCIAL STATEMENTS
DECEMBER
31, 2009
Northern
Oil and Gas, Inc. (the “Company,” “we,” “us,” “our” and words of similar import)
is a growth-oriented independent energy company engaged in the acquisition,
exploration, exploitation and development of oil and natural gas
properties. Prior to March 20, 2007, our name was “Kentex Petroleum,
Inc.” The Company took its present form on March 20, 2007, when
Kentex completed a so-called short-form merger with its wholly-owned subsidiary,
Northern Oil and Gas, Inc. (“NOG”), a Nevada corporation engaged in the
Company’s current business, in which NOG merged into Kentex and Kentex was the
surviving entity. The Company’s common stock trades on the American
Stock Exchange under the symbol “NOG”.
The
Company will continue to focus on projects in the oil and gas industry primarily
based in the Rocky Mountains and specifically the Williston Basin Bakken Shale
formation. The Company has begun to develop its substantial leasehold in the
Bakken play and will continue to do so as well as target additional
opportunities in emerging plays utilizing its first mover leasing
advantage. The Company participates on a heads up basis in the
drilling of wells on our leasehold. The Company owns working interest
in wells, and does not lease land to operators. To this point we have
participated only in wells operated by others but have a substantial inventory
of high working interest locations that we have begun to develop. We
believe the advantage gained by participating as a non-operating partner in
approximately 179 gross oil wells completed as of December 31, 2009 has given us
valuable data on completions and will help our operating partners control well
costs and enhance results as we continue to develop our higher working interest
sections in 2010 and beyond.
The
Company participates on a heads up basis proportionate to its working interest
in a declared drilling unit. Although to this point we have
participated with interests ranging from approximately 1% to 61%, we expect to
participate in incrementally higher working interest drilling
units. Our current North Dakota and Montana acreage position in the
growing Williston Basin Bakken and Three Forks Play exposes us to approximately
162 net wells based on 640 acre spacing units and 255 net wells based on 320
acre spacing units. With 320-acre spacing units we have the ability
to drill approximately 578 net wells, including 255 net wells targeting the
Bakken formation, 255 net wells targeting the Three Forks formation and 68 net
wells targeting the Red River formation.
Our land
acquisition and field operations, along with various other services, are
primarily outsourced through the use of consultants and drilling
partners. The Company will continue to retain independent contractors
to assist in operating and managing the prospects as well as to carry out the
principal and necessary functions incidental to the oil and gas
business. With the additional acquisition of oil and natural gas
properties, the Company intends to continue to use both in-house employees and
outside consultants to develop and exploit its leasehold interests.
As an
independent oil and gas producer, the Company’s revenue, profitability and
future rate of growth are substantially dependent on prevailing prices of
natural gas and oil. Historically, the energy markets have been very
volatile and it is likely that oil and gas prices will continue to be subject to
wide fluctuations in the future. A substantial or extended decline in
natural gas and oil prices could have a material adverse effect on the Company’s
financial position, results of operations, cash flows and access to capital, and
on the quantities of natural gas and oil reserves that can be economically
produced.
These
financial statements have been prepared in accordance with generally accepted
accounting principles in the United States of America (“GAAP”).
F-7
Cash and Cash
Equivalents
The
Company considers highly liquid investments with insignificant interest rate
risk and original maturities to the Company of three months or less to be cash
equivalents. Cash equivalents consist primarily of interest-bearing
bank accounts and money market funds. Our cash positions represent
assets held in checking and money market accounts. These assets are
generally available to us on a daily or weekly basis and are highly liquid in
nature. Due to the balances being greater than $250,000, we do not
have FDIC coverage on the entire amount of bank deposits. The company
believes this risk is minimal. In addition, we are subject to
Security Investor Protection Corporation (SIPC) protection on a vast majority of
our financial assets.
Short-Term
Investments
All
marketable debt and equity securities and United States Treasuries that are
included in short-term investments are considered available-for-sale and are
carried at fair value. The short-term investments are considered
current assets due their maturity term or the company’s ability and intent to
use them to fund current operations. The unrealized gains and losses
related to these securities are included in accumulated other comprehensive
income (loss). When securities are sold, their cost is determined
based on the first-in first-out method. The realized gains and losses
related to these securities are included in other income in the statements of
operations.
Other Property and
Equipment
Property
and equipment that are not oil and gas properties are recorded at cost and
depreciated using the straight-line method over their estimated useful lives of
three to five years. Expenditures for replacements, renewals, and
betterments are capitalized. Maintenance and repairs are charged to
operations as incurred. Long-lived assets, other than oil and gas
properties, are evaluated for impairment to determine if current circumstances
and market conditions indicate the carrying amount may not be
recoverable. We have not recognized any impairment losses on non oil
and gas long-lived assets. Depreciation expense was $91,794, $67,070,
and $3,446 for the years ended December 31, 2009, 2008, and 2007.
Debt Issuance
Costs
In
February 2009, the Company entered into a revolving credit facility with CIT
Capital USA, Inc. (CIT) (See Note 9). The Company incurred costs
related to this facility that were capitalized on the Balance Sheet as Debt
Issuance Costs. Included in the Debt Issuance Costs are direct costs
paid to third parties for broker fees and legal fees, 180,000 shares of
restricted common stock paid as additional compensation for broker fees, and the
fair value of 300,000 warrants issued to CIT. The fair value of the
warrants was calculated using the Black-Scholes valuation model based on factors
present at the time of closing. CIT can exercise these warrants at
any time until the warrants expire in February 2012. The exercise
price of the warrants is $5.00 per warrant. The total amount
capitalized for Debt Issuance Costs is $1,670,000. The capitalized
costs are being amortized for three years over the term of the facility using
the effective interest method. In May 2009, the Company amended the
revolving credit facility with CIT to allow for additional
borrowings. The Company incurred $216,414 of direct costs related to
this amendment. The capitalized costs will be amortized over the
remaining term of the facility using the effective interest method.
The
amortization of debt issuance costs for the year ended December 31, 2009 was
$459,343.
Asset Retirement
Obligations
The
Company records the fair value of a liability for an asset retirement obligation
in the period in which the asset is acquired and a corresponding increase in the
carrying amount of the related long-lived asset. The liability is
accreted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the
liability is settled for an amount other than the recorded amount, a gain or
loss is recognized.
Revenue Recognition and Gas
Balancing
We
recognize oil and gas revenues from our interests in producing wells when
production is delivered to, and title has transferred to, the purchaser and to
the extent the selling price is reasonably determinable. We use the
sales method of accounting for gas balancing of gas production and would
recognize a liability if the existing proven reserves were not adequate to cover
the current imbalance situation. As of December 31, 2009 and 2008,
our gas production was in balance, i.e., our cumulative portion of gas
production taken and sold from wells in which we have an interest equaled our
entitled interest in gas production from those wells.
F-8
Stock-Based
Compensation
The
Company has accounted for stock-based compensation under the provisions of FASB
Accounting Standards Codification (ASC) 718-10-55 (
Prior authoritative literature:
FASB Statement 123(R),
Share-Based
Payment).
This statement requires us to record an expense
associated with the fair value of stock-based compensation. We use
the Black-Scholes option valuation model to calculate stock based compensation
at the date of grant. Option pricing models require the input of
highly subjective assumptions, including the expected price
volatility. Changes in these assumptions can materially affect the
fair value estimate.
The
Company accounts for income taxes under FASB ASC 740-10-30 (
Prior authoritative literature,
FASB Statement 109,
Accounting for Income Taxes)
.
Deferred income tax assets and liabilities are determined based upon differences
between the financial reporting and tax bases of assets and liabilities and are
measured using the enacted tax rates and laws that will be in effect when the
differences are expected to reverse. Accounting standards requires
the consideration of a valuation allowance for deferred tax assets if it is
“more likely than not” that some component or all of the benefits of deferred
tax assets will not be realized.
Stock
Issuance
The
Company records the stock-based compensation awards issued to non-employees and
other external entities for goods and services at either the fair market value
of the goods received or services rendered on the instruments issued in exchange
for such services, whichever is more readily determinable, using the measurement
date guidelines enumerated in FASB ASC 505-50-30 (
Prior authoritative literature,
EITF 96-18,
Accounting
for Equity Instruments That Are Issued to Other Than Employees for Acquiring or
in Conjunction with Selling, Goods, or Services).
Net Income (Loss) Per Common
Share
Net
Income (Loss) per common share is based on the Net Income (Loss) divided by
weighted average number of common shares outstanding.
Diluted
earnings per share are computed using weighted average number of common shares
plus dilutive common share equivalents outstanding during the period using the
treasury stock method. As the Company has a loss for the period ended
December 31, 2007 the potentially dilutive shares were anti-dilutive and were
thus not added into the earnings per share calculation.
Full Cost
Method
The
Company follows the full cost method of accounting for oil and gas operations
whereby all costs related to the exploration and development of oil and gas
properties are initially capitalized into a single cost center (“full cost
pool”). Such costs include land acquisition costs, geological and
geophysical expenses, carrying charges on non-producing properties, costs of
drilling directly related to acquisition, and exploration
activities. Internal costs that are capitalized are directly
attributable to acquisition, exploration and development activities and do not
include costs related to the production, general corporate overhead or similar
activities. Costs associated with production and general corporate
activities are expensed in the period incurred. Capitalized costs are summarized
as follows for the years ended December 31, 2009, 2008, and 2007:
F-9
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Capitalized
Certain Payroll and Other Internal Costs
|
$ | 2,616,262 | $ | 1,374,071 | $ | - | ||||||
|
Capitalized
Interest Costs
|
624,717 | - | - | |||||||||
|
Total
|
$ | 3,240,979 | $ | 1,374,071 | $ | - | ||||||
As of
December 31, 2009 we controlled acreage in Sheridan County, Montana with primary
targets including the Red River and Mission Canyon. We controlled acreage
in North Dakota, primarily in Mountrail County, targeting the Bakken Shale
and Three Forks/Sanish as well as acreage in Yates County, New York that is
prospective for Marcellus Shale and Trenton-Black River natural gas
production. See Note 5 for explanation of activities on these
properties.
Proceeds
from property sales will generally be credited to the full cost pool, with no
gain or loss recognized, unless such a sale would significantly alter the
relationship between capitalized costs and the proved reserves attributable to
these costs. A significant alteration would typically involve a sale
of 25% or more of the proved reserves related to a single full cost
pool. In the year ended December 31, 2008, the Company sold acreage
for $468,609. The proceeds for these sales were applied to reduce the
capitalized costs of oil and gas properties. There were no property sales for
the year ended December 31, 2009.
Capitalized
costs associated with impaired properties and capitalized cost related to
properties having proved reserves, plus the estimated future development costs,
asset retirement costs under FASB ASC 410-20-25 (
Prior authoritative literature:,
FASB Statement 143,
Accounting for Asset Retirement
Obligations)
are depleted and amortized on the unit-of-production method
based on the estimated gross proved reserves as determined by independent
petroleum engineers. The costs of unproved properties are withheld
from the depletion base until such time as they are either developed or
abandoned. When proved reserves are assigned or the property is
considered to be impaired, the cost of the property or the amount of the
impairment is added to costs subject to depletion calculations.
Capitalized
costs of oil and gas properties (net of related deferred income taxes) may not
exceed an amount equal to the present value, discounted at 10% per annum, of the
estimated future net cash flows from proved oil and gas reserves plus the cost
of unevaluated properties (adjusted for related income tax
effects). Should capitalized costs exceed this ceiling, impairment is
recognized. The present value of estimated future net cash flows is
computed by applying 12-month average price of oil and natural gas to estimated
future production of proved oil and gas reserves as of period-end, less
estimated future expenditures to be incurred in developing and producing the
proved reserves and assuming continuation of existing economic
conditions. Such present value of proved reserves’ future net cash
flows excludes future cash outflows associated with settling asset retirement
obligations that have been accrued on the Balance Sheet. Should this
comparison indicate an excess carrying value, the excess is charged to earnings
as an impairment expense. To this point the Company has not
realized any
impairment of its properties due to our low basis in the acreage and
productivity and economics of our producing wells.
Use of
Estimates
The
preparation of financial statements under generally accepted accounting
principles (“GAAP”) in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. The most significant estimates relate to proved oil
and natural gas reserve volumes, future development costs, estimates relating to
certain oil and natural gas revenues and expenses, fair value of derivative
instruments, fair value of certain investments, and deferred income
taxes. Actual results may differ from those estimates.
F-10
Reclassifications
Certain
reclassifications have been made to prior years’ reported amounts in order to
conform with the current year presentation. These reclassifications did not
impact our net income, stockholders’ equity or cash flows.
Derivative Instruments and
Price Risk Management
The
Company uses derivative instruments from time to time to manage market risks
resulting from fluctuations in the prices of oil and natural gas. The
Company may periodically enter into derivative contracts, including price swaps,
caps and floors, which require payments to (or receipts from) counterparties
based on the differential between a fixed price and a variable price for a fixed
quantity of oil or natural gas without the exchange of underlying
volumes. The notional amounts of these financial instruments are
based on expected production from existing wells. The Company has,
and may continue to use exchange traded futures contracts and option contracts
to hedge the delivery price of oil at a future date.
At the
inception of a derivative contract, the Company historically designated the
derivative as a cash flow hedge. For all derivatives designated as
cash flow hedges, the Company formally documented the relationship between the
derivative contract and the hedged items, as well as the risk management
objective for entering into the derivative contract. To be designated
as a cash flow hedge transaction, the relationship between the derivative and
the hedged items must be highly effective in achieving the offset of changes in
cash flows attributable to the risk both at the inception of the derivative and
on an ongoing basis. The Company historically measured hedge
effectiveness on a quarterly basis and hedge accounting would be discontinued
prospectively if it determined that the derivative is no longer effective in
offsetting changes in the cash flows of the hedged item. Gains and
losses deferred in accumulated other comprehensive income related to cash flow
hedge derivatives that become ineffective remain unchanged until the related
production is delivered. If the Company determines that it is
probable that a hedged forecasted transaction will not occur, deferred gains or
losses on the
derivative are recognized
in earnings immediately. See Note 15 for a description of the
derivative contracts which the Company executed during 2009.
Derivatives,
historically, are recorded on the balance sheet at fair value and changes in the
fair value of derivatives are recorded each period in current earnings or other
comprehensive income, depending on whether a derivative is designated as part of
a hedge transaction and, if it is, depending on the type of hedge
transaction. The Company’s derivatives historically consist primarily
of cash flow hedge transactions in which the Company is hedging the variability
of cash flows related to a forecasted transaction. Period to period
changes in the fair value of derivative instruments designated as cash flow
hedges were reported in other comprehensive income and reclassified to earnings
in the periods in which the contracts are settled. The ineffective
portion of the cash flow hedges was reflected in current period earnings as gain
or loss from derivative. Gains and losses on derivative instruments
that did not qualify for hedge accounting were included in income or loss from
derivatives in the period in which they occur. The resulting cash
flows from derivatives are reported as cash flows from operating
activities.
On
November 1, 2009, due to the volatility of price differentials in the Williston
Basin, the Company de-designated all derivatives that were previously classified
as cash flow hedges and in addition, the Company has elected not to designate
any subsequent derivative contracts as accounting hedges under FASB ASC
815-20-25 (Prior authoritative literature: FASB Statement 133,
Accounting for Derivative
Instruments and Hedging Activities)
. As such, all derivative
positions are carried at their fair value on the balance sheet and are
marked-to-market at the end of each period. Any realized and
unrealized gains or losses are recorded as gain (loss) on derivatives net, as an
increase or decrease in revenues on the Statement of Operations rather than as a
component of other comprehensive income (loss) or other Income
(expense).
Impairment
FASB ASC
360-10-35-21 (
Prior
authoritative literature,
FASB Statement 144,
Accounting for the Impairment and
Disposal of Long-Lived Assets)
, requires that long-lived assets to be
held and used be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. Oil and gas properties accounted for using the full cost
method of accounting (which we use) are excluded from this requirement but
continue to be subject to the full cost method’s impairment
rules. There was no impairment identified at December 31, 2009, 2008,
and 2007.
Change in Accounting
Principle Related to Drilling Costs
In 2009,
the Company changed its method of accounting for drilling costs from the accrual
of drilling costs at the time drilling commenced for a well to recording the
costs when amounts are invoiced by operators. Recording
F-11
drilling
costs when the amounts are invoiced by operators is deemed preferable as it
better represents the Company’s actual drilling costs. The recording
of drilling costs in this method also is consistent with other companies in the
oil and gas industry. Generally accepted accounting principles
require that the impact of the change in accounting be applied retrospectively
to all periods presented. As a result, all prior period financial
statements have been adjusted to give effect to the cumulative impact of this
change.
The
following Table shows the effects on the Company's Balance Sheet:
|
Year
Ended December 31, 2008
|
||||||||||||
|
As
Reported
|
Adjusted
|
Effect
of Change
|
||||||||||
|
Deferred
Tax Asset - Current
|
$ | 1,433,000 | $ | 1,390,000 | $ | (43,000 | ) | |||||
|
Oil
and Gas Properties, Full Cost Method
|
55,680,567 | 47,260,838 | (8,419,729 | ) | ||||||||
|
Accumulated
Depreciation and Depletion
|
856,010 | 748,421 | (107,589 | ) | ||||||||
|
Accrued
Drilling Costs
|
8,419,729 | - | (8,419,729 | ) | ||||||||
|
Accumulated
Deficit
|
$ | (2,021,649 | ) | $ | (1,957,060 | ) | $ | 64,589 | ||||
The
following Table shows the effect on the Company's Statement of
Operations:
|
Year
Ended December 31, 2008
|
||||||||||||
|
As
Reported
|
Adjusted
|
Effect
of Change
|
||||||||||
|
Depletion
Expense
|
$ | 785,504 | $ | 677,915 | $ | (107,589 | ) | |||||
|
Income
Tax Provision (Benefit)
|
(873,000 | ) | (830,000 | ) | 43,000 | |||||||
|
Net
Income
|
$ | 2,359,751 | $ | 2,424,340 | $ | 64,589 | ||||||
|
Earnings
Per Share – Basic
|
$ | 0.07 | $ | 0.08 | $ | 0.01 | ||||||
|
Earnings
Per Share – Diluted
|
$ | 0.07 | $ | 0.07 | $ | - | ||||||
The
following Table shows the effect on the Company’s Statement of Cash
Flows:
|
Year
Ended December 31, 2008
|
||||||||||||
|
As
Reported
|
Adjusted
|
Effect
of Change
|
||||||||||
|
Net
Income
|
$ | 2,359,751 | $ | 2,424,340 | $ | 64,589 | ||||||
|
Depletion
of Oil and Gas Properties
|
785,504 | 677,915 | (107,589 | ) | ||||||||
|
Income
Tax Benefit
|
(873,000 | ) | (830,000 | ) | 43,000 | |||||||
|
Increase
in Accrued Drilling Costs
|
8,419,729 | - | (8,419,729 | ) | ||||||||
|
Increase
in Oil and Gas Properties
|
(46,416,886 | ) | (37,997,157 | ) | 8,419,729 | |||||||
There was
no effect on the Company's Statement of Operations or Statement of Cash Flows
for the year ended December 31, 2007. The Company did not commence
production on its wells until 2008 and reported no Accrued Drilling Costs as of
December 31, 2007.
New Accounting
Pronouncements
In March
2008, the FSAB issued
FASB ASC
815-10-15 (
Prior authoritative
literature,
FASB Statement 161,
Disclosures About Derivative
Instruments and Hedging Activities
).
FASB ASC
815-10-15 is intended to improve financial reporting about derivative
instruments and hedging activities by requiring enhanced disclosures to enable
investors to better understand their effects on an entity's financial position,
financial performance, and cash flows. FASB ASC 815-10-15 is
effective for financial statements issued for fiscal years and interim
periods
F-12
beginning
after November 15, 2008, with early application encouraged.
Pursuant to the transition provisions of
the Statement, the Company adopted FASB ASC 815-10-15 on January 1,
2009. The required disclosures are presented in Note 15 on a
prospective basis. This Statement does not impact the financial results as it is
disclosure-only in nature.
In
April 2009, the FASB issued FASB ASC 270-10-05 (
Prior authoritative literature:
APB 28-1,
Interim
Disclosures About Fair Value of Financial Instruments)
. FASB
ASC 270-10-05 amends FASB ASC 825-10-50
(Prior authoritative literature:
FASB Statement 107,
Disclosures About Fair Value of
Financial Instruments)
to require an entity to provide disclosures about
fair value of financial instruments in interim financial
information. FASB ASC 270-10-05 is to be applied prospectively and is
effective for interim and annual periods ending after June 15, 2009 with
early adoption permitted for periods ending after March 15, 2009. The
required disclosures are presented in Note 13 on a prospective
basis.
In
February 2008, the FASB issued FASB ASC 820-10-65-1 (
Prior authoritative literature:
FSP FAS 157-2/Statement 157,
Effective Date of FASB Statement No.
157.)
FASB ASC 820-10-65-1
delayed the effective
date for all nonfinancial assets and nonfinancial liabilities, except those that
are recognized or disclosed at fair value in the financial statements on a
recurring basis (at least annually). The adoption of the provisions of FASB ASC
820-10-65-1
related to nonfinancial
assets and nonfinancial liabilities on January 1, 2009 did not have a
material impact on the Financial Statements. See Note 13 for FASB ASC
820-10-65-1
disclosures.
In April
2009, the FASB issued FASB ASC 820-10-65-4 (
Prior authoritative literature:
FASB Statement 157-4,
Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not
Orderly)
. FASB ASC 820-10-65-4 provides additional guidance in
estimating fair value, when the volume and level of transaction activity for an
asset or liability have significantly decreased in relation to normal market
activity for the asset or liability. FASB ASC 820-10-65-4
also provides
additional guidance on circumstances that may indicate a transaction is not
orderly. FASB ASC 820-10-65-4
is effective for
interim periods ending after June 15, 2009, and the Company has adopted its
provisions during second quarter 2009. FASB ASC 820-10-65-4 did not
have a significant impact on the Company’s financial position, results of
operations, cash flows, or disclosures.
In
April 2009, the FASB issued FASB ASC 320-10-65 (
Prior authoritative literature:
FSP FAS 115-2/124-2,
Recognition and Presentation of
Other-Than-Temporary Impairments)
. The guidance applies to investments in
debt securities for which other-than-temporary impairments may be recorded. If
an entity’s management asserts that it does not have the intent to sell a debt
security and it is more likely than not that it will not have to sell the
security before recovery of its cost basis, then an entity may separate
other-than-temporary impairments into two components: 1) the amount related to
credit losses (recorded in earnings), and 2) all other amounts (recorded in
other comprehensive income). This ASC is to be applied prospectively and is
effective for interim and annual periods ending after June 15, 2009 with
early adoption permitted for periods ending after March 15, 2009. The
adoption of the provisions of this ASC in the second quarter 2009 did not have a
material impact on the Financial Statements.
In June
2009, the FASB issued FASB ASC 860-10-05 (
Prior authoritative literature:
FASB Statement 166,
Accounting for Transfers of
Financial Assets)
. FASB ASC 860-10-05 is effective for fiscal years
beginning after November 15, 2009. The Company is currently assessing the impact
of FASB ASC 860-10-05 on its financial position and results of
operations.
In June 2009, the FASB issued FASB ASC
810-10-25 (
Prior authoritative
literature:
FASB Statement
167-Amendment to FIN 46(R),
Consolidation of
Variable Entities)
. FASB
ASC 810-10-25 eliminates the quantitative approach previously required for
determining the primary beneficiary of a variable interest entity and requires a
qualitative analysis to determine whether an enterprise’s variable interest
gives it a controlling financial interest in a variable interest entity. FASB
ASC 810-10-25 contains
certain guidance for determining
whether an
entity is a variable interest entity.
This statement also requires ongoing reassessments of whether an enterprise is
the primary beneficiary of a variable interest entity. FASB ASC 810-10-25 will
be effective as of the beginning of the Company’s 2010 fiscal year. The Company
is currently evaluating the impact of the adoption of FASB ASC
810-10-25.
F-13
In June
2009, the FASB issued FASB ASC 105-10-65 (
Prior authoritative literature:
FASB Statement 168,
The
FASB Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles
). Under FASB ASC 105-10-65, the FASB Accounting
Standards Codification
™
(the “Codification”) becomes the exclusive source of authoritative U.S.
generally accepted accounting principles (“U.S. GAAP”) recognized by the FASB to
be applied by nongovernmental entities. Rules and interpretive releases of the
Securities and Exchange Commission (“SEC”) under authority of federal securities
laws are also sources of authoritative GAAP for SEC registrants. The
Codification will supersede all then-existing non-SEC accounting and reporting
standards, with the exception of certain non-SEC accounting literature which
will become nonauthoritative. FASB ASC 105-10-65 is effective for the Company’s
2009 third fiscal quarter. The adoption of FASB ASC 105-10-65 did not have a
material impact on the Company’s Financial Statements. All references to U.S.
GAAP provided in the notes to the Financial Statements have been updated to
conform to the Codification.
In
October 2009, the FASB issued ASU No. 200-13, Revenue Recognition – Multiple
Deliverable Revenue Arrangements (“ASU 2009-13”). ASU 2009-13 updates
the existing multiple-element revenue arrangements guidance currently included
in FASB ASC 605-25. The revised guidance provides for two significant
changes to the existing multiple-element revenue arrangements
guidance. The first change relates to the determination of when the
individual deliverables included in a multiple-element arrangement may be
treated as separate units of accounting. This change will result in
the requirement to separate more deliverables within an arrangement, ultimately
leading to less revenue deferral. The second change modifies the
manner in which the transaction consideration is allocated across the separately
identified deliverables. Together, these changes will result in
earlier recognition of revenue and related costs for multiple-element
arrangements than under previous guidance. This guidance expands the
disclosures required for multiple-element revenue
arrangements. Effective for interim and annual reporting periods
beginning after December 15, 2009. The Company is currently
evaluating the potential impact, if any, of this guidance on its financial
statements.
All
marketable debt and equity securities and United States Treasuries that are
included in short-term investments are considered available-for-sale and are
carried at fair value. The short-term investments are considered
current assets due their maturity term or the company’s ability and intent to
use them to fund current operations. The unrealized gains and losses
related to these securities are included in accumulated other comprehensive
income (loss). When securities are sold, their cost is determined
based on the first-in first-out method. The realized gains and losses
related to these securities are included in other income in the statements of
operations.
The
following is a summary of our short-term investments as of December 31,
2009:
|
Fair
Market
|
||||||||||||
|
Cost
at
|
Value
at
|
|||||||||||
|
December
31,
|
December
31,
|
|||||||||||
|
2009
|
Unrealized
(Loss)
|
2009
|
||||||||||
|
Auction
Rate Municipal Bonds
|
$ | 1,750,000 | $ | (198,105 | ) | $ | 1,551,895 | |||||
|
Auction
Rate Preferred Stock
|
275,143 | (8,682 | ) | 266,461 | ||||||||
|
United
States Treasuries
|
24,063,314 | (978,194 | ) | 23,085,120 | ||||||||
|
Total
Short-Term Investments
|
$ | 26,088,457 | $ | (1,184,981 | ) | $ | 24,903,476 | |||||
For the
year ended December 31, 2009 there were no realized gains or losses recognized
on the sale of investments. In November 2008 we received, in a
settlement agreement from UBS AG (“UBS”), rights which allow us to put back the
auction rate securities at par value to UBS starting in June 2010. We
expect to liquidate these investments at par no later than June 2010, in the
meantime they continue to pay interest at various rates. Under the
settlement agreement with UBS, we also have the ability to borrow up to 75% of
the loan-to-market value of eligible auction rate securities on a no-net cost
basis. As of December 31, 2009, we have borrowed $834,492 under this
agreement, with an additional $684,258 of borrowings available under the
agreement.
The
Company reviews these investments on a quarterly basis to determine if it is
probable that the Company will realize some portion of the unrealized loss in
accordance with FASB ASC 320-10-35 (
Prior authoritative
literature,
F-14
FASB
Statement 115, 115-1, and 124-1,
The Meaning of Other-Than-Temporary
Impairment and Its Application to Certain
Investments)
. In determining if the difference between
cost and estimated fair value of the short-term investments was deemed either
temporary or other-than-temporary impairment, the Company evaluated each type of
short-term investment using a set of criteria including decline in value,
duration of the decline, period until anticipated recovery, nature of
investment, probability of recovery, financial condition and near-term prospects
of the issuer, the Company’s intent and ability to retain the investment,
attributes of the decline in value, status with rating agencies, status of
principal and interest payments and any other issues related to the underlying
securities. The Company determined the decline in the fair values in all of the
short-term investments were temporary as of December 31, 2009 and 2008,
primarily based on estimated cash flows of the investments, the settlement
agreement entered into with UBS, and the Company’s ability and intent to hold
the investments until settlement.
Property
and equipment at December 31, 2009 and 2008, consisted of the
following:
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
Adjusted
|
|||||||
|
Oil
and Gas Properties, Full Cost Method
|
||||||||
|
Unevaluated
Costs, Not Subject to Amortization or Ceiling Test
|
$ | 53,862,529 | $ | 35,990,267 | ||||
|
Evaluated
Costs
|
42,939,097 | 11,270,571 | ||||||
| 96,801,626 | 47,260,838 | |||||||
|
Office
Equipment, Furniture, Leasehold Improvements and Software
|
439,656 | 408,400 | ||||||
| 97,241,282 | 47,669,238 | |||||||
|
Less:
Accumulated Depreciation, Depletion and Amortization
|
||||||||
|
Property
and Equipment
|
5,091,198 | 748,421 | ||||||
|
Total
|
$ | 92,150,084 | $ | 46,920,817 | ||||
The
following table shows depreciation, depletion, and amortization expense by type
of asset:
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
Adjusted
|
|||||||
|
Depletion
of Costs for Evaluated Oil and Gas Properties
|
$ | 4,250,983 | $ | 677,915 | ||||
|
Depreciation
of Office Equipment, Furniture, and Software
|
91,794 | 67,060 | ||||||
|
Total
Depreciation, Depletion, and Amortization Expense
|
$ | 4,342,777 | $ | 744,975 | ||||
Acquisitions
Montana
Acquisitions
In
February 2007, the Company acquired leasehold interests in approximately 22,000
net mineral acres in Sheridan County, Montana. The Company paid a
combination of cash and stock as consideration for such acquisition, including
the issuance of an aggregate of 400,000 restricted shares of its common
stock.
At
various points in 2009, we acquired leasehold interests in approximately 6,100
net mineral acres in development areas located in Roosevelt, Richland and
Sheridan Counties, Montana, in which we are targeting the Bakken
Shale.
F-15
On
November 13, 2009, we entered into a Letter of Intent with Slawson pursuant to
which we agreed to acquire a twenty percent (20%) working interest ownership in
the exploration and development of Slawson’s Big Sky Project in Richland County,
Montana for which Slawson controls leasehold interest in 13,401 gross acres and
11,586 net acres. For each well we elect to participate, we will pay a
participation interest share of all costs to drill, equip, complete, test and
plug such well(s) on an at cost basis.
North
Dakota Acquisitions
At
various points in late 2007 and throughout 2008, the Company acquired leasehold
interests in approximately 21,498 net mineral acres of land via bulk purchases
in the core development area of Mountrail County, North Dakota. The
Company paid a combination of cash and stock as consideration for such
acquisitions, including the issuance of an aggregate of 633,027 restricted
shares of its common stock. In addition to these major acquisitions
the Company completed a series of small transactions pursuant to which it
purchased leasehold interests in approximately 8,000 net mineral acres in
Mountrail County.
On June
11, 2008, the Company entered into a purchase agreement pursuant to which it
ultimately acquired leasehold interests in approximately 23,210 net mineral
acres primarily in Dunn County, North Dakota. The Company also
completed various additional acquisitions of oil and gas leasehold interests
through numerous small transactions with several parties in fiscal years 2007
and 2008.
At
various points in 2007 and 2008, the Company purchased leasehold interests in
approximately 10,000 net mineral acres in and around Burke and Divide Counties
of North Dakota for cash consideration.
In May
2009, the Company entered into an exploration and development agreement with
Slawson Exploration Company, Inc. (Slawson) pursuant to which the Company
acquired certain North Dakota Bakken assets from Windsor Bakken LLC as part of a
syndicate led by privately owned Slawson. Pursuant to the agreement, the
Company purchased a five percent (5.0%) interest of the undeveloped acreage,
including approximately 60,000 net acres. The Company also acquired an
additional nine percent (9%) interest in the existing well bores purchased from
Windsor Bakken LLC, providing the Company an aggregate fourteen percent (14%)
interest in the existing 59 gross Bakken and Three Forks well bores in North
Dakota including approximately 1,200 barrels of oil production per day. In
the transaction, the Company purchased approximately 300,000 barrels of proven
producing reserves as well as approximately 3,000 net undeveloped
acres. The Company paid a total cost of $7,300,000 for the initial
acquisition of acreage and well bore interests.
On
November 3, 2009, along with Slawson Exploration we acquired 24 high working
interest sections comprising approximately 12,000 net acres located in western
McKenzie and Williams Counties of North Dakota. We acquired a 50%
interest in these properties and will participate in drilling on a heads-up
basis. These properties are proximal to several recent high-rate
producing wells. We paid approximately $1,100 per net acre acquired
in this acquisition and expect to begin drilling these properties in early
2011.
On
November 17, 2009, we entered into an Exploration and Development Agreement with
Area of Mutual Interest with Slawson pursuant to which we agreed to participate
with a fifty percent (50%) working interest ownership, which equates to a thirty
percent (30%) participation interest in the exploration and development of
Slawson’s Anvil Project in Roosevelt and Sheridan Counties, Montana and Williams
County, North Dakota. In the transaction, we acquired an interest in
12,500 net acres in leases at $750 per net acre for a thirty percent (30%)
interest and an aggregate sum of $2,812,500. We agreed to participate
in all costs to drill, equip, complete, test and plug the well and to pay costs
for the well on an at cost basis. We have the option to elect to
participate or not participate as to each well drilled in the applicable project
area. For each well in which we elect to participate, we will pay a
participation interest share of all costs to drill, equip, complete, test and
plug such wells on an at cost basis.
In
addition to acquiring acreage through large block acquisitions, we have
organically acquired approximately 4,000 net mineral acres in all of our key
prospect areas in the form of both effective leases and
top-leases. In this organic acquisition program we have spent an
average of approximately $730 per net acre acquired.
The
Company has also completed other miscellaneous non-material acquisitions in
North Dakota, and utilized a combination of stock and cash consideration for
some of the acquisitions.
F-16
New
York Acquisition
In
September 2007, the Company acquired leasehold interests in approximately 10,000
net mineral acres in the Appalachia Basin of New York. The Company
paid a combination of cash and stock as consideration for such acquisition,
including the issuance of an aggregate of 275,000 restricted shares of its
common stock.
Certain
of the foregoing acquisitions were purchased using the services of, or purchased
from, parties considered to be related to the Company or the Company’s Chief
Executive Officer, Michael L. Reger. See Note 7. All
transactions involving related parties were approved by the Company’s Board of
Directors or Audit Committee.
The
Company has neither authorized nor issued any shares of preferred
stock.
On May 3,
2007, the Company issued 100,000 shares of common stock to Insight Capital
Consultants Corporation pursuant to a consulting agreement with
them. The stock issued was valued at $475,000 and expensed to general
and administrative expense. The shares were valued based on the
market price of the Company’s stock on the date of issuance.
In
September 2007, the Company completed a private placement of 4,545,455 shares of
common stock to accredited investors at a subscription price of $3.30 per share
for total gross proceeds of $15,000,002. In addition to common stock,
investors purchasing shares in the private placement received a warrant to
purchase common stock. For each share of common stock purchased in
this transaction, the purchaser received the right to purchase one-half share of
the Company’s common stock at a price of $5.00 per share for a period of 18
months from the date of closing and the right to purchase one-half share of the
Company’s common stock at a price of $6.00 for a period of 48 months from the
date of closing. The placement agents received consideration in cash
and warrants of $1,191,000 which were netted against the proceeds of the
offering through Additional Paid-In Capital. The total number of
shares that are issuable upon exercise of warrants, including the placement
agent's warrant is 4,818,183. All warrants issued as part of this
private placement were exercised in 2008.
In
November 2007, the Company issued 73,500 shares of common stock to various
consultants pursuant to consulting agreements. The company also
issued 75,000 shares of common stock to an employee pursuant to a written
employment agreement. These 148,500 shares were valued at $769,230,
the market value of the shares of common stock on the date of issuance, and
expensed as general and administrative expenses. The shares were
valued at the calculated fair value of the Company’s stock on the date of the
issuance.
In
December 2007, the Chief Executive Officer and Chief Financial Officer each
exercised 500,000 stock options granted to them in 2006.
In 2008
optionees exercised 260,000 stock options granted in 2006 and 2007, resulting in
cash proceeds to the Company of $933,800. A tax benefit of $425,000
related to fully vested stock option awards exercised was recorded as an
increase to additional paid-in capital
In
February 2009, the Company agreed to issue 92,000 shares of Common Stock to
three employees of the company as compensation for their
services. The employees were fully vested in the shares on the date
of the grant. The fair value of the stock to be issued was $261,280
or $2.84 per share, the market value of a share of common stock on the date the
stock was obligated to be issued. The entire amount of this stock
award was expensed in the year ended December 31, 2009.
On
February 27, 2009, the Company closed on a revolving credit facility with CIT
Capital USA, Inc. (CIT). As part of obtaining this credit facility
agreement the Company entered into an engagement with Cynergy Advisors, LLC
(Cynergy). As part of the compensation for the work performed on
obtaining the financing, Cynergy received 180,000 shares of restricted Common
Stock of the Company. The fair value of the restricted stock was
$475,200 or $2.64 per share, the market value of a share of Common Stock on the
date the financing closed. The fair value of this stock was
capitalized as Debt Issuance Costs and is being amortized for three years over
the term of the financing.
F-17
On April
3, 2009 the Company acquired leasehold interests in North Dakota. The total
consideration paid for this acreage was 49,092 shares of restricted common
stock. The fair value of the restricted stock was $224,879, or $4.58 per
share, the market value of a share of Common Stock on the date the leasehold
interests were acquired.
In June
2009, the Company completed a registered direct offering of 2,250,000 shares of
common stock at a price of $6.00 per share for total gross proceeds of
$13,500,000. The Company incurred costs of $813,237 related to this
offering. These costs were netted against the proceeds of the
offering through Additional Paid-In Capital.
On
October 26, 2009, we deposited 41,989 shares of common stock in a
specially-designated shareholder account that had been previously-created to
hold shares of our common stock represented by certificates that appear in our
stock transfer records but were known to have been cancelled and their
underlying shares transferred between July of 1987 and August of 1999. An
aggregate of 58,268 shares of our common stock are held in the
specially-designated shareholder account, which, following a substantial review
of all available historical stock transfer records, we concluded represents the
maximum number of shares of our common stock that could potentially be released
to shareholders who may be able to establish a valid claim to such shares due to
previously unrecognized issues with our stock transfer records. These
shares are considered issued and outstanding and are included in the total
number of shares outstanding disclosed on the cover page of this
report.
On
November 4, 2009 the Company completed a registered direct offering of 6,500,000
shares of common stock at a price of $9.12 per share for total gross proceeds of
$59,280,000. The Company incurred costs of $2,972,027 related to the
offering. These costs were netted against the proceeds of the
offering through Additional Paid-in Capital.
In
November and December 2009, the issued 79,005 shares of common stock related to
the purchase of leasehold interests in North Dakota. The fair value of the stock
was $890,859, the market value of the Common Stock on the date the leasehold
interests were acquired.
In
November 2009, the Company issued 50,000 shares of Common Stock to two employees
of the company as compensation for their services. The employees were
fully vested in the shares on the date of the grant. The fair value
of the stock issued was $457,500 or $9.15 per share, the market value of a share
of common stock on the date the stock was issued. The entire amount
of this stock award was expensed in the year ended December 31,
2009.
In
December 2009, the Company issued 100,000 shares of Common Stock to two
executives of the company as compensation for their services. The
executives were fully vested in the shares on the date of the
grant. The fair value of the stock issued was $970,000 or $9.70 per
share, the market value of a share of common stock on the date the stock was
issued. The entire amount of this stock award was expensed in the
year ended December 31, 2009.
In
December 2009, the Company issued 41,670 shares of Common Stock to the Company’s
outside Directors as compensation for their services. The Directors
were fully vested in the shares on the date of the grant. The fair
value of the stock issued was $404,199 or $9.70 per share, the market value of a
share of common stock on the date the stock was issued. The entire
amount of this stock award was expensed in the year ended December 31,
2009.
In
December 2009, a Director of the Company exercised 100,000 stock options granted
to him in 2007. The exercise of these options was completed through a
cashless exercise whereas the company repurchased 52,061 of common shares to
issue the common shares related to this option exercise.
Restricted Stock
Awards
During
the years ended December 31, 2009 and 2008, The Company issued 361,330 and
20,000, respectively, restricted shares of common stock as compensation to
officers, employees, and directors of the Company. The restricted shares vest
over various terms with all restricted shares vesting no later than December 31,
2011. As of December 31, 2009, there was approximately $2.9 million of
total unrecognized compensation expense related to unvested restricted stock.
This compensation expense will be recognized over the remaining vesting period
of the grants. The Company has assumed a zero percent forfeiture rate for
restricted stock.
F-18
The
following table reflects the outstanding restricted stock awards and activity
related thereto for the years ended December 31:
|
Year
Ended
|
Year
Ended
|
|||||||||||||||
|
December
31, 2009
|
December
31, 2008
|
|||||||||||||||
|
Weighted-
|
Weighted-
|
|||||||||||||||
|
Number
of
|
Average
|
Number
of
|
Average
|
|||||||||||||
|
Shares
|
Price
|
Shares
|
Price
|
|||||||||||||
|
Restricted
Stock Awards:
|
||||||||||||||||
|
Restricted
Shares Outstanding at the
Beginning
of the Year
|
20,000 | $ | 7.03 | - | $ | - | ||||||||||
|
Shares
Granted
|
361,330 | $ | 8.49 | 20,000 | $ | 7.03 | ||||||||||
|
Lapse
of Restrictions
|
(56,000 | ) | $ | 4.91 | - | $ | - | |||||||||
|
Restricted
Shares Outstanding at the End of the Year
|
325,330 | $ | 9.01 | 20,000 | $ | 7.03 | ||||||||||
The
Company has purchased leasehold interests from South Fork Exploration, LLC
(SFE). In 2009, the company paid a total of $501,603 related to a
previously executed leasehold agreement. SFE’s president is J.R.
Reger, the brother of the Company’s CEO, Michael Reger. J.R. Reger is
also a shareholder in the Company.
The
Company has also purchased leasehold interests from MOP. MOP is
controlled by Mr. Tom Ryan and Mr. Steven Reger, both are relatives of the
Company’s CEO, Michael Reger.
The
Company has also purchased leasehold interests from Gallatin Resources,
LLC. Carter Stewart, one of the Company’s directors, owns a 25%
interest in Gallatin Resources, LLC.
All
transactions involving related parties were approved by the Company’s Board of
Directors or Audit Committee.
The
Company’s Board of Directors approved a stock option plan in October 2006 (“2006
Stock Option Plan”) to provide incentives to employees, directors, officers, and
consultants and under which 2,000,000 shares of common stock have been reserved
for issuance. The options can be either incentive stock options or
non-statutory stock options and are valued at the fair market value of the stock
on the date of grant. The exercise price of incentive stock options
may not be less than 100% of the fair market value of the stock subject to the
option on the date of the grant and, in some cases, may not be less than 110% of
such fair market value. The exercise price of non-statutory options
may not be less than 100% of the fair market value of the stock on the date of
grant.
On
November 1, 2007 the Board of Directors granted 560,000 of options under this
2006 Stock Option Plan. The Company granted 500,000 options in
aggregate, to members of the board and 60,000 options to one employee pursuant
to an employment agreement. These options were granted at a price of
$5.18 per share and the optionees were fully vested on the grant
date. 260,000 options granted in 2007 have been exercised as of
December 31, 2009.
The
Company accounts for stock-based compensation under the provisions of FASB ASC
718-10-55 (
Prior authoritative
literature:
FASB Statement 123(R),
Share-Based
Payment).
This statement requires us to record an expense
associated with the fair value of stock-based compensation. We use
the Black-Scholes option valuation model to calculate stock-based compensation
at the date of grant. Option pricing models require the input of
highly subjective assumptions, including the expected price
volatility. Changes in these assumptions can materially affect the
fair value estimate. The total fair value of the options are
recognized as compensation over the vesting period. There have been
no stock options granted in 2009 and 2008 under the 2006 Stock Option Plan, and
all exercises of options during 2009 and 2008 related to 2007 grants.
F-19
Options
Granted November 1, 2007
On
November 1, 2007, the Board of Directors granted 560,000 options to board
members and one employee. The total fair value of the options was
recognized as compensation in 2007 as the optionees were immediately
vested. In computing the expected volatility, we used the combined
historical volatility of the Company’s common stock for a one-month period and
the blended historical volatility for two of our peer companies over a period of
four years and eleven months. In computing the exercise price we used
the average closing/last trade price of the Company’s common stock for the five
highest volume trading days during the 30-day trading period ending on the last
trading day preceding the date of the grants.
The
following assumptions were used for the Black-Scholes model:
|
November
1,
|
||||
|
2007
|
||||
|
Risk
free rates
|
4.36 | % | ||
|
Dividend
yield
|
0 | % | ||
|
Expected
volatility
|
56 | % | ||
|
Weighted
average expected stock option life
|
5
Years
|
|||
The “fair
market value” at the date of grant for stock options granted using the formula
relied upon for calculating the exercise price is as follows:
|
$
|
2.72
|
|||
|
Total
options granted
|
560,000
|
|||
|
Total
weighted average fair value of options granted
|
$
|
1,524,992
|
The
following table presents the impact on our statement of operations of
stock-based compensation expense related to options granted for the years ended
December 31, 2009, 2008, and 2007:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Expenses
|
$ | - | $ | - | $ | 2,366,417 | ||||||
|
Option
Stock-Based Compensation Expense Before Taxes
|
- | - | 2,366,417 | |||||||||
|
Income
Tax Benefit
|
- | - | - | |||||||||
|
Option
Stock-Based Compensation Expense After Taxes
|
$ | - | $ | - | $ | 2,366,417 | ||||||
F-20
Changes
in stock options for the years ended December 31, 2009, 2008, and 2007 were as
follows:
|
Number
of
Shares
|
Weighted
Average Exercise Price
|
Remaining
Contractual Term
(in
Years)
|
Intrinsic
Value
|
|||||||||||||
|
2007:
|
||||||||||||||||
|
Beginning
Balance
|
1,100,000 | $ | - | - | - | |||||||||||
|
Granted
|
560,000 | 5.18 | - | - | ||||||||||||
|
Exercised
|
1,000,000 | 1.05 | - | - | ||||||||||||
|
Outstanding
at December 31
|
660,000 | 4.55 | 9.7 | 1,581,200 | ||||||||||||
|
Exercisable
|
660,000 | 4.55 | 9.7 | 1,581,200 | ||||||||||||
|
Ending
Vested
|
660,000 | 4.55 | 1,581,200 | |||||||||||||
|
Weighted
Average Fair Value of Options Granted During Year
|
$ | 2.72 | ||||||||||||||
|
2008:
|
||||||||||||||||
|
Beginning
Balance
|
660,000 | $ | - | - | - | |||||||||||
|
Granted
|
- | - | - | - | ||||||||||||
|
Exercised
|
260,000 | 3.59 | - | - | ||||||||||||
|
Outstanding
at December 31
|
400,000 | 5.18 | 8.8 | - | ||||||||||||
|
Exercisable
|
400,000 | 5.18 | 8.8 | - | ||||||||||||
|
Ending
Vested
|
400,000 | 5.18 | 8.8 | - | ||||||||||||
|
Weighted
Average Fair Value of Options Granted During Year
|
$ | - | ||||||||||||||
|
2009:
|
||||||||||||||||
|
Beginning
Balance
|
400,000 | $ | - | - | - | |||||||||||
|
Granted
|
- | - | - | - | ||||||||||||
|
Exercised
|
100,000 | 5.18 | - | - | ||||||||||||
|
Outstanding
at December 31
|
300,000 | 5.18 | 7.8 | 1,998,000 | ||||||||||||
|
Exercisable
|
300,000 | 5.18 | 7.8 | 1,998,000 | ||||||||||||
|
Ending
Vested
|
300,000 | 5.18 | 7.8 | 1,998,000 | ||||||||||||
|
Weighted
Average Fair Value of Options Granted During Year
|
$ | - | ||||||||||||||
Currently
Outstanding Options
|
·
|
No
options were forfeited or expired during the years ended December 31,
2009, 2008, and 2007.
|
|
·
|
The
company recorded compensation expense related to these options of
$2,366,417 for the year ended December 31, 2007. There is no
further compensation expense that will be recognized in future years,
relating to all options that have been granted as of December 31, 2009,
since the entire fair value compensation has been recognized based on the
vesting period of the options during 2006 and 2007.
|
|
·
|
There
were no unvested options at December 31, 2009, 2008, and
2007.
|
F-21
Warrants
Granted February 2009
On
February 27, 2009, in conjunction with the closing of the revolving
credit facility (see Note 9), the company issued CIT Capital USA, Inc.
(CIT) warrants to purchase a total of 300,000 shares of common stock
exercisable at $5.00 per share. The total fair value of the
warrants was calculated using the Black-Scholes valuation model based on factors
present at the time the warrants were issued. The fair value of the
warrants is included in Debt Issuance
Costs and are being amortized for
three years over the term of the facility using the effective interest
method. CIT can exercise the warrants at any time until the warrants
expire in February 2012.
The
following assumptions were used for the Black-Scholes model:
|
February
27,
|
||||
|
2009
|
||||
|
Risk
free rates
|
1 | % | ||
|
Dividend
yield
|
0 | % | ||
|
Expected
volatility
|
96.43 | % | ||
|
Weighted
average expected warrant life
|
1.5
Years
|
|||
The “fair
market value” at the date of issuance for the warrants issued using the formula
relied upon for calculating the fair value of warrants is as
follows:
|
Weighted
average fair value per share
|
$
|
.74
|
||
|
Total
options granted
|
300,000
|
|||
|
Total
weighted average fair value of options granted
|
$
|
221,153
|
In
January 2009, the Company’s Board of Directors adopted the 2009 Equity Incentive
Plan, pursuant to which we may issue up to 3,000,000 shares of our common stock
either upon exercise of stock options granted under such plan or through
restricted stock awards under such plan. As of December 31, 2009, we had
issued 642,916 shares of common stock pursuant to our 2009 Equity Incentive Plan
(See Note 6).
The table
below reflects the status of warrants outstanding at December 31,
2009:
|
Common
|
Exercise
|
Expiration
|
|||||||
|
Issue
Date
|
Shares
|
Price
|
Date
|
||||||
|
February
27, 2009
|
300,000
|
$
|
5.00
|
February
27, 2012
|
|||||
At
December 31, 2009 the per-share weighted average exercise price of
outstanding warrants was $5.00 per share, and the weighted average remaining
contractual life was 2.2 years. None of the warrants issued in
2009 were exercised and all of the warrants are exercisable at December 31,
2009.
In
February 2009, the Company completed the closing of a revolving credit facility
with CIT Capital USA Inc. (“CIT”) that will provide up to a maximum principal
amount of $25 million of working capital for exploration and production
operations (the “Facility”). The borrowing base of funds available
under the Facility will be redetermined semi-annually based upon the net present
value, discounted at 10% per annum, of the future net revenues expected to
accrue from its interests in proved reserves estimated to be produced from its
oil and gas properties. $11 million of financing was initially
available under the Facility. In May 2009 CIT agreed to increase the
current amount available under the Facility to $16 million in conjunction with
the acquisition of certain assets of Windsor Bakken, LLC (see Note
5). An additional $9 million of financing could become available upon
subsequent borrowing base redeterminations. The Facility terminates
on February 27, 2012, with all outstanding borrowings due at that
time. The Company had no borrowings under the facility at December
31, 2009.
The
Company has the option to designate the reference rate of interest for each
specific borrowing under the Facility as amounts are
advanced. Borrowings based upon the London interbank offering rate
(LIBOR) will be outstanding for a period of one, three or six months (as
designated by us) and bear interest at a rate equal to 5.50% over the one-month,
three-month or six-month LIBOR rate to be no less than 2.50%. Any
borrowings not designated as being based upon LIBOR will have no specified term
and generally will bear interest at a rate equal to 4.50% over the greater of
(a) the current three-month LIBOR rate plus 1.0% or (b) the current prime rate
as published by JP Morgan Chase Bank, N.A. The Company has the option
to designate either pricing mechanism. Payments are due under the
Facility in arrears, in the case of a loan based on LIBOR on the last day of the
specified loan period and in the case of all other loans on the last day of each
March, June, September and December. All outstanding principal is due
and payable upon termination of the Facility.
F-22
The
applicable interest rate increases under the Facility and the lenders may
accelerate payments under the Facility, or call all obligations due under
certain circumstances, upon an event of default. The Facility
references various
events constituting a default on the Facility,
including, but not limited to, failure to pay interest on any loan under the
Facility, any material violation of any representation or warranty under the
Credit Agreement in connection with the Facility, failure to observe or perform
certain covenants, conditions or agreements under the Facility, a change in
control of the Company, default under any other material indebtedness the
Company might have, bankruptcy and similar proceedings and failure to pay
disbursements from lines of credit issued under the Facility. The
Company was not in default on the Facility as of December 31, 2009, and is not
expected to be in default in the future.
The
Facility required that the Company enter into swap agreements with Macquarie
Bank Limited (“Macquarie”) for each month of the thirty-six (36) month period
following the date on which each such swap agreement is executed, the notional
volumes for which (when aggregated with other commodity swap agreements and
additional fixed-price physical off-take contracts then in effect other than
basis differential swaps on volumes already hedged pursuant to other swap
agreements), as of the date such swap agreement is executed, is not less than
50% of, nor exceeds 80% of, the reasonably anticipated projected production from
the Company’s proved developed producing reserves. The hedged
production is estimated to be equal to approximately 20% of 2009 total
production and less than 10% of production volumes in 2010-12. See
Note 15 for additional disclosure concerning these swap agreements.
All of
the Company’s obligations under the Facility and the swap agreements with
Macquarie are secured by a first priority security interest in any and all
assets of the Company pursuant to the terms of a Guaranty and Collateral
Agreement and perfected by a mortgage, notice of pledge and security and similar
documents.
The
Company has asset retirement obligations associated with the future plugging and
abandonment of proved properties and related facilities. Under the
provisions of FASB ASC 410-20-25 (
Prior authoritative literature:
FASB Statement 143,
Accounting for Asset Retirement
Obligations)
, the fair value of a liability for an asset retirement
obligation is recorded in the period in which it is incurred and a corresponding
increase in the carrying amount of the related long lived asset. The
liability is accreted to its present value each period, and the capitalized
cost is depreciated over the useful life
of the related asset. If the liability is settled for an amount other
than the recorded amount, a gain or loss is recognized. The Company
has no assets that are legally restricted for purposes of settling asset
retirement obligations.
The
following table summarizes the company's asset retirement obligation
transactions recorded in accordance with the provisions of FASB ASC 410-20-25
during the year ended December 31, 2009 and 2008.
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
| $ | 61,437 | $ | -0- | |||||
|
Liabilities
Incurred for New Wells Placed in Production
|
137,222 | 60,407 | ||||||
|
Accretion
of Discount on Asset Retirement Obligations
|
8,082 | 1,030 | ||||||
|
Ending
Asset Retirement Obligation
|
$ | 206,741 | 61,437 | |||||
The
Company utilizes the asset and liability approach to measuring deferred tax
assets and liabilities based on temporary differences existing at each balance
sheet date using currently enacted tax rates in accordance with FASB ASC
740-10-30 (
Prior authoritative
literature:
FASB Statement 109,
Accounting for Income Taxes).
Deferred tax assets are reduced by a valuation allowance when, in the
opinion of management, it is more likely than not that some portion or all of
the deferred tax assets will not be realized. Deferred tax assets and
liabilities are adjusted for the effects of changes in tax laws and rates on the
date of enactment.
F-23
The income tax expense (benefit)
for the year ended December 31, 2009, 2008, and 2007 consists of the
following:
|
2009
|
2008
Adjusted
|
2007
|
||||||||||
|
Current
Income Taxes
|
$ | - | $ | - | $ | - | ||||||
|
Deferred
Income Taxes
|
||||||||||||
|
Federal
|
1,215,000 | (680,000 | ) | - | ||||||||
|
State
|
251,000 | (150,000 | ) | - | ||||||||
|
Total
Expense
|
$ | 1,466,000 | $ | (830,000 | ) | $ | - | |||||
The
following is a reconciliation of the reported amount of income tax expense
(benefit) for the years ended December 31, 2009, 2008, and 2007 to the amount of
income tax expenses that would result from applying the statutory rate to pretax
income.
Reconciliation
of reported amount of income tax expense:
|
2009
|
2008
Adjusted
|
2007
|
||||||||||
|
Income
(Loss) Before Tau8xes and NOL
|
$ | 4,264,952 | $ | 1,594,340 | $ | (4,305,293 | ) | |||||
|
Federal
Statutory Rate
|
X 34 | % | x 34 | % | x 34 | % | ||||||
|
Taxes
(Benefit) Computed at Federal Statutory Rates
|
1,450,000 | 540,000 | (1,460,000 | ) | ||||||||
|
State
Taxes (Benefit), Net of Federal Taxes
|
295,000 | 110,000 | - | |||||||||
|
Effects
of:
|
||||||||||||
|
Other
|
(279,000 | ) | (7,659 | ) | (12,341 | ) | ||||||
|
Change
in Valuation
|
- | (1,472,341 | ) | 1,472,341 | ||||||||
|
Reported
Provision
|
$ | 1,466,000 | $ | (830,000 | ) | $ | - | |||||
At
December 31, 2009, 2008 and 2007, the Company has a net operating loss
carryforward for Federal income tax purposes of $18,494,000, $9,348,000 and
$1,950,000, respectively, which expires in varying amounts during the tax years
2027, 2028 and 2029.
The
components of the Company’s deferred tax asset were as follows:
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
Adjusted
|
|||||||
|
Deferred
Tax Assets
|
||||||||
|
Current:
|
||||||||
|
Share
Based Compensation (Options)
|
$ | 774,000 | $ | 774,000 | ||||
|
Share
Based Compensation (Restricted Stock)
|
(91,000 | ) | - | |||||
|
Unrealized
Investment Losses
|
1,231,000 | 168,000 | ||||||
|
Accrued
Payroll
|
288,000 | 520,000 | ||||||
|
Other
|
(145,000 | ) | (72,000 | ) | ||||
|
Current
|
2,057,000 | 1,390,000 | ||||||
|
Non-Current:
|
||||||||
|
Net
Operating Loss Carryforwards (NOLs)
|
7,583,000 | 3,588,000 | ||||||
|
Fixed
Assets
|
(2,646,000 | ) | (931,000 | ) | ||||
|
Dry
Well Write Off
|
(36,000 | ) | (36,000 | ) | ||||
|
Unrealized
Investment Losses
|
395,000 | |||||||
|
Depletion
|
1,562,000 | 214,000 | ||||||
|
Intangible
Drilling Costs
|
(7,955,000 | ) | (2,962,000 | ) | ||||
|
Sale
of Land Lease Rights
|
117,000 | 117,000 | ||||||
|
Other
|
58,000 | 43,000 | ||||||
|
Non-Current
|
(922,000 | ) | 33,000 | |||||
|
Total
Deferred Tax Assets
|
1,135,000 | 1,423,000 | ||||||
|
Less:
Valuation Allowance
|
- | - | ||||||
|
Net
Deferred Tax Asset
|
$ | 1,135,000 | $ | 1,423,000 | ||||
In June
2006, FASB issued FASB ASC 740-10-05-6 (
Prior authoritative literature:
FASB Statement 48,
Accounting for Uncertainty in Income
Taxes)
. We adopted FASB ASC 740-10-05-6 on January 1,
2007. Under FASB ASC 740-10-05-6, tax benefits are recognized only
for tax positions that are more likely than not to be sustained upon examination
by tax authorities. The amount recognized is measured as the largest
amount of benefit that is greater than 50 percent likely to be realized upon
ultimate settlement. Unrecognized tax benefits are tax benefits
claimed in our tax returns that do not meet these recognition and measurement
standards.
Upon the
adoption of FASB ASC 740-10-05-6, we had no liabilities for unrecognized tax
benefits and, as such, the adoption had no impact on our financial statements,
and we have recorded no additional interest or penalties. The
adoption of FASB ASC 740-10-05-6
did not impact our
effective tax rates.
Our
policy is to recognize potential interest and penalties accrued related to
unrecognized tax benefits within income tax expense. For the year
ended December 31, 2009, we did not recognize any interest or penalties in our
Statement of Operations, nor did we have any interest or penalties accrued in
our Balance Sheet at December 31, 2009 relating to unrecognized
benefits.
The tax
years 2008, 2007 and 2006 remain open to examination for federal income tax
purposes and by the other major taxing jurisdictions to which we are
subject.
F-24
Vehicles
The
Company leases vehicles under noncancelable operating leases. Total
rent expense under the agreements was approximately $52,000, $31,000 and $22,000
for the years ended December 31, 2009, 2008, and 2007,
respectively.
Minimum
future lease payments under these vehicle leases are as follows:
|
Year
Ending
December
31,
|
Amount
|
|||
|
2010
|
$ | 41,372 | ||
|
2011
|
19,744 | |||
|
Total
|
$ | 61,116 | ||
Building
Effective
February 2008, the Company entered into an operating lease agreement to lease
3,044 square feet of office space. The lease requires initial gross
monthly lease payments of $11,415. The monthly payments increase by
4%
on each
anniversary date. The lease expires in December
2012. Total rent expense under the agreement was approximately
$142,000 and $114,000 for the years ended December 31, 2009 and 2008,
respectively.
The
Company has prepaid $34,245, the last three months rent. Minimum
future lease payments under the building lease are as follows:
The
Company received $91,320 of landlord incentives under the lease
agreement. The Company has recorded a deferred rent liability for
this amount that is being amortized over the term of the lease.
Prior to
this lease the Company was paying $1,250 on a month-to-month lease.
FASB ASC
820-10-55 (
Prior authoritative
literature:
FASB Statement 157,
Fair Value Measurements)
defines fair value, establishes a framework for measuring fair value
under generally accepted accounting principles and enhances disclosures about
fair value measurements. Fair value is defined under FASB ASC
820-10-55 as the exchange price that would be received for an asset or paid to
transfer a liability (an exit price) in the principal or most advantageous
market for the asset or liability in an orderly transaction between market
participants on the measurement date. Valuation techniques used to
measure fair value under FASB ASC 820-10-55 must maximize the use of observable
inputs and minimize the use of unobservable inputs. The standard
describes a fair value hierarchy based on three levels of inputs, of which the
first two are considered observable and the last unobservable, that may be used
to measure fair value which are the following:
Level 1 -
Quoted prices in active markets for identical assets or
liabilities.
Level 2 -
Inputs other than Level 1 that are observable, either directly or indirectly,
such as quoted prices for similar assets of liabilities; quoted prices in
markets that are not active; or other inputs that are observable or can be
corroborated by observable market data for substantially the full term of the
assets or liabilities.
Level 3 -
Unobservable inputs that are supported by little or no market activity and that
are significant to the fair value of the assets or liabilities.
The
following schedule summarizes the valuation of financial instruments measured at
fair value on a recurring basis in the balance sheet as of December 31, 2009 and
2008.
|
Fair
Value Measurements at December 31, 2009 Using
|
||||||||||||
|
Quoted
Prices In Active Markets for Identical Assets
(Level
1)
|
Significant
Other Observable Inputs
(Level
2)
|
Significant
Unobservable Inputs
(Level
3)
|
||||||||||
|
Current
Derivative Liabilities
|
$ | - | $ | (1,320,679 | ) | $ | - | |||||
|
Non-Current
Derivative Liabilities
|
- | (1,459,374 | ) | - | ||||||||
|
Short-Term
Investments (See Note 3)
|
23,085,120 | - | 1,818,356 | |||||||||
|
Total
|
$ | 23,085,120 | $ | (2,780,053 | ) | $ | 1,818,356 | |||||
F-25
|
Fair
Value Measurements at December 31, 2008 Using
|
||||||||||||
|
Quoted
Prices In Active Markets for Identical Assets
(Level
1)
|
Significant
Other Observable Inputs
(Level
2)
|
Significant
Unobservable Inputs
(Level
3)
|
||||||||||
|
Long-Term
Investments (See Note 3)
|
$ | - | $ | - | $ | 2,416,369 | ||||||
|
Total
|
$ | - | $ | - | $ | 2,416,369 | ||||||
Level 1
assets consist of US Treasury Notes, the fair value of these treasuries is based
on quoted market prices.
Level 2
liabilities consist of derivative liabilities (see Note 15). Under
FASB ASC 820-10-55 (
Prior
authoritative literature:
FASB Statement 157,
Fair Value Measurements)
, the
fair value of the Company's derivative financial instruments is determined based
on the Company’s valuation models that utilize market corroborated
inputs. The fair value of all derivative contracts is reflected on
the balance sheet. The current liability amounts represent the fair
values expected to be included in the results of operations for the subsequent
year.
Level 3
assets consist of municipal bonds and floating rate preferred stock (see Note 3)
with an auction reset feature (“auction rate securities” or ARS). The
underlying assets for the municipal bonds are student loans which are
substantially backed by the federal government. Auction-rate
securities are long-term floating rate bonds or floating rate perpetual
preferred stock tied to short-term interest rates. After the initial
issuance of the securities, the interest rate on the securities is reset
periodically, at intervals established at the time of issuance (primarily every
twenty-eight days), based on market demand for a reset
period. Auction-rate securities are bought and sold in the
marketplace through a competitive bidding process often referred to as a “Dutch
auction”. If there is insufficient interest in the securities at the
time of an auction, the auction may not be completed and the rates may be reset
to predetermined “penalty” or “maximum” rates based on mathematical formulas in
accordance with each security's prospectus.
In
February 2008, auctions began to fail for these securities and each auction
since then has failed. Consequently, the investments are not
currently liquid. In the event the Company needed to access these
funds, they are not expected to be accessible until one of the following occurs:
a successful auction occurs, the issuer redeems the issue, a buyer is found
outside of the auction process or the underlying securities
mature. In October 2008, the Company received an offer (the “Offer”)
from UBS AG (“UBS”), one of its investment providers, to sell at par value
auction-rate securities originally purchased from UBS ($2,025,143) at anytime
during a two-year period beginning June 30, 2010. The Offer was
non-transferable and expired on November 14, 2008. On October 28, 2008 the
Company elected to participate in the Offer. The Company has
classified auction rate securities as short-term assets on our balance
sheet. In addition to the Offer, UBS is providing no net cost loans
up to 75% of the loan-to-market value of eligible auction rate securities until
June 30, 2010.
Typically,
the fair value of ARS investments approximates par value due to the frequent
resets through the auction process. While the Company continues to
earn interest on its ARS investments at the contractual rate, these investments
are not currently trading and therefore do not have a readily determinable
market value. Accordingly, the estimated fair value of the ARS no
longer approximates par value. At December 31, 2009, the Company
valued the ARS investments based on Level 3 inputs. The Company
utilized a discounted cash flow approach to arrive at this valuation. The
assumptions used in preparing the discounted cash flow model include estimates
of, based on data available as of December 31, 2009, interest rates, timing and
amount of cash flows, credit and liquidity premiums, and expected holding
periods of the ARS. These assumptions are volatile and subject to
change as the underlying sources of these assumptions and market conditions
change. Based on this Level 3 valuation, the Company valued the ARS
investments at $1,818,356, which represents a decline in value of $206,787 from
par.
F-26
Although
there is uncertainty with regard to the short-term liquidity of these
securities, the Company continues to believe that the carrying value represents
the fair value of these marketable securities because of the overall quality of
the underlying investments and the anticipated future market for such
investments. In addition, the Company has the intent and ability to hold
these securities until the earlier of: the market for auction rate securities
stabilizes, the issuer refinances the underlying security, a buyer is found
outside of the auction process at acceptable terms, the underlying securities
have matured or the Company accepts the investment manager’s offer to redeem the
securities.
Based on the CIT
financing, the expected positive operating cash flows, and the Company’s ability
to obtain no net cost loans up to 75% of the loan-to-market value, as determined
by UBS, on eligible auction rate securities, the Company does not anticipate the
current inability to liquidate the auction rate securities to adversely affect
the Company’s ability to conduct its business.
The
following table provides a reconciliation of the beginning and ending balances
for the assets measured at fair value using significant unobservable inputs
(Level 3):
|
Fair Value Measurements at Reporting
Date Using Significant Unobservable Inputs (Level 3)
Level
3 Financial Assets
|
||||
|
Balance
at January 1, 2008
|
$ | - | ||
|
Purchases
|
3,800,524 | |||
|
Sales/Maturities
|
(975,000 | ) | ||
|
Realized
Loss on Sales/Maturities
|
(381 | ) | ||
|
Unrealized
Loss Included in Other Comprehensive Income (Loss)
|
(408,774 | ) | ||
|
Balance
at December 31, 2008
|
$ | 2,416,369 | ||
|
Sales
|
(800,000 | ) | ||
|
Unrealized
Gain Included in Other Comprehensive Income (Loss)
|
201,987 | |||
|
Balance
at December 31, 2009
|
$ | 1,818,356 | ||
The
Company’s assessment of the significance of a particular input to the fair value
measurement requires judgment and may effect the valuation of the nonfinancial
assets and liabilities and their placement in the fair value hierarchy levels.
The fair value of the Company’s asset retirement obligations are determined
using discounted cash flow methodologies based on inputs that are not readily
available in public markets. The fair value of the asset retirement obligations
is reflected on the balance sheet as follows.
|
Fair
Value Measurements at December 31, 2009 Using
|
||||||||||||||||
|
Description
|
December
31, 2009
|
Quoted
Prices In Active Markets for Identical Assets
(Level
1)
|
Significant
Other Observable Inputs
(Level
2)
|
Significant
Unobservable Inputs
(Level
3)
|
||||||||||||
|
Other
Non-current Liabilities
|
$ | (206,741 | ) | $ | - | $ | - | $ | (206,741 | ) | ||||||
|
Total
|
$ | (206,741 | ) | $ | - | $ | - | $ | (206,741 | ) | ||||||
F-27
|
Fair
Value Measurements at December 31, 2008 Using
|
||||||||||||||||
|
Description
|
December
31, 2008
|
Quoted
Prices In Active Markets for Identical Assets
(Level
1)
|
Significant
Other Observable Inputs
(Level
2)
|
Significant
Unobservable Inputs
(Level
3)
|
||||||||||||
|
Other
Non-current Liabilities
|
$ | (61,437 | ) | $ | - | $ | - | $ | (61,437 | ) | ||||||
|
Total
|
$ | (61,437 | ) | $ | - | $ | - | $ | (61,437 | ) | ||||||
See Note
10 for a rollforward of the Asset Retirement Obligation.
The
Company’s non-derivative financial instruments include cash and cash
equivalents, accounts receivable, accounts payable and line of credit. The
carrying amount of cash and cash equivalents, accounts receivable, accounts
payable, and line of credit approximate fair value because of their immediate or
short-term maturities.
The
Company’s accounts receivable relate to oil and natural gas sold to various
industry companies. Credit terms, typical of industry standards, are
of a short-term nature and the Company does not require
collateral. The Company’s accounts receivable at December 31,
2009 and 2008 do not represent significant credit risks as they are dispersed
across many counterparties.
The
Company utilizes commodity swap contracts to (i) reduce the effects of
volatility in price changes on the oil commodities it produces and sells, (ii)
reduce commodity price risk and (iii) provide a base level of cash flow in order
to assure it can execute at least a portion of its capital
spending.
Crude Oil Derivative
Contracts Cash-flow Hedges
Historically,
all derivative positions that qualified for hedge accounting were designated on
the date the Company entered into the contract as a hedge against the
variability in cash flows associated with the forecasted sale of future oil
production. The cash flow hedges were valued at the end of each period and
adjustments to the fair value of the contract prior to settlement were recorded
on the statement of stockholders’ equity as other comprehensive income. Upon
settlement, the gain (loss) on the cash flow hedge was recorded as an
increase or decrease in revenue on the statement of operations. The company
reports average oil and gas prices and revenues including the net results of
hedging activities.
On
November 1, 2009, due to the volatility of price differentials in the
Williston Basin, the Company de-designated all derivates that were previously
classified as cash flow hedges and, in addition, the Company has elected not to
designate any subsequent derivative contracts as cash flow hedges under FASB ASC
815-20-25 (
Prior authoritative
literature:
FASB Statement 133,
Accounting for Derivative
Instruments and Hedging Activities)
. Beginning on November 1, 2009, all
derivative positions are carried at their fair value on the balance sheet and
are marked-to-market at the end of each period. Any realized and unrealized
gains or losses are recorded as gain (loss) on derivatives, net, as an
increase or decrease in revenue on the statement of operations rather than as a
component of other comprehensive income or as other income
(expense).
F-28
The net
mark-to-market loss on the Company's remaining swaps that qualified for cash
flow hedge accounting at the date the decision was made to discontinue
hedge accounting totals $2,416,639 as of December 31,
2009. The
amount is in accumulated other comprehensive income
in stockholders' equity and will be amortized into revenues as the original
forecasted hedged oil production occurs in 2010 and 2011.
The
Company realized a hedging loss of $624,541 and a hedging gain of $778,885 for
the years ended December 31, 2009 and 2008, respectively.
The
following table reflects open commodity derivative contracts as of December 31,
2009, the associated volumes and the corresponding weighted average NYMEX
reference price.
|
Oil
(Barrels)
|
Fixed
Price
|
Weighted
Avg
NYMEX Reference
Price
|
||||||||||
|
Oil
Swaps
|
||||||||||||
|
01/01/10
– 02/29/12
|
63,000 | 51.25 | 83.99 | |||||||||
|
01/01/10
– 12/31/11
|
36,000 | 66.15 | 84.20 | |||||||||
|
01/01/10
- 12/31/11
|
132,000 | 82.60 | 83.68 | |||||||||
|
01/01/10
- 12/31/11
|
54,000 | 84.25 | 83.56 | |||||||||
At
December 31, 2009, the Company had derivative financial instruments under FASB
ASC 815-20-25 recorded on the consolidated balance sheet as set forth
below:
|
Type
of Contract
|
Balance
Sheet Location
|
Estimated
Fair
Value
|
|||
|
Derivatives
Designated as Hedging Instruments
|
|||||
|
Derivative
Liabilities:
|
|||||
|
Oil
Contracts
|
Other
Current Liabilities
|
$ | 1,320,679 | ||
|
Oil
Contracts
|
Other
Non-Current Liabilities
|
1,459,374 | |||
|
Total
Derivative Liabilities:
|
$ | 2,780,053 | |||
The
following is a reconciliation of the numerator and denominator used to calculate
basic earnings per share and diluted earnings per share for the years ended
December 31, 2009, 2008, and 2007:
|
2009
|
2008
|
2007
|
|||||||||||||||||
|
Net
Income
|
Shares
|
Per
Share
|
Net
Income
Adjusted
|
Shares
|
Per
Share
|
Net
Loss
|
Shares
|
Per
Share
|
|||||||||||
|
Basic
EPS
|
$2,798,952
|
36,705,267
|
$ 0.08
|
$ 2,424,340
|
31,920,747
|
$ 0.08
|
$ (4,305,293)
|
23,667,119
|
$(0.18)
|
||||||||||
|
Dilutive
effect of options
|
-
|
171,803
|
- |
-
|
732,805
|
- |
-
|
-
|
- | ||||||||||
|
Diluted
EPS
|
$2,798,952
|
36,877,070
|
$ 0.08
|
$ 2,424,340
|
32,653,552
|
$ 0.07
|
$
(4,305,293)
|
23,667,119
|
$(0.18)
|
||||||||||
For the
years ended December 31, 2009 and 2008, options and warrants to purchase 21,678
and 7,476 shares of common stock were not considered in calculating diluted
earnings per share because the exercise prices were greater than the average
market price of common shares during the year and, therefore, the effect would
be anti-dilutive.
As of
December 31, 2007, there were 600,000 potentially dilutive shares from stock
options that became exercisable during 2007. In addition, there were
4,818,183 warrants that were issued and outstanding. These warrants
were exercisable and represented potentially dilutive shares. As the
Company had a loss for the year ended December 31, 2007 the potentially dilutive
share were anti-dilutive and were not added into the earnings per share
calculation.
F-29
The
Company follows the provisions of FASB ASC 220-10-55 (
Prior authoritative literature:
FASB Statement 130,
Reporting Comprehensive
Income)
which establishes standards for reporting comprehensive
income. In addition to net income, comprehensive income includes all
changes in equity during a period, except those resulting from investments and
distributions to stockholders of the Company.
For the
periods indicated, comprehensive income (loss) consisted of the
following:
|
Year
Ended
|
||||||||||||
|
December
31,
|
||||||||||||
|
2009
|
2008
Adjusted
|
2007
|
||||||||||
|
Net
Income (Loss)
|
$ | 2,798,952 | $ | 2,424,340 | $ | (4,305,293 | ) | |||||
|
Unrealized
losses on Short-term Investments (net of tax of $290,000 and
$168,000 at December 31, 2009 and 2008)
|
(486,207 | ) | (240,774 | ) | - | |||||||
|
Net
unrealized losses on hedges (Net of tax of $933,000 at December 31,
2009)
|
(1,483,639 | ) | - | - | ||||||||
|
Other
Comprehensive income (loss) net
|
$ | 829,106 | $ | 2,183,566 | $ | (4,305,293 | ) | |||||
In 2009,
the Company adopted a defined contribution 401(k) plan for substantially all of
its employees. The plan provides for Company matching of employee contributions
to the plan, at the Company’s discretion. During 2009, the Company provided a
match contribution equal to 100% of an eligible employee’s deferral
contribution, up to 6% of the employee’s earnings up to $16,500. The Company
contributed approximately $66,400 to the 401(k) plan for the year ended
December 31, 2009.
In
February 2010, the Company entered into a commodity swap
contract. The oil swap contract is for 11,900 barrels of oil per
month for the months of March 2010 through December 2010 and 4,583 barrels of
oil per month in 2011. The price on the contract is fixed at $80.90
per barrel.
SUPPLEMENTAL
OIL AND GAS INFORMATION
(UNAUDITED)
Oil
and Natural Gas Exploration and Production Activities
Oil and
gas sales reflect the market prices of net production sold or transferred with
appropriate adjustments for royalties, net profits interest, and other
contractual provisions. Production expenses include lifting costs incurred to
operate and maintain productive wells and related equipment including such costs
as operating labor, repairs and maintenance, materials, supplies and fuel
consumed. Production taxes include production and severance taxes.
Depletion of oil and gas properties relates to capitalized costs incurred in
acquisition, exploration, and development activities. Results of operations do
not include interest expense and general corporate amounts. The
results of operations for the company's oil and gas production activities are
provided in the company's related statements of operations.
F-30
Costs
Incurred and Capitalized Costs
The costs
incurred in oil and gas acquisition, exploration and development activities
follow:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Costs
Incurred for the Year:
|
||||||||||||
|
Proved
Property Acquisition
|
$ | 30,800,883 | $ | 30,508,139 | $ | 3,231,694 | ||||||
| Unproved Property Acquisition | - | 4,169,773 | ||||||||||
|
Development
|
18,739,905 | 9,165,188 | 186,044 | |||||||||
|
Total
|
$ | 49,540,788 | $ | 39,673,327 | $ | 7,587,511 | ||||||
Excluded costs for
unevaluated properties are accumulated by year. Costs are reflected in the full
cost pool as the drilling costs are incurred or as costs are evaluated and
deemed impaired. The Company anticipates these excluded costs will be
included in the depletion computation over the next five years. The
Company is unable to predict the future impact on depletion rates. The following
is a summary of capitalized costs excluded from depletion at December 31,
2009 by year incurred.
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Property
Acquisition
|
$ | 17,478,196 | $ | 29,080,499 | $ | 5,147,236 | ||||||
|
Drilling
|
394,066 | 1,762,532 | - | |||||||||
|
Total
|
$ | 17,872,262 | $ | 30,843,031 | $ | 5,147,236 | ||||||
Oil
and Natural Gas Reserves and Related Financial Data
Information
with respect to the Company’s oil and gas producing activities is presented in
the following tables. Reserve quantities, as well as certain information
regarding future production and discounted cash flows, were determined by Ryder
Scott Company, independent petroleum consultants based on information provided
by the company.
Oil
and Natural Gas Reserve Data
The
following tables present the Company’s independent petroleum consultants’
estimates of its proved oil and gas reserves. The Company emphasizes that
reserves are approximations and are expected to change as additional information
becomes available. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
way, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and
judgment.
F-31
|
Natural
|
||||||||
|
Gas
|
Oil
|
|||||||
|
(MCF)
|
(BLS)
|
|||||||
|
Proved
Developed and Undeveloped Reserves at December 31,
2007
|
- | - | ||||||
|
Extensions,
Discoveries and Other Additions
|
220,420 | 778,545 | ||||||
|
Production
|
(3,969 | ) | (50,880 | ) | ||||
|
Proved
Developed and Undeveloped Reserves at December 31,
2008
|
216,451 | 727,665 | ||||||
|
Revisions
of Previous Estimates
|
(27,820 | ) | (93,819 | ) | ||||
|
Extensions,
Discoveries and Other Additions
|
1,619,597 | 5,456,261 | ||||||
|
Production
|
(47,305 | ) | (274,528 | ) | ||||
|
Proved
Developed and Undeveloped Reserves at December 31,
2009
|
1,760,923 | 5,815,579 | ||||||
|
Proved
Developed Reserves at December 31, 2008
|
216,451 | 727,665 | ||||||
|
Proved
Developed Reserves at December 31, 2009
|
727,237 | 2,247,718 | ||||||
Proved
reserves are estimated quantities of oil and gas, which geological and
engineering data indicate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating conditions.
Proved developed reserves are proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods. Proved undeveloped reserves are included for reserves for
which there is a high degree of confidence in their recoverability and they are
scheduled to be drilled within the next five years.
Standardized
Measure of Discounted Future Net Cash Inflows and Changes Therein
The
following table presents a standardized measure of discounted future net cash
flows relating to proved oil and gas reserves and the changes in standardized
measure of discounted future net cash flows relating proved oil and gas were
prepared in accordance with the provisions of ASC 932-235-555 (formerly SFAS
69). Future cash inflows were computed by applying average prices of oil and gas
for the last 12 months as of December 31, 2009 and current prices as of December
31, 2008 to estimated future production. Future production and development costs
were computed by estimating the expenditures to be incurred in developing and
producing the proved oil and gas reserves at the end of the year, based on
year-end costs and assuming continuation of existing economic
conditions. Future income tax expenses were calculated by applying
appropriate year-end tax rates to future pretax cash flows relating to proved
oil and gas reserves, less the tax basis of properties involved and tax credits
and loss carryforwards relating to oil and gas producing
activities. Future net cash flows are discounted at the rate of 10%
annually to derive the standardized measure of discounted future cash flows.
Actual future cash inflows may vary considerably, and the standardized measure
does not necessarily represent the fair value of the Company’s oil
and gas reserves.
F-32
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Future
Cash Inflows
|
$ | 315,142,688 | $ | 29,342,354 | ||||
|
Future
Production Costs
|
(105,982,773 | ) | (8,719,621 | ) | ||||
|
Future
Development Costs
|
(54,011,133 | ) | (1,321,948 | ) | ||||
|
Future
Income Tax Expense
|
(43,761,765 | ) | - | |||||
|
Future
Net Cash Inflows
|
111,387,017 | 19,300,785 | ||||||
|
10%
Annual Discount for Estimated Timing of Cash Flows
|
(43,580,456 | ) | (7,514,731 | ) | ||||
|
Standardized
Measure of Discounted Future Net Cash Flows
|
$ | 67,806,561 | $ | 11,786,054 | ||||
The
twelve month average prices for the year ended December 31, 2009 and year-end
spot prices at December 31, 2008 were adjusted to reflect applicable
transportation and quality differentials on a well-by-well basis to arrive at
realized sales prices used to estimate the Company’s reserves. The prices for
the Company’s reserve estimates were as follows:
|
Natural
Gas
|
Oil
|
|||||||
|
MCF
|
Bbl
|
|||||||
|
December 31,
2008 (Spot Price)
|
$ | 5.80 | $ | 38.60 | ||||
|
December 31,
2009 (Average)
|
$ | 3.93 | $ | 53.00 | ||||
Changes
in the future net cash inflows discounted at 10% per annum follow:
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Beginning
of Period
|
$ | 11,786,054 | $ | - | ||||
|
Sales
of Oil and Natural Gas Produced, Net of Production Costs
|
(13,116,475 | ) | (3,268,858 | ) | ||||
|
Extensions
and Discoveries
|
74,946,755 | 19,967,182 | ||||||
|
Previously
Estimated Development Cost Incurred During the Period
|
1,321,948 | - | ||||||
|
Net
Change of Prices and Production Costs
|
4,352,381 | (3,660,754 | ) | |||||
|
Change
in Future Development Costs
|
- | (1,251,516 | ) | |||||
|
Revisions
of Quantity and Timing Estimates
|
(1,650,626 | ) | - | |||||
|
Accretion
of Discount
|
1,178,605 | - | ||||||
|
Change
in Income Taxes
|
(20,005,322 | ) | - | |||||
|
Purchase
of Reserves in Place
|
9,579,951 | - | ||||||
|
Other
|
(586,710 | ) | - | |||||
|
End
of Period
|
$ | 67,806,561 | $ | 11,786,054 | ||||
F-33
Quarterly
data for the years ended December 31, 2009, 2008, and 2007 is as
follows:
|
Quarter
Ended
|
|||||||||||||||||||
|
March
31,
Adjusted**
|
June
30,
Adjusted**
|
September
30,
Adjusted**
|
December
31,
|
||||||||||||||||
|
2009:
|
|||||||||||||||||||
|
Revenue
|
$
|
658,268
|
$
|
2,275,084
|
$
|
4,855,972
|
$
|
6,432,175
|
|||||||||||
|
Expenses
|
1,047,614
|
1,437,445
|
|
2,530,315
|
5,077,164
|
||||||||||||||
|
Income
(Loss) from Operations
|
(389,346
|
)
|
837,639
|
|
|
2,325,657
|
|
1,355,011
|
|
||||||||||
|
Other
Income (Expense)
|
(43,527
|
)
|
(139,243
|
)
|
321,589
|
(2,828)
|
|||||||||||||
|
Income
Tax Provision (Benefit)
|
(174,000
|
)
|
280,000
|
1,059,000
|
301,000
|
||||||||||||||
|
Net
Income (Loss)
|
(258,873
|
)
|
418,396
|
|
|
1,588,246
|
|
1,051,183
|
|
||||||||||
|
Net
Income (Loss) Per Common Share - Basic
|
(0.01
|
)
|
0.01
|
|
|
0.04
|
|
0.03
|
|
||||||||||
|
Net
Income (Loss) Per Common Share - Diluted
|
(0.01
|
)
|
0.01
|
0.04
|
0.03
|
||||||||||||||
|
Quarter
Ended
|
|||||||||||||||||||
|
March
31,
Adjusted**
|
June
30,
Adjusted**
|
September
30,
Adjusted**
|
December
31,
Adjusted**
|
||||||||||||||||
|
2008:
|
|||||||||||||||||||
|
Revenue
|
$
|
287,029
|
$
|
764,528
|
$
|
1,362,655
|
$
|
1,907,667
|
|||||||||||
|
Expenses
|
570,575
|
548,849
|
600,213
|
1,391,793
|
|||||||||||||||
|
Income
(Loss) from Operations
|
(283,546
|
)
|
215,679
|
762,442
|
515,874
|
||||||||||||||
|
Other
Income
|
96,269
|
95,424
|
155,121
|
37,077
|
|||||||||||||||
|
Income
Tax Provision (Benefit)
|
-
|
-
|
-
|
(830,000
|
)
|
||||||||||||||
|
Net
Income (Loss)
|
(187,277
|
)
|
311,103
|
917,563
|
1,382,951
|
||||||||||||||
|
Net
Income (Loss) Per Common Share - Basic and Diluted
|
(0.01
|
)
|
0.01
|
0.03
|
0.03
|
||||||||||||||
|
Quarter
Ended
|
|||||||||||||||||||
|
March
31,
|
June
30,
|
September
30,
|
December
31,
|
||||||||||||||||
|
2007:
|
|||||||||||||||||||
|
Revenue
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
|||||||||||
|
Expenses
|
297,719
|
894,720
|
*
|
309,487
|
3,011,263
|
||||||||||||||
|
Loss
from Operations
|
(297,719
|
)
|
(894,720
|
)
|
*
|
(309,487
|
)
|
(3,011,263
|
)
|
||||||||||
|
Other
Income
|
10,133
|
13,660
|
42,189
|
141,914
|
|||||||||||||||
|
Income
Tax Expense
|
-
|
-
|
-
|
-
|
|||||||||||||||
|
Net
Loss
|
(287,586
|
)
|
(881,060
|
)
|
*
|
(267,298
|
)
|
(2,869,349
|
)
|
||||||||||
|
Net
Loss Per Common Share - Basic and Diluted
|
(0.01
|
)
|
(0.04
|
)
|
*
|
(0.01
|
)
|
(0.10
|
)
|
||||||||||
* The
second quarter 2007 financial statements were adjusted, from what was reported,
as the company rescinded stock it had previously issued to Ibis Consulting
Group, LLC.
** In
2009, the company changed its method of accounting for drilling
costs. As required by generally accepted accounting principles the
impact of the change in accounting has been applied retrospectively to all
periods presented.
F-34
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Un Resolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. ReservedPart IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accountant Fees and ServicesPart IVItem 15. Exhibits and Financial Statement SchedulesNote 1 Organization and Nature Of BusinessNote 2 Significant Accounting PoliciesNote 3 Short-term InvestmentsNote 4 Property and EquipmentNote 5 Oil and Gas PropertiesNote 6 Preferred and Common StockNote 7 Related Party TransactionsNote 8 Stock Options/stock-based Compensation and WarrantsNote 9 Revolving Credit FacilityNote 10 Asset Retirement ObligationNote 11 Income TaxesNote 12 Operating LeasesNote 13 Fair ValueNote 14 Financial InstrumentsNote 15 Derivative Instruments and Price Risk ManagementNote 16 Earnings Per ShareNote 17 Comprehensive IncomeNote 18 Employee Benefit PlansNote 19 Subsequent Events