UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year ended December 31, 2008
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number – 0-8041
GEORESOURCES, INC.
(Exact name of registrant as specified in its charter)
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Colorado
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84-0505444
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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110 Cypress Station Drive, Suite 220
Houston, Texas 77090-1629
(Address of principal executive offices) (Zip code)
(281) 537-9920
(Registrant’s telephone number, including area code)
Securities registered
pursuant to Section 12(b) of the Act:
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Title of each class
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Name of exchange on which registered
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Common Stock, Par Value $0.01 Per Share
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NASDAQ
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Indicated by check mark if the registrant is a
well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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Yes
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No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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Yes
x
No
Indicate by check
mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
x
No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will
not be contained, to the best of the 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.
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Indicated by check mark whether the registrant is a large accelerated file, an accelerated file, a
non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated file,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer
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Accelerated filer
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Non-accelerated filer
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Smaller reporting company
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x
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Indicated by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes
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No
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Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2008: $128,936,298
Number of shares of the registrant’s common stock outstanding at March 20, 2009: 16,241,717
DOCUMENTS INCORPORATED BY REFERENCE
None
TABLE OF CONTENTS
Forward-Looking Statements
This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act
of 1934, as amended. All statements other than statements of historical facts included in this report, including, without limitation, statements regarding our business strategy, plans, objectives, expectations, intent, and beliefs of management,
related to current or future operations are forward-looking statements. These statements are based on certain assumptions and analyses made by our management in light of its experience and its perception of historical trends, current conditions,
expected future developments and other factors it believes to be appropriate. The forward-looking statements included in this report are subject to a number of material risks and uncertainties. Forward-looking statements are not guarantees of future
performance and actual results; therefore, developments and business decisions may differ materially from those envisioned by the forward-looking statements.
Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: changes in production volumes; our assumptions about
oil and gas prices; operating costs and production; our ability to achieve growth in assets and revenues; worldwide supply and demand, which affect commodity prices for oil; the timing and extent of our success in discovering, acquiring, developing
and producing oil, and natural gas reserves; risks inherent in the operation of oil and natural gas wells; future production and development costs; the effect of existing and future laws, governmental regulations and the political and economic
climate of the United States; and conditions in the capital markets. See also “Risk Factors” in Item 1A of this report for factors that could cause results to differ materially from forward-looking statements.
Certain Definitions
Unless the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used in this Annual Report on Form 10-K refer to GeoResources, Inc., together with its
consolidated operating subsidiaries. When the context requires, we refer to these entities separately.
We have included
below the definitions for certain terms used in this Annual Report on Form 10-K:
After payout
— With respect to an oil or
natural gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered.
Bbl
— One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bbls/d or BOPD
— barrels per day.
Bcf
— Billion cubic feet.
Bcfe
— Billion cubic feet equivalent, determined using the ratio of six thousand cubic feet (Mcf) of natural gas to one Bbl of crude oil,
condensate or natural gas liquids.
Before payout
— With respect to an oil and natural gas interest in a property, refers to
the time period before which the costs to drill and equip a well have been recovered.
Behind-pipe reserves
— Those reserves
expected to be recovered from completion interval(s) not yet open but still behind casing in existing wells.
BOE
— Barrel of
oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.
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Carried interest
— A contractual arrangement, usually in a drilling project, whereby all or a
portion of the working interest cost participation of the project originator is paid for by another party in exchange for earning an interest in such project.
Completion
— The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Compression
— A force that tends to shorten or squeeze, decreasing volume or increasing pressure.
Crestal well
— A well at the top of a geological structure.
DD&A
— Depreciation, depletion and amortization.
Developed acreage
— The
number of acres which are allotted or assignable to producing wells or wells capable of production.
Development activities
—
Activities following exploration including the installation of facilities and the drilling and completion of wells for production purposes.
Development well
— A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well
— A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed the related oil and
natural gas operating expenses and taxes.
Exploitation
— The act of making oil and gas property more profitable, productive or
useful.
Exploratory well
— A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a
new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Farm-in or Farm-out
— An agreement whereunder the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty and/or reversionary interest in the lease. The interest received by the assignee is a
“farm-in” while the interest transferred by the assignor is a “farm-out.”
Field
— An area consisting of a
single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
GAAP
— Generally accepted accounting principles in the United States of America.
Gross
acres or gross wells
— The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal
drilling
— A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques that may, depending on horizon, result in increase production rates
and greater ultimate recoveries of hydrocarbons.
Injection well
— A well used to inject gas, water, or LPG under high pressure
into a producing formation to maintain sufficient pressure to produce the recoverable reserves.
LPG
— Liquefied petroleum gas.
MBbls
— One thousand barrels of crude oil or other liquid hydrocarbons.
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Mbtu
(Mmbtu)
— Used as a standard unit of measurement for natural gas and provides a
convenient basis for comparing the energy content of various grades of natural gas and other fuels. One cubic foot of natural gas produces approximately 1,000 BTUs, so 1,000 cubic feet of gas is comparable to 1 MBTU. MBTU is often express as MMBTU,
which is intended to represent a thousand BTUs.
Mcf
— One thousand cubic feet.
Mcf/d
— One thousand cubic feet per day.
Mcfe
— One thousand cubic feet equivalent determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content
of crude oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher for crude oil than natural gas on an energy equivalent basis although there have been periods in which they
have been lower or substantially lower.
MMcf
— One million cubic feet.
MMcf/d
— One million cubic feet per day.
MMcfe
— One million cubic feet equivalent per day.
Net acres or net wells
— The
sum of the fractional working interests owned in gross acres or gross wells.
NGL’s
— Natural gas liquids measured in
barrels.
NRI or Net Revenue Interests
— The share of production after satisfaction of all royalty, oil payments and other
non-operating interests.
Normally pressured reservoirs
— Reservoirs with a formation-fluid pressure equivalent to 0.465 PSI
per foot of depth from the surface. For example, if the formation pressure is 4,650 PSI at 10,000 feet, the pressure is considered to be normal.
Over-pressured reservoirs
— Reservoirs with a formation fluid pressure greater than 0.465 PSI per foot of depth from the surface.
Plant products
— Liquids generated by a plant facility; including propane, iso-butane, normal butane, pentane and ethane.
Plugging and abandonment or P&A
— Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations
of many states require plugging of abandoned wells.
Pre-tax PV10%
— The present value of estimated future revenues to be
generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission (“SEC”) guidelines, net of estimated lease operating expense, production taxes and future development costs, using price and
costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion and amortization, or Federal income taxes and
discounted using and annual discount rate of 10%. Pre-tax PV10% many be considered a non-GAAP financial measure as defined by the SEC.
Primary recovery
— The first stage of hydrocarbon production in which natural reservoir drives are used to recover hydrocarbons, although some form of artificial lift may be required to exploit declining reservoir drives.
Productive well
— A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds
from the sale of such production exceeds production expenses and taxes.
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Proved developed nonproducing reserves or PDNP
— Proved developed nonproducing reserves are
proved reserves that are either shut-in or are behind-pipe reserves.
Proved developed producing reserves or PDP
— Proved
developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.
Proved developed reserves
— Proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.
Proved reserves
— The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions.
Proved undeveloped location
— A site on which a
development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved
undeveloped reserves or PUD
— Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion
— The completion for production of an existing well bore in another formation from that in which the well has been previously
completed.
Reprocessing
— Refers to taking older seismic data and performing new mathematical techniques to refine subsurface
images or to provide additional ways of interpreting the subsurface environment.
Reservoir
— A porous and permeable
underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest
— An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of
costs of production.
SEC
— The Securities and Exchange Commission of the United States of America.
Secondary recovery
— The use of water-flooding or gas injection to maintain formation pressure during primary production and to reduce the
rate of decline of the original reservoir drive.
Shut-in reserves
— Those reserves expected to be recovered from completion
intervals that were open at the time of the reserve estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or pipelines were not yet installed.
Standardized Measure of Discounted Future Net Cash Flows
— Present value of proved reserves, as adjusted to give effect to estimated future
abandonment costs, net of estimated salvage value of related equipment, and estimated future income taxes.
3-D seismic
—
Advanced technology method of detecting accumulation of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as
they reflect back to the surface.
Undeveloped acreage
— Lease acreage on which wells have not been drilled or completed to a
point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Waterflooding
— The secondary recovery method in which water is forced down injection wells laid out in various patterns around the producing wells. The water injected displaces the oil and forces it to the producing wells.
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Working interest or WI
— The operating interest that gives the owner the right to drill,
produce and conduct operating activities on the property and share of production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development operations and all risks in connection
therewith.
Workover
— Operations on a producing well to restore or increase production.
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PART I
Overview
GeoResources, Inc. (the “Company,” “we” or “us”), a Colorado corporation, is an independent oil and gas
company engaged in the acquisition and development of oil and gas reserves through an active and diversified program which includes purchases of reserves, re-engineering, development and exploration activities primarily focused in the Southwest,
Gulf Coast and the Williston Basin. Our corporate headquarters and Southern division operating offices are located in Houston, Texas, and our Northern division operating office is located in Denver, Colorado. We also have an additional operating
office for the Northern division in Williston, North Dakota.
On April 17, 2007, the Company merged with Southern Bay
Oil & Gas, L.P. (“Southern Bay”) and a subsidiary of Chandler Energy, LLC (“Chandler”) and acquired certain Chandler-associated oil and gas properties in exchange for 10,690,000 shares of common stock (collectively, the
“Merger”). At the time of the Merger, the former Southern Bay partners received approximately 57% of the outstanding common stock of the Company and thus, acquired voting control. Although GeoResources was the legal acquirer, for financial
reporting purposes the Merger was accounted for as a reverse acquisition of GeoResources by Southern Bay and an acquisition of Chandler and its associated properties.
During the course of 2007 and 2008, we transformed the Company from a small regional North Dakota-based company to a full scale exploration and production company with operations in multiple
basins. As of December 31, 2008, we had an estimated 17,501 MBOE of proved reserves, associated with both our directly owned mineral interests (14,592 MBOE) and our partnership interests (2,909 MBOE), which were approximately 51% oil and 79%
developed. See Item 2 of this report for estimates of our oil and gas reserves at December 31, 2008. Our production for the year ended December 31, 2008 totaled 1,236 MBOE or 3,387 BOE per day of which 60% was oil.
Recent Developments
Acquisition and Divestitures
In accordance with our business strategy, during 2008 we expanded our acreage positions and drilling inventory,
implemented our drilling programs and high-graded the assets resulting from the Merger and significant acquisitions of 2007. We sold or abandoned certain properties which, collectively had a net production at the time of the sale of 316 Bbls/d and
742 Mcf/d, but were outside our focus areas, had limited development potential, short remaining productive lives, high maintenance requirements, or significant plugging obligations. We also acquired producing and undeveloped properties, principally
in the Williston Basin and in Oklahoma. A summary of this activity is as follows:
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In January, 2008, we sold all of our interest in the Grand Canyon Unit, a property acquired in the Merger. This property, located in Otsego County, Michigan, was
sold to an unaffiliated party for $6.6 million in cash. At the date of sale, the carrying value of this property was equal to the selling price; therefore, no gain or loss was recognized on the sale.
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In February, 2008, we acquired producing properties from an unaffiliated party in the Williston Basin of North Dakota and Montana for $7.9 million in cash. The
acquired properties are operated by us.
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In February, 2008, we sold our interest in certain non-core oil and gas properties located in Louisiana to unaffiliated parties for $1.8 million and recognized
gains of $430,000.
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In May, 2008, we sold seven non-core oil and gas properties in Louisiana and Texas for approximately $11.8 million. We recognized a gain of $1.5 million related
to these sales.
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In May, 2008, Catena Oil & Gas LLC (“Catena”), a wholly-owned subsidiary of the Company, participated in the formation of OKLA Energy Partners
LP (“OKLA”) in order to acquire certain producing oil and gas properties and undeveloped acreage located throughout Oklahoma. The acquisition totaled $61.7 million. Catena directly purchased 18% of the interests and OKLA purchased the
remaining 82%. Catena, the general partner for OKLA, has a 2% partnership interest. Under the terms of the partnership agreement, Catena’s general partner interest can increase to approximately 36% pending certain performance hurdles.
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In September, 2008, we acquired producing properties in Oklahoma from an unaffiliated party for $3.6 million in cash.
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During 2008, we identified an exploration opportunity in the Paradox Basin and began leasing in Colorado and Utah targeting the Gothic shale, as a newly emerging
resource play with multiple objectives. In the fourth quarter of 2008, we sold a majority of our interest for $6 million and recognized a gain of $2.5 million. We retained an option to participate, up to a 12.5% working interest, in any future
drilling on the acreage.
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Long Term Debt
On October 16, 2007, we entered into an Amended and Restated Credit Agreement (“Amended Credit Agreement”) with a bank that provides for financing of up to $200 million. The
Amended Credit Agreement provided for interest at either (a) the London Interbank Offered Rate (“LIBOR”) plus 1.5% to 2.25%, or (b) the prime lending rate of the bank plus .5% to 1.25%, depending on principal amounts outstanding.
All amounts outstanding under this Amended Credit Agreement are due and payable in full at maturity on October 16, 2010. The initial borrowing base was $110 million. On September 30, 2008, the borrowing base had been reduced to $95 million
due to the sales of certain non-core oil and gas properties. On November 5, 2008, the borrowing base was increased to $100 million and the Amended Credit Agreement was amended to provide for interest rates at either, (a) LIBOR plus 1.75%
to 2.50%, or (b) the prime lending rate plus .75% to 1.50%, depending on the amount borrowed. On March 13, 2009, in connection with the borrowing base redetermination due April 1, 2009, we were advised that our lead bank will
recommend that the $100 million borrowing base be extended to the next redetermination. Approval is required by the bank group and is presently expected in early April.
Private Placement
On June 5, 2008, we issued 1,533,334 shares of our common
stock and 613,336 warrants to purchase common stock to non-affiliated accredited investors pursuant to exemptions from registration under federal and state securities laws. The shares of common stock were sold for $22.50 per share. The warrants have
a term of five years with an exercise price of $32.43 per share. The gross proceeds of $34.5 million were reduced by private placement fees and issue costs of $2.3 million.
Our Business Strategy
We implemented our business strategy upon the closing
of the Merger. Our strategy includes a combination of acquisition, re-engineering, development and exploration activities. We first focus on building reserves and cash flows and then expand acreage, development and exploration inventory. Further,
our strategy includes activities with geological and geographical diversity.
Our business strategy includes:
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acquiring additional oil and gas reserves through asset or corporate acquisitions or mergers;
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expanding acreage and prospect inventory through internal generation of new projects and selective prospect participations with other capable oil and gas
operators;
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comprehensive field re-engineering, designed to increase and maintain production, lower per-unit operating expenses, and therefore, improve field economics; and
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development, exploitation and exploration activities intended to increase production and estimated proved reserves.
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This fundamental operating and technical strategy is complemented by management’s commitment to:
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maintain a fundamentally sound capital structure which provides the Company a low cost of capital;
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control capital, operating and administrative costs;
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hedge a portion of total production to provide a foundation of predictable cash flows to support development and exploration activities;
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divest non-core assets to high-grade our portfolio of properties; and
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promote industry and institutional partners into projects to manage risk and to lower net finding and development costs.
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In the opinion of management, our strategy is appropriate for us because:
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it addresses multiple risks of oil and gas operations while providing shareholders with significant upside potential;
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it results in “staying-power,” which management believes is essential to mitigate the adverse impacts of volatile commodity prices and financial
markets; and
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it is a strategy employed successfully in prior entities formed, acquired and operated by management.
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Each component of our business strategy and related matters are briefly discussed below.
Acquisitions and Divestitures
– Acquisitions of oil and gas properties and/or companies in conjunction with exploration and development
activities are intended to allow us to assemble a portfolio of properties with the potential for meaningful economic returns from (1) the application of operational and technical attention, (2) development of non-producing reserves, and
(3) realization of exploration upside. We seek to acquire oil and gas interests with the characteristics of manageable risks, fairly predictable production and value enhancement potential. An ongoing part of our portfolio approach is the
divestiture of non-core assets in order to streamline and high-grade our oil and gas property portfolio. Divestitures of this type of properties are an integral part of our strategy.
Development Activities
– We are also focused on development and exploitation of non-producing reserves. We conduct comprehensive field studies, which usually result in:
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Re-engineering projects with the intent to lower per-unit operating expenses and/or reduce field down-time. In addition, we seek to implement more efficient
production practices in order to increase production and/or arrest natural field production declines. These practices are often deployed in fields in connection with or in anticipation of further field development activities such as installation of
secondary recovery operations or additional drilling.
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Development and exploration projects resulting from the integration of operations and reservoir engineering with geology and geophysics. When applicable, 3-D
seismic technology is utilized. Our objective is to develop specific projects to recover bypassed or undeveloped reserves and define exploration potential.
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Exploration
– We believe our management and technical personnel have the experience and capability to expand our acreage positions and drilling inventory, and accordingly, we expect
to continue to expand our exploration activities as our asset base increases. This strategy has three distinct purposes:
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expand our inventory of substantive acreage and prospects;
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fully develop acquired properties; and
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realize substantial economic returns from exploration.
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While we intend to dedicate a meaningful portion of our budget to exploration and drilling, as the geological objectives move to a higher risk and cost profile, industry or institutional partners
may be solicited on a promoted basis where we sell part of the project in exchange for cash and/or a carried interest.
Corporate
Mergers and Acquisitions
– As a distinct part of our overall strategy, we continue to pursue corporate merger and acquisition opportunities. Criteria for such acquisitions might include, but are not limited to:
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the potential to increase assets in a core area;
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the opportunity to increase our earnings and cash flow;
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development and exploration potential;
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the ability to refinance debt and attract capital; and
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realization of administrative savings.
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In summary, we believe these diversified business strategies and methodical processes will maintain the reserve and production base and lead to growth in reserves, production, cash flow and consequently, in per share
values.
8
Oil and Gas Exploration and Development
Our oil and gas exploration and production efforts are concentrated on oil and gas properties in our areas of operations. We typically
generate prospects for our own exploitation, but when we believe a prospect may have substantial risk or cost, we may partially finance our drilling activities through the sale of participations to industry or institutional partners on a promoted
basis, whereby we may earn working interests in reserves and production greater than our proportionate capital costs. For example, we may enter into farm-outs, joint ventures, or other similar types of cost-sharing arrangements to reduce our overall
capital cost. The amount of interest retained by us in a cost-sharing arrangement varies widely and depends upon many factors, including the exploratory costs and the risks involved.
Marketing of Production
Our oil and gas production is marketed to third
parties consistent with industry practices. Typically, oil is sold at the wellhead at field posted prices or market indices, plus or minus adjustments for quality or transportation. Natural gas is usually sold under a contract at a negotiated price
based upon factors normally considered in the industry, such as quality, distance from the well to the pipeline and liquid hydrocarbon content, and prevailing supply/demand conditions.
Backlog Orders, Research and Development
Our oil and gas sales contracts and
off-lease marketing arrangements are generally standard industry contracts with 30 to 90 day cancelation notice provisions. We do not have any contracts to supply crude oil or natural gas which exceed one year. We have not spent any material time or
funds on research and development and do not expect to do so in the foreseeable future. In addition, as discussed elsewhere, we have entered into long-term commodity hedge contracts to mitigate the effects of price declines of oil and natural gas.
Competition
In
addition to being highly speculative, the oil and gas business is highly competitive among many independent operators and major oil companies in the industry. Many competitors possess financial resources and technical facilities greater than those
available to us and they may, therefore, be able to pay for more desirable properties or find more potentially productive prospects.
Environmental
Regulations
Our operations are generally subject to numerous stringent federal, state and local environmental
regulations under various acts including the Comprehensive Environmental Response, Compensation and Liability Act, the Federal Water Pollution Control Act, and the Resources Conservation and Recovery Act. For example, our operations are affected by
diverse environmental regulations including those regarding the disposal of produced oilfield brines, other oil-related wastes, and additional wastes not directly related to oil and gas production. Additional regulations exist regarding the
containment and handling of crude oil as well as preventing the release of oil into the environment. It is not possible to estimate future environmental compliance costs due in part, to the uncertainty of continually changing environmental
initiatives. While future environmental costs can be expected to be significant to the entire oil and gas industry, we do not believe that our costs would be any more of a relative financial burden than others in our industry.
Foreign Operations and Export Sales
We do not have any interests, production facilities, or operations in foreign countries
Employees
As of December 31, 2008, we had 52 full-time employees, 34 of which are management, technical and administrative personnel, and 18
are field employees. Contract personnel operate some of our producing fields under the direct supervision of our employees. We consider all relations with our employees to be good.
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Available Information
We maintain a website at the address
www.georesourcesinc.com
. We are not including the information contained on our website as part of, or incorporating it by reference into this report.
Through our website, we make available our Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to these reports, as soon as reasonably practicable after we file such material with the SEC.
Set forth below are
risks with respect to our Company. Readers should review these risks, together with the other information contained in this report. The risks and uncertainties we have described in this report are not the only ones we face. Additional risks and
uncertainties not presently known to us, or that we deem immaterial, may also adversely affect our business. Any of the risks discussed in this report that are presently unknown or immaterial, if they were to actually occur, could result in a
significant adverse impact on our business, operating results, prospects and/or financial condition.
We are dependent upon the services of our chief
executive officer and other executive officers.
We are dependent upon a limited number of personnel, including Frank A.
Lodzinski, our Chief Executive Officer and President, and other management personnel and key employees. Failure to retain the services of these persons, or to replace them with adequate personnel in the event of their departure or termination, may
have a material adverse effect on our operations. No employment agreements with any of our officers currently exist, but we may consider such agreements in the future. We have no key-man life insurance on the lives of any of our executive officers.
We must successfully acquire or develop additional reserves of oil and gas.
Our future production of oil and gas is highly dependent upon our level of success in acquiring or finding additional reserves. The rate of production from our oil and gas properties generally
decreases as reserves are produced. We may not be able to acquire or develop oil and gas properties economically due to a lack of drilling success as well as lack of capital and inability to obtain adequate financing, which may be required to fund
prospect generation, drilling operations and property acquisitions.
Intense competition in the oil and gas exploration and production
segment could adversely affect our ability to acquire desirable properties prospective for oil and gas, as well as producing oil and gas properties.
The oil and gas industry is highly competitive. We compete with major integrated and independent oil and gas companies for the acquisition of desirable oil and gas properties and leases, for the equipment and services
required to develop and operate properties, and in the marketing of oil and gas to end-users. Many competitors have financial and other resources that are substantially greater than ours, which could, in the future, make acquisitions of producing
properties at economic prices difficult for us. In addition, many larger competitors may be better able to respond to factors that affect the demand for oil and natural gas production, such as changes in worldwide oil and natural gas prices and
levels of production, the cost and availability of alternative fuels and the application of government regulations. We also face significant competition in attracting and retaining experienced, capable and technical personnel, including geologists,
geophysicists, engineers, landmen and others with experience in the oil and gas industry.
We may be faced with shortages of personnel and equipment,
thereby adversely affecting operations and financial results.
The oil and gas industry, as a whole, suffers from an
aging workforce and shortage of qualified and experienced personnel. Our operations and financial results may be adversely impacted due to difficulties in attracting and retaining such personnel within our Company or within companies that provide
materials and services to the industry. Additional personnel are likely to be required in connection with our expansion plans, and the domestic oil and gas industry has in the past experienced significant shortages of qualified personnel in all
areas of
10
operations. Further, our expansion plans will likely require access to services and oil field equipment. Such equipment and operating personnel may be in
short supply. The substantial decrease in commodity prices has resulted in decreased drilling and construction activity in the industry and shortages of personnel and equipment has recently eased, but nevertheless shortages of qualified and
experienced personnel still exist.
Volatile oil and natural gas prices could adversely affect our financial condition and results of operations.
Our success will be largely dependent on oil and natural gas prices, which are highly volatile. During 2008 such prices
reached historically high levels only to fall dramatically in the later part of the year. Significant further declines in the price of oil and natural gas will have a negative impact on our business operations and future revenues. Moreover, oil and
natural gas prices depend on factors that are outside of our control, including:
|
|
•
|
|
economic and energy infrastructure disruptions caused by actual or threatened acts of war, or terrorist activities particularly with respect to oil producers in
the Middle East, Nigeria and Venezuela;
|
|
|
•
|
|
weather conditions, such as hurricanes, including energy infrastructure disruptions resulting from those conditions;
|
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|
•
|
|
changes in the global oil supply, demand and inventories;
|
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•
|
|
changes in domestic natural gas supply, demand and inventories;
|
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|
•
|
|
the price and quantity of foreign imports of oil;
|
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•
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|
the price and availability of liquified natural gas imports;
|
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|
•
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|
political conditions in or affecting other oil-producing countries;
|
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|
•
|
|
general economic conditions in the United Stated and worldwide;
|
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•
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|
the level of worldwide oil and natural gas exploration and production activity;
|
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|
•
|
|
technological advances affecting energy consumption; and
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•
|
|
the price and availability of alternative fuels.
|
Lower oil and natural gas prices not only decrease revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can economically produce. Lower prices also negatively impact estimates of
our proved reserves. Substantial or extended declines in oil or natural gas prices may materially and adversely affect our financial condition, results of operations, liquidity or ability to finance operations and planned capital expenditures.
Industry changes may adversely affect various financial measurements and negatively affect the market price of our common stock.
Although we believe that our business strategy has and will continue to allow us to continue our growth and increase
operating efficiencies, unforeseen costs and industry changes, as listed below, could potentially have an adverse effect on return of capital and earnings per share. Future events and conditions could cause any such changes to be significant,
including, among other things, adverse changes in:
|
|
•
|
|
commodity prices for oil, natural gas and liquid natural gas, such as occurred in 2008;
|
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|
•
|
|
capital expenditure obligations; and
|
We may
incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.
Oil and natural gas exploration, drilling and production activities are subject to numerous operating risks including the possibility of:
|
|
•
|
|
blowouts, fires and explosions;
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•
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|
personal injuries and death;
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•
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|
uninsured or underinsured losses;
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•
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|
unanticipated, abnormally pressured formations;
|
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•
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|
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses; and
|
11
|
|
•
|
|
environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including
groundwater and shoreline contamination.
|
Any of these operating hazards could cause damage to
properties, serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs, and other environmental damages, which could expose us to liabilities. Although we believe that we are adequately insured for
replacement costs of our wells and associated equipment, the payment of any of these liabilities could reduce the funds available for exploration, development, and acquisition, or could result in a loss of our properties. Also, as is customary in
the oil and gas business, we do not carry business interruption insurance.
The insurance market in general and the energy
insurance market in particular have recently experienced substantial cost increases from 2007 to 2008. It is possible that we will determine not to purchase some insurance because of high insurance premiums. If we incur substantial liabilities and
the damages are not fully covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition would likely be materially adversely affected.
We have hurricane associated risks in connection with our operations in the Texas and Louisiana Gulf Coast.
We could be subject to production curtailments resulting from hurricane damage to certain fields or, even in the event that producing
fields are not damaged, production could be curtailed due to damage to facilities and equipment owned by oil and gas purchasers, or vendors and suppliers, because a portion of our oil and gas properties are located in or near coastal areas of the
Texas and Louisiana Gulf Coast. In the third quarter of 2008, hurricanes Gustav and Ike damaged certain production facilities, located in the state waters of Louisiana. As a result, production volumes for the third quarter were down by approximately
15,800 net barrels of oil. Oil production started to be restored in phases in late October and as of year-end was fully restored. We incurred additional operating and capital expenditures as a result of the hurricanes of approximately $1.1 million
and expect to recoup $685,000 from insurance proceeds. Considering significant cost increases associated with “wind-storm” insurance coverage, we may increase our insurance deductibles or otherwise modify coverage.
If oil and gas prices decrease or exploration efforts are unsuccessful, we may be required to write-down the capitalized cost of individual oil and
gas properties.
A writedown of the capitalized cost of individual oil and gas properties could occur when oil and gas
prices are low or if we have substantial downward adjustments to our estimated proved oil and gas reserves, if operating costs or development costs increase over prior estimates, or if exploratory drilling is unsuccessful. A writedown could
adversely affect the trading prices of our common stock.
We use the successful efforts accounting method. All property
acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves are discovered. If proved reserves are not discovered with an exploratory well, the costs of
drilling the well are expensed. All geological and geophysical costs on exploratory prospects are expensed as incurred.
The capitalized costs of our oil and gas properties, on a field-by-field basis, may exceed the estimated future net cash flows of that field. If so, pursuant to generally accepted accounting principles, we are required to record impairment
charges to reduce the capitalized costs of each such field to its estimate of the field’s fair market value, even though other fields may have increased in value. Unproved properties are evaluated at the lower of cost or fair market value.
These types of charges will reduce earnings and shareholders’ equity.
12
Revisions of oil and gas reserve estimates could adversely affect the trading price of our common stock. Oil and gas
reserves and the standardized measure of cash flows represent estimates, which may vary materially over time due to many factors.
The market price of our common stock may be subject to significant decreases due to decreases in estimated reserves, our estimated cash flows and other factors. Estimated reserves may be subject to downward revision
based upon future production, results of future development, prevailing oil and gas prices, prevailing operating and development costs and other factors. There are numerous uncertainties and uncontrollable factors inherent in estimating quantities
of oil and gas reserves, projecting future rates of production, and timing of development expenditures.
In addition, the
estimates of future net cash flows from proved reserves and the present value of proved reserves are based upon various assumptions about prices and costs and future production levels that may prove to be incorrect over time. Any significant
variance from the assumptions could result in material differences in the actual quantity of reserves and amount of estimated future net cash flows from estimated oil and gas reserves.
Our hedging activities may prevent us from realizing the benefits in oil or gas price increases.
In an attempt to reduce our sensitivity to oil and gas price volatility, we have, and will likely continue to, enter into hedging transactions which may include fixed price swaps, price collars, puts and other
derivatives. In a typical hedge transaction, we may fix the price, a floor or a range, on a portion of our production over a predetermined period of time. It is expected that we will receive from the counter-party to the hedge payment of the excess
of the fixed price specified in the hedge contract over a floating price based on a market index, multiplied by the volume of the production hedged. Conversely, if the floating price exceeds the fixed price, we would be required to pay the
counter-party such price difference multiplied by the volume of production hedged. There are numerous risks associated with hedging activities such as the risk that reserves are not produced at rates equivalent to the hedged position, and the risk
that production and transportation cost assumptions used in determining an acceptable hedge could be substantially different from the actual cost. In addition, the counter-party to the hedge may become unable or unwilling to perform its obligations
under hedging contracts, and we could incur a material adverse financial effect if there is any significant non-performance. While intended to reduce the effects of oil and gas price volatility, hedging transactions may limit potential gains earned
by us from oil and gas price increases and may expose us to the risk of financial loss in certain circumstances.
Drilling for and producing oil and
natural gas are high-risk activities with many uncertainties that could adversely affect our financial condition and results of operations.
Our success will depend on the results of our exploitation, exploration, development and production activities. 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. 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. Costs of drilling, completing and operating wells are often uncertain
before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Furthermore, many factors may curtail, delay or cancel drilling, including:
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|
•
|
|
shortages of or delays in obtaining equipment and qualified personnel;
|
|
|
•
|
|
pressure or irregularities in geological formations;
|
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|
•
|
|
equipment failures or accidents;
|
|
|
•
|
|
adverse weather conditions;
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|
•
|
|
reductions in oil and natural gas prices;
|
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•
|
|
issues associated with property titles; and
|
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•
|
|
delays imposed by or resulting from compliance with regulatory requirements.
|
13
Existing debt and use of debt financing may adversely affect our business strategy.
We have used debt to fund a portion of our acquisition activities and we will likely use debt to fund a portion of our future acquisition
activities. Any temporary or sustained inability to service or repay debt will materially adversely affect our results of operations and financial condition and will materially adversely affect our ability to obtain other financing.
The global financial crisis may have impacts on our business and financial condition that we currently cannot predict.
The continued credit crisis and related turmoil in the global financial system, as well as the global economic recession, may have an
impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. The current economic situation could have a material adverse impact on our lenders or customers causing them to
fail to meet their obligations to us. Additionally, market conditions could have a materially adverse impact on our commodity hedging arrangements if our counterparties are unable to perform their obligations or seek bankruptcy protection. Also, the
current economic worldwide situation could lead to further reduced demand for oil and natural gas, or lower prices for oil and natural gas, or both, which could have a material negative impact on our revenues, results of operations and financial
conditions.
Due to the current state of the financial markets, we may have significantly reduced access to public and private capital as well as
substantially higher costs of capital if we are able to obtain capital.
Oil and gas activities are capital intensive.
Historically, we have obtained equity and debt capital to fund our growth strategy. We may require additional equity capital in order to pursue our business strategy and avoid excessive debt levels. Considering the current state of the worldwide
economy and the financial markets, we may not be able to attract investors that would provide equity capital to us at all, or the costs to obtain such capital may be unreasonable. To the extent that we may attract capital, the costs of such capital
could increase appreciably and such capital may take forms, such as preferred stock or convertible debt, which would be senior to our common stock. We believe that the ability to attract capital at reasonable costs is critical to our long-term
growth strategy, particularly due to the depleting nature of oil and gas operations.
We are obligated to comply with financial and other covenants in
our existing Amended Credit Facility that could restrict our operating activities, and the failure to comply could result in defaults that accelerate the payment under our debt.
Our Amended Credit Facility generally contains customary covenants, including, among others, provisions:
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•
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|
relating to the maintenance of the oil and gas properties securing the debt; and
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•
|
|
restricting our ability to assign or further encumber the properties securing the debt.
|
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|
•
|
|
all of our obligations under the Amended Credit Facility are secured by substantially all of our assets.
|
In addition, our Amended Credit Facility requires us to maintain financial covenants, including, but not limited to the following:
|
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•
|
|
a current ratio of not less than 1.0 to 1.0 excluding current hedge obligations;
|
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|
•
|
|
a funded debt to EBITDA ratio of not greater than 4.0 to 1.0; and
|
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|
•
|
|
an interest coverage ratio, which is the ratio of the EBITDA for the four most recently completed quarters ending on such date compared to the cash interest
payments made for such fiscal quarters, of not less than 3.0 to 1.0.
|
As of the date of this report, we
were in compliance with all such covenants. If we were to breach any of our debt covenants and not cure the breach within any applicable cure period, the Lender could require us to repay the debt immediately, and if the debt is secured, could
immediately begin proceedings to take possession of substantially all of our properties. Any such property losses would materially and adversely affect our cash flow and results of operations.
14
Our properties may be subject to influence by third parties that do not allow us to proceed with planned explorations
and expenditures.
We are the operator of a majority of our properties, but for many of our properties we own less than
100% of the working interests. Joint ownership is customary in the oil and gas industry and is generally conducted under the terms of a joint operating agreement (“JOA”), where a single working interest owner is designated as the
“operator” of the property. For properties where we own less than 100% of the working interest, whether operated or non-operated, drilling and operating decisions may not be within our sole control. If we disagree with the decision of a
majority of working interest owners, we may be required, among other things, to postpone the proposed activity or decline to participate. If we decline to participate, we might be forced to relinquish our interest through “in-or-out”
elections or may be subject to certain non-consent penalties, as provided in a JOA. In-or-out elections may require a joint owner to participate, or forever relinquish its position. Non-consent penalties typically allow participating working
interest owners to recover from the proceeds of production, if any, an amount equal to 200% to 500% of the non-participating working interest owner’s share of the cost of such operations.
Recent legislative proposals could materially lessen the economic viability of domestic exploration and production companies, including us.
The recent budgetary proposals of the Obama Administration, if enacted into law by Congress, could have a material adverse impact on the
domestic oil and gas industry and on exploration and production companies in particular. The proposals Would eliminate the so called “oil and gas company preferences” worth an estimated $31.5 billion over 10 years and raise other taxes on
the industry. The proposed budget would eliminate tax mechanisms critical to capital formation for drilling, such as expensing of intangible drilling costs and eliminating the percentage depletion allowance, and if enacted, would have a significant
adverse impact on domestic drilling for oil and natural gas. The proposed budget would also charge producers user fees for processing permits to drill on federal lands and increase royalty rates of minerals produced from federal lands. We cannot
predict the outcome of the proposed U.S. Government budget, but the enactment of any of the proposals would likely adversely affect the domestic oil and gas exploration and production business by making future production more difficult and
expensive, thereby lessening the economic viability of these companies, of which we are part.
There are a substantial number of shares of our common
stock eligible for future sale in the public market. The sale of a large number of these shares could cause the market price of our common stock to fall.
There were 16,241,717 shares of our common stock outstanding as of March 20, 2009.
Members of our management and other affiliates owned approximately 8,999,183 shares of our common stock, representing 55% of our outstanding common stock as of March 20, 2009. Sale of a substantial number of
these shares would likely have a significant negative affect on the market price of our common stock, particularly if the sales are made over a short period of time. These shares may be sold publicly pursuant to an effective registration statement
with the SEC.
If our stockholders, particularly management and their affiliates, sell a large number of shares of our
common stock, the market price of shares of our common stock could decline significantly. Moreover, the perception in the public market that our management and affiliates might sell shares of our common stock could depress the market price of those
shares.
Recovery of investments in acquiring oil and gas properties is uncertain.
We cannot assure that we will recover the costs we incur in acquiring oil and gas properties. While the acquisition and development of oil
and gas properties is based on engineering, geological and geophysical assessments, such data and analysis is inexact and inherently uncertain. There can be no assurance that any properties we acquire will be economically produced or developed.
Re-engineering operations pose the risk that anticipated benefits, which may include reserve additions, production rate improvements or lower recurring operating expenses, may not be achieved, or that actual results obtained may not be sufficient to
recover investments. Drilling activities, whether exploratory or developmental, are subject to mechanical and geological risks, including the risk that no commercially productive reservoirs will be encountered. Unsuccessful acquisitions,
re-engineering or drilling activities could have a material adverse effect on our results of operations and financial condition.
15
We cannot assure we would be able to achieve continued growth in assets, production or revenue.
There can be no assurance that we will continue to experience growth in revenues, oil and gas reserves or production. Any future growth in
oil and gas reserves, production and operations will place significant demands on us and our management and personnel. Our future performance and profitability will depend, in part, on our ability to successfully integrate acquired properties into
our operations, develop such properties, hire additional personnel and implement necessary enhancements to our management systems.
The nature of our
business and assets may expose us to significant compliance costs and liabilities.
Our operations involving the
exploration, production, storage, treatment, and transportation of liquid hydrocarbons, including crude oil, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. Our
operations are also subject to laws and regulations relating to protection of the environment, operational safety, and related employee health and safety matters. Compliance with all of these laws and regulations may represent a significant cost of
doing business. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial liabilities; the issuance of injunctions that may restrict,
inhibit or prohibit our operations; or claims of damages to property or persons.
Compliance with environmental laws and regulations may require us to
spend significant resources.
Environmental laws and regulations may: (1) require the acquisition of a permit
before well drilling commences; (2) restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; (3) prohibit or limit drilling
activities on certain lands lying within wetlands or other protected areas; and (4) impose substantial liabilities for pollution resulting from past or present drilling and production operations. Moreover, changes in Federal and state
environmental laws and regulations could occur and may result in more stringent and costly requirements which could have a significant impact on our operating costs. In general, under various applicable environmental regulations, we may be subject
to enforcement action in the form of injunctions, cease and desist orders and administrative, civil and criminal penalties for violations of environmental laws. We may also be subject to liability from third parties for civil claims by affected
neighbors arising out of a pollution event. Laws and regulations protecting the environment may, in certain circumstances, impose strict liability rendering a person liable for environmental damage without regard to negligence or fault on the part
of such person. Such laws and regulations may expose us to liability for the conduct of or conditions caused by others, or for our acts which were in compliance with all applicable laws at the time such acts were performed. We believe we are in
compliance with applicable environmental and other governmental laws and regulations. There can be no assurance, however, that significant costs for environmental regulatory compliance will not be incurred by us in the future, thereby having an
adverse effect on our ability to conduct our business profitably.
Our failure to successfully identify, complete and integrate future acquisitions of
properties or businesses could reduce our earnings and slow our growth.
There is intense competition for acquisition
opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and
equity financing and, in some cases, regulatory approvals. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional
employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and
results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
16
|
Item 1B.
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Unresolved Staff Comments
|
None.
Offices
Our principal offices are located at 110 Cypress Station Drive, Suite 220, Houston,
Texas 77090, where we occupy approximately 14,000 square feet of office space. This lease provides for gross rent of $220,080 per year and expires on October 31, 2010. Our Northern Region office, consisting of approximately 3,600 square feet,
is located at 475 17
th
Street, Suite 1210, Denver, Colorado 80202. The Denver lease provides for gross rent of $77,190 per year for 2009 and expires
on January 31, 2011. Our Williston office consists of approximately 4,000 square feet and is located at 1407 West Dakota Parkway, Williston, North Dakota 58801. The Williston lease provides for gross rent of $24,000 per year for 2009 and
expires on December 31, 2010. We currently expect to renew all of our office leases upon expiration.
17
Oil and Gas Reserve Information
All of our oil and gas reserves are located in the United States. Unaudited information concerning the estimated net quantities of all of our proved reserves and the standardized measure of
future net cash flows from the reserves is presented in Note N to the Consolidated Financial Statements. The estimates are based upon the reports of Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. We have no
long-term supply or similar agreements with foreign governments or authorities.
Set forth below is a summary of our oil
and gas reserves as of December 31, 2008. All of our reserves are located in the United States. We did not provide any reserve information to any federal agencies in 2008 other than to the SEC.
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|
|
|
|
|
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Oil
(Mbbl)
|
|
Gas
(Mmcf)
|
|
Present Value
Discounted at
10% ($M) (1)
|
|
Proved developed
|
|
7,522
|
|
25,025
|
|
$
|
125,540
|
|
Proved undeveloped
|
|
1,271
|
|
9,771
|
|
|
25,076
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
8,793
|
|
34,796
|
|
$
|
150,616
|
|
|
|
|
|
|
|
|
|
Oil and Gas Reserve Quantities
|
|
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|
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|
|
Oil
(Mbbl)
|
|
|
Gas
(Mmcf)
|
|
|
Proved reserve quantities, January 1, 2008
|
|
10,744
|
|
|
29,810
|
|
|
Purchase of minerals-in-place
|
|
672
|
|
|
9,726
|
|
|
Sales of minerals-in-place
|
|
(988
|
)
|
|
(4,946
|
)
|
|
Extensions and discoveries
|
|
501
|
|
|
1,155
|
|
|
Production
|
|
(743
|
)
|
|
(2,962
|
)
|
|
Revision of estimated quantity
|
|
(1,393
|
)
|
|
2,013
|
|
|
|
|
|
|
|
|
|
|
Proved reserve quantities, December 31, 2008
|
|
8,793
|
|
|
34,796
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserve quantities
|
|
|
|
|
|
|
|
January 1, 2008
|
|
8,921
|
|
|
26,427
|
|
|
December 31, 2008
|
|
7,522
|
|
|
25,025
|
|
|
(1)
|
Present Value Discounted at 10% (“PV10”) is a Non-GAAP measure that differs from the GAAP measure “standardized measure of discounted future net
cash flows” in that PV10 is calculated without regard to future income taxes. Management believes that the presentation of PV10 value is relevant and useful to our investors because it presents the estimated discounted future net flows
attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. Because many factors that are unique to each individual
company impact the amount of future income taxes to be paid, we believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies. For these reasons, management uses, and believes the industry generally uses,
the PV10 measure in evaluating and comparing acquisition candidates and assessing the potential return on investment related to investments in oil and natural gas properties.
|
18
PV10 is not a measure of financial or operational performance under GAAP, nor should it
be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. For presentation of the standardized measure of discounted future net cash flows, please see “Note N:
Supplemental Financial Information for Oil and Gas Producing Activities” in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this Annual Report on Form 10-K. The table below provides a reconciliation of PV10 to the
standardized measure of discounted future net cash flows.
Partnership operations and reserves as of December 31, 2008 (not included above):
The reserve quantities and values shown above do not include our interest in two affiliated partnerships.
We hold direct working interests in the Giddings Field (discussed further below) and we also hold the general partner interest of a
partnership, SBE Partners, LP (“SBE Partners”) which owns controlling interests in the producing wells and developmental acreage in that field. Our 2% partnership interest reverts to 35.66% when the limited partner realizes a contractually
specified rate of return.
We hold direct working interests in producing oil and gas properties located throughout Oklahoma
and we also hold the general partner interest of a partnership, OKLA Energy Partners, LP (“OKLA”) which owns a larger interest in those same producing oil and gas properties. Our 2% partnership interest reverts to 35.66% when the limited
partner realizes a contractually specified rate of return.
The following table represents our estimated share (inclusive
of our reversionary interests) of the affiliated partnerships’ reserves and estimated present value of future net income discounted at 10% (in thousands of dollars), using SEC guidelines.
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|
|
|
|
|
|
|
|
|
|
|
Affiliated Partnership Reserves
|
|
|
|
Oil
(Mbbl)
|
|
Gas
(Mmcf)
|
|
Present Value
Discounted at
10% ($M) (1)
|
|
Proved developed
|
|
58
|
|
12,227
|
|
$
|
21,147
|
|
Proved undeveloped
|
|
61
|
|
4,510
|
|
|
9,125
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
119
|
|
16,737
|
|
$
|
30,272
|
|
|
|
|
|
|
|
|
|
19
Non-GAAP Reconcilation
The following table reconciles our direct interest in oil and gas reserves (in thousands):
|
|
|
|
|
|
|
Present value of estimated future net revenues (PV10)
|
|
$
|
150,616
|
|
|
Future income taxes, discounted at 10%
|
|
|
(29,997
|
)
|
|
|
|
|
|
|
|
Standardize measure of discounted future net cash flows
|
|
$
|
120,619
|
|
|
|
|
|
|
|
|
|
|
The following table reconciles our indirect interest, through our affiliated partnerships, in oil and gas reserves (in thousands):
|
|
|
|
|
|
Present Value of estimated future net revenues (PV10)
|
|
$
|
30,272
|
|
|
Future income taxes, discounted at 10%
|
|
|
(12,401
|
)
|
|
|
|
|
|
|
|
Standardize measure of discounted future net cash flows
|
|
$
|
17,871
|
|
|
|
|
|
|
|
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, and the accuracy of any reserve estimate is a function of the
quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date
of the estimates, as well as economic factors such as change in product prices, may require revision of such estimates. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserve estimates.
20
Net Oil and Gas Production, Average Price and Average Production Cost
The net quantities of oil and gas produced and sold by us for each of the three fiscal years ended December 31, the average sales
price per unit sold and the average production cost per unit are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Oil Production (MBbls)
|
|
|
743
|
|
|
392
|
|
|
184
|
|
Gas Production (MMcf)
|
|
|
2,962
|
|
|
1,648
|
|
|
577
|
|
Total Production (MBOE)*
|
|
|
1,236
|
|
|
667
|
|
|
280
|
|
Average sales price (net of hedging):
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl
|
|
$
|
82.42
|
|
$
|
67.20
|
|
$
|
54.61
|
|
Gas per Mcf
|
|
$
|
8.12
|
|
$
|
6.19
|
|
$
|
6.83
|
|
BOE
|
|
$
|
68.96
|
|
$
|
54.74
|
|
$
|
49.92
|
|
Production cost per BOE**
|
|
$
|
27.46
|
|
$
|
23.67
|
|
$
|
20.37
|
|
*
|
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (1 BOE).
|
|
**
|
Average production cost includes lifting costs, remedial workover expenses and production taxes.
|
Our production is sold to large petroleum purchasers. Due to the quality and location of our crude oil production, we may receive a
discount or premium from index prices or “posted” prices in the area. Our gas production is sold primarily to pipelines and/or gas marketers under short-term contracts at prices which are tied to the “spot” market for gas sold in
the area.
In 2008, one purchaser accounted for 16% of our consolidated oil and gas revenue, two more accounted for 11%
each and two purchasers accounted for 10% each of our oil and gas revenues. In 2007, two purchasers accounted for 17% and 14% of our consolidated oil and gas revenues. In 2006, four purchasers accounted for 27%, 18%, 15% and 12% of our consolidated
oil and gas revenues. No other single purchaser accounted for 10% or more of our oil and gas revenues in 2008, 2007, or 2006. There are adequate alternate purchasers of our production such that we believe the loss of one or more of the above
purchasers would not have a material adverse effect on our results of operations or cash flows.
Gross and Net Productive Wells
As of December 31, 2008, our total gross and net productive wells were as follows:
Productive Wells *
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
Gas
|
|
|
|
Total
|
|
Gross
Wells
|
|
|
|
Net
Wells
|
|
|
|
Gross
Wells
|
|
|
|
Net
Wells
|
|
|
|
Gross
Wells
|
|
|
|
Net
Wells
|
|
456.0
|
|
|
|
259.2
|
|
|
|
470.0
|
|
|
|
130.8
|
|
|
|
926.0
|
|
|
|
390.0
|
|
*
|
There are no wells with multiple completions. A gross well is a well in which a working interest is owned. The number of net wells represents the sum of
fractions of working interests we own in gross wells. Productive wells are producing wells plus shut-in wells we deem capable of production. Horizontal re-entries of existing wells do not increase a well total above one gross well.
|
21
Gross and Net Developed and Undeveloped Acres
As of December 31, 2008, we had total gross and net developed and undeveloped leasehold acres as set forth below. The developed
acreage is stated on the basis of spacing units designated by state regulatory authorities.
Gross acres are those acres in
which working interest is owned. The number of net acres represents the sum of fraction working interests we own in gross acres.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
Undeveloped
|
|
Total
|
|
State
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Texas
|
|
86,726
|
|
35,179
|
|
19,861
|
|
1,637
|
|
106,587
|
|
36,816
|
|
N. Dakota
|
|
32,063
|
|
17,957
|
|
50,484
|
|
20,432
|
|
82,547
|
|
38,389
|
|
Colorado
|
|
7,049
|
|
5,119
|
|
65,069
|
|
47,200
|
|
72,118
|
|
52,319
|
|
Oklahoma
|
|
52,653
|
|
10,227
|
|
595
|
|
—
|
|
53,248
|
|
10,227
|
|
Alabama
|
|
42,480
|
|
21,240
|
|
—
|
|
—
|
|
42,480
|
|
21,240
|
|
Louisiana
|
|
34,798
|
|
12,516
|
|
1,150
|
|
80
|
|
35,948
|
|
12,596
|
|
Montana
|
|
8,891
|
|
6,393
|
|
11,462
|
|
10,230
|
|
20,353
|
|
16,623
|
|
All Others
|
|
4,676
|
|
3,658
|
|
5,259
|
|
4,583
|
|
9,935
|
|
8,241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
269,336
|
|
112,289
|
|
153,880
|
|
84,162
|
|
423,216
|
|
196,451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory Wells and Development Wells
Set forth below for the three years ended December 31, is information concerning the number of wells we drilled during the years
indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Exploratory
Wells Drilled
|
|
Net Development
Wells Drilled
|
|
Total Net Productive
or Dry Wells Drilled
|
|
Year
|
|
Productive
|
|
Dry
|
|
Productive
|
|
Dry
|
|
|
2006
|
|
—
|
|
0.20
|
|
2.13
|
|
0.58
|
|
2.91
|
|
2007
|
|
1.97
|
|
—
|
|
4.27
|
|
—
|
|
6.24
|
|
2008
|
|
0.09
|
|
1.00
|
|
9.72
|
|
1.96
|
|
12.77
|
Subsequent to year-end we drilled three exploratory dry holes; the costs incurred
through December 31, 2008, are included in exploration expense.
Present Activities
At March 20, 2009, we had 7 gross (0.37 net) wells in the process of drilling or completing.
Supply Contracts or Agreements
As December 31, 2008, we are not obligated to provide any fixed or determinable quantities of oil and gas in the future under any existing contracts or agreements, beyond the short-term contracts customary in division orders and off
lease marketing agreements with the industry. In March, 2009, we entered into a forward sales contract for a portion of the crude oil sales on several of our Northern Region properties. The contract obligates us to sell 300 Bbls/d at a fixed price
of $40.80. The contract term begins April, 2009 and runs through March, 2010. We also engage in hedging activities as discussed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
22
Summary of our Producing Properties
The following is a description of our noteworthy producing fields that provide a production base for our continued operations. We believe that many of these fields have upside exploitation
potential. See also “Exploration and Exploitation” below.
Black Warrior Basin
— located in Alabama and Mississippi.
These properties include several fields with 36 producing wells. Production is from conventional reservoirs consisting of Mississippian-aged sands. Some wells are on rod-pump while the majority of the wells flow directly into low pressure gathering
systems. The current aggregated gross production rate is 1.45 MMcf/d. The majority of the wells are operated by the Company, which has an average working interest of 60% and an average net revenue interest of 46%.
Chittim Field
— located in Maverick County, Texas. The field consists of 43 gross producing wells which produce from the Cretaceous Glen Rose
interval. All of the wells flow into a low pressure gathering system at a current aggregate gross rate of 3.62 MMcf/d. The majority of the wells are horizontal producers. The field is operated by the Company, which has an average working interest of
47% and an average net revenue interest of 36%.
Driscoll Field
— located in Duval County, Texas. This field consists of 41
gross producing wells, which produce from the Jackson/Yegua interval. The majority of the field produces with the aid of rod pumps and the current aggregate gross production rate is 164 Bbls/d and 361 Mcf/d. The field is operated by the Company,
which has an average working interest of 98% and an average net revenue interest of 86%.
East Nesson Bakken Area
— Located in
Mountrail County, North Dakota. The area is being developed by numerous operators and we have varying working interests ranging from 10% to 15% and net revenue interests ranging from 8.2% to 12.3% in approximately 35,000 acres. Our participation in
this field is primarily through a joint venture with another Williston Basin operator. To date, 13 joint venture wells have been drilled by that operator and we also have nominal interests in another 24 wells that are producing or are in various
stages of completion. Current production net to our interest is approximately 100 Bbls/d.
Eloi Bay Field Complex
— located in
state waters offshore St. Bernard Parish, Louisiana. The field (including the adjacent Chandler Sound Block 71) is located in 5-10 feet of water. This non-operated field complex has 46 gross producing wells on gas lift – all completed in the
Miocene section. Current aggregate gross production is 1,077 Bbls/d. The Company’s working interest varies between 12.5% and 50%. Across the field as a whole, the average working interest is 46% and the average net revenue interest is 39%.
Frisco and Fordoche Fields
— located in Pointe Coupee Parish, Louisiana. These fields consist of 23 gross producing wells,
which produce from the Frio and multiple Wilcox Sand intervals. All of the wells are on rod-pump or hydraulic lift with an aggregate current gross rate of 384 Bbls/d. Both fields are operated by the Company, which has an average working interest of
70% and an average net revenue interest of 55%.
Giddings Field
— located in Brazos, Burleson, Fayette, Grimes, Lee, Montgomery
and Washington Counties, Texas. These properties consist of 63 gross producing wells, which produce from the Cretaceous Austin Chalk interval. All of the wells are horizontal producers utilizing rod pumps, compression, and other methods to produce
the current aggregate gross rate of 111 Bbls/d and 48.36 MMcf/d. The field is operated by the Company, which has an average direct working interest of 6.7% and a net revenue interest of 5.2%. In Grimes County, however, where a majority of production
and development is located, the Company has a direct working interest of 7.2% and average net revenue interest of 5.6%. In addition, the Company is the General Partner of a partnership which owns an average 77% working interest with an average 66%
net revenue interest in 61,333 gross (55,200 net) acres. The Company’s 2% partnership interest reverts to 35.66% when the partnership realizes a contractually specified rate of return.
Harris Field
— located in Gaines County, Texas. The field consists of six gross producing wells, which produce from the San Andres interval. The field produces with the aid of rod
pumps and the current gross production rate is 57 Bbls/d. The field is operated by the Company, which has an average working interest of 76% and an average net revenue interest of 57%.
23
Landa West Madison Unit / Northeast Landa Field
— located in Bottineau County, North Dakota.
These two fields consist of 14 gross producing wells, which produce from the Spearfish and Mississippian Madison intervals. Both fields are operated by the Company, which has an average working interest of 92% and average net revenue interest of
78%. The current gross production is 66 Bbls/d.
MAK Field
— located in Andrews County, Texas. This field consists of nine
gross producing wells, which produce from the Spraberry interval. The field produces with the aid of rod pumps and the current gross production rate is 145 Bbls/d and 52 Mcf/d. The field is operated by the Company, which has an average working
interest of 91% and an average net revenue interest of 71%.
New Mexico Fields
— located in Eddy and Lea Counties, New Mexico.
This area consists of three fields with 37 gross producing wells. Production is from the Seven Rivers, Queen, Grayburg and San Andres formations. The wells are on rod pumps and the current aggregate gross production rate is 88 Bbls/d. The fields are
operated by the Company, which has an average working interest of 94% and an average net revenue interest of 76%.
Odem Field
—
located in San Patricio County, Texas. This field consists of 67 gross producing wells, which produce from multiple Frio Sands. The fields produce with the aid of rod pumps, compression and gas lift with the current gross production rate of 143
Bbls/d and 2.01 MMcf/d. The field is operated by the Company, which has an average working interest of 48% and net revenue interest of 37%.
Quarantine Bay Field
— located in State waters offshore Plaquemines Parish, Louisiana. The field is located in 6-15 feet of water. The non-operated field has 31 gross producing wells completed above 10,500 feet. All of the wells
produce with the aid of gas lift equipment. Current field gross production is approximately 910 Bbls/d and 104 Mcf/d. The Company has an average working interest in these wells of 7.0% and an average net revenue interest of 5.2%. The Company,
however, has a 33% working interest in exploration acreage below 10,500 feet and rights which are held by production (see “Exploration and Exploitation” discussion below).
Sherman/Wayne Fields
— located in Bottineau County, North Dakota. These fields consist of 19 gross producing wells, which produce from the Mississippian Wayne interval. These fields
are operated by the Company, which has an average working interest of 80% and an average net revenue interest of 67%. The current gross production of these fields is 259 Bbls/d.
St. Martinville Field
— located in St. Martin Parish, Louisiana. The field consists of 16 gross producing wells, which produce from numerous Miocene sand intervals. The wells are on
rod-pump or electric submersible pumps and have a current gross production rate of 392 Bbls/d. The field is operated by the Company, which has an average working interest of 97%. The Company owns the majority of the minerals resulting in a net
revenue interest of approximately 91%.
Starbuck Madison Unit and Southwest Starbuck Field
— located in Bottineau County, North
Dakota. The Starbuck Madison Field has been unitized and water-flood operations are underway. The Starbuck Madison Unit includes 14 gross producing wells and three active injectors as well as and two additional drilled but not yet completed
injection wells. The unit produces from the Mississippian Madison interval. The capital plan was divided into phases. Phase one was completed February, 2008, phase two began in the fourth quarter, 2008, and was recently completed. The field is
operated by the Company, which has an average working interest of 96% and an average net revenue interest of 83%. The gross production from the field is currently 56 Bbls/d and can increase significantly pending successful flood performance. The
Company also has successfully unitized the Southwest Starbuck Field which includes 560 gross acres. The Company has a 97.52% working interest, a 75.42% net revenue interest and has completed the initial phase of water flood operations in connection
with phase two of the larger Starbuck Madison Unit, which is in close proximity and can share certain facilities, thereby enhancing the economics of both units.
Exploration and Exploitation
Our producing properties have reasonably predictable production profiles,
earnings and cash flows and thus provide a foundation for our technical staff to further develop our existing properties and also generate new projects that we believe have the potential to increase our share value. We believe that many of our
existing fields have
24
exploration and exploitation potential, much of which is presently defined. The steep and rapid decline of commodity prices in 2008 and the collapse of the
capital markets have caused numerous independents to significantly reduce their capital budgets. While we have not yet reduced our capital budget, some of our projects, particularly those that are held by production, have been deferred in favor of
projects with lease expirations. In addition, some projects in North Dakota have been deferred as a result of prices being adversely affected by increased transportation and quality deductions. In some cases, these projects were replaced by Gulf
Coast projects with better current commodity prices. Our capital budget is discussed more fully in Item 7. The table and discussion below, while not all inclusive, present a broad range of projects and prospects in various stages of
development.
Exploration and Exploitation Acreage
We attempt to establish production operations in areas of
interest and expand exploration and exploitation opportunities in those fields and regional proximity thereto. The table below is presented to summarize certain acreage positions associated with exploration and exploitation opportunities. The
acreage table is not all inclusive but summarizes the field discussions below.
|
|
|
|
|
|
|
|
|
|
|
|
|
Acreage
|
|
Field
|
|
State
|
|
Gross
|
|
Net
|
|
Chittim
|
|
TX
|
|
12,822
|
|
6,411
|
|
Driscoll
|
|
TX
|
|
12,000
|
|
11,760
|
|
East Nesson
|
|
ND
|
|
70,493
|
|
39,219
|
|
Eloi Bay
|
|
LA
|
|
8,704
|
|
4,352
|
|
Harris
|
|
TX
|
|
160
|
|
122
|
|
Giddings (1)
|
|
TX
|
|
61,333
|
|
55,200
|
|
Landa West Madison Unit
|
|
ND
|
|
1,145
|
|
1,070
|
|
MAK
|
|
TX
|
|
3,680
|
|
3,348
|
|
New Mexico
|
|
NM
|
|
2,156
|
|
1,847
|
|
Northeast Landa
|
|
ND
|
|
1,127
|
|
849
|
|
Odem
|
|
TX
|
|
6,500
|
|
3,250
|
|
Oklahoma (1)(2)
|
|
OK
|
|
52,653
|
|
28,217
|
|
Quarantine Bay (3)
|
|
LA
|
|
14,535
|
|
1,281
|
|
Rip Rap Coulee
|
|
MT
|
|
997
|
|
498
|
|
Roth-Leonard
|
|
ND
|
|
1,374
|
|
1,353
|
|
Sherman/Wayne
|
|
ND
|
|
1,090
|
|
967
|
|
St. Martinville
|
|
LA
|
|
1,322
|
|
1,283
|
|
Starbuck Unit
|
|
ND
|
|
6,619
|
|
6,354
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
258,710
|
|
167,381
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes acreage held by us and our affiliated partnership, see Partnership Reserves and discussion of the Giddings field included above.
|
|
(2)
|
Represents acreage in multiple fields, includes acreage held by GeoResources and its affiliated partnership
|
|
(3)
|
Represents net exploration acreage held by shallow production. See discussion below.
|
Chittim Field
(also discussed above) — We have 12,822 gross and 6,411 net acres in the field. The field presently produces out of the Glen Rose interval and the upside potential
includes an additional three proved and probable undeveloped locations. The Maverick Basin, however, has additional plays and targets including the Pearsall and Eagleford shale. We have budgeted a horizontal offset well to a vertical Pearsall well
that produced and we believe horizontal drilling and advanced completion techniques offer the potential to make the Pearsall meaningful to us. The commercial viability of the Eagleford shale is unknown and we will monitor the drilling and
development
25
efforts of other operators before we commit drilling dollars to development. Our acreage is held by production and therefore, we have no pending lease
obligations or expirations.
Driscoll Field
(also discussed above) — The field was owned by Conoco for much of its life and
little development occurred over the last 20 years. We own nearly all of the working interest in this field. We hold 12,000 gross and 11,760 net acres. In 2008, we initiated a field-wide and regional study, which has been deferred due to our
expanded activities in other areas. Initial reviews identified several re-engineering and recompletion projects. We successfully completed certain nominal re-engineering and recompletion projects. The acreage is held by production and therefore, we
have no pending lease obligations or expirations.
East Nesson Bakken Area
— Located in Mountrail County, North Dakota. We have
varying working interests in the area ranging from 10% to 15% and net revenue interests ranging from 8.2% to 12.3% in approximately 35,000 acres. This is a developing Bakken Formation horizontal drilling play at vertical depths of about 9,800 feet.
We are participating in an active leasehold acquisition and drilling program in a joint venture with another Williston Basin operator. The leasehold generally consists of portions of tracts or governmental subdivisions that will become drilling and
spacing units. Accordingly, our working and net revenue interests could be reduced proportionally to acreage contributed to a drilling unit. To date, 13 joint venture wells have been drilled by the operator and 43 wells have been staked by other
operators where we own minor interests. The joint venture remains active and has continued to acquire attractive acreage. The reduction in commodity prices which occurred 2008 has caused numerous operators to curtail or significantly reduce drilling
and development operations. We expect to continue drilling throughout 2009 with one rig. However, in the near term, until drilling and development costs decline further, wells may include acreage where the joint venture has lower working interests
in order to reduce near term capital expenditures. To date, the joint venture gross completed well costs have been approximately $5 million per well. In the near term, we expect gross joint venture wells to be approximately $4.5 million and to
average under $4.0 million in four to six months. We intend to further increase our acreage position and participating interest as the play develops and expands.
Eloi Bay Field Complex
(also discussed above) — In addition to the proved production, this field has numerous behind-pipe opportunities due to multiple stacked sand reservoirs along with four proved
undeveloped locations, which are above existing production. At present, 8,074 gross and 4,352 net acres are held by production. Other operators have had drilling success and established deeper production in the area and we have budgeted funds for
the acquisition and reprocessing of 3-D seismic over the field and certain surrounding acreage to define prospective opportunities which may exist. The hurricanes of 2008 and the reduction in commodity prices have caused us to defer data
acquisition, processing and interpretation activities. We intend to pursue prospect leads in the orderly course of business. This acreage is held by production and, therefore, we have no pending lease obligations or expirations.
Harris Field
(also discussed above) — This field consists of 160 gross and 122 net acres and is in the early stages of water-flooding with
one injector well installed in 2007. Additional capital was allocated in 2008 for a crestal well, but has been deferred in favor of committing drilling dollars to projects with lease obligations.
Giddings Field
(also discussed above) — We have implemented a development program and we are actively acquiring additional acreage. Along
with our affiliated partnership, we control 50,080 gross (46,189 net) acres that are held by production and an additional 11,253 gross and 9,011 net leased acres that are not currently held by production. This field consists of multiple wells that
have the potential for production rate increases through the use of fracture stimulations and 11 proved undeveloped drilling locations. We have drilled 10 wells to date and achieved a 100% success rate. We have recently leased 5,683 federal acres.
We presently expect at least 15 additional drilling locations and intend to retain the current drilling rig and spud a new well approximately every 60-75 days. We will consider deploying a second rig as drilling costs decline. We are the operator of
all of these wells and hold a direct 7.2% working interest in the core development area of this field. In addition, an affiliated partnership owns an 82.8% working interest. Throughout the field we have an average working interest of 6.7% and an
incremental reversionary interest of 35.66% through our affiliate partnership (see “Partnership Reserves” above). There has been significant exploration activity in regional proximity to our large acreage position in Grimes County, Texas,
including a shallow Yegua formation gas discovery, which we believe would be prospective to our acreage and justify a 3-D seismic program, and in the deeper Eagleford shale which underlies the Austin Chalk. The Eagleford shale is being drilled and
evaluated by a number of substantially larger independents.
26
Landa West Madison Unit
(also discussed above) — We hold 1,145 gross and 1,070 net acres in
the field. These acres are held by production. This unit has additional potential in reconfiguring its current injection pattern to increase recoveries.
MAK Field
(also discussed above) — We hold 3,680 gross and 3,348 net acres by production. A completed waterflood is in place and production has continued to increase slowly over time. The possibility of
drilling infill locations in this existing waterflood is under evaluation with at least one location expected in 2009.
New Mexico
Fields
(also discussed above) — We hold 2,156 gross and 1,847 net acres by production. These acres are held by production. Upside exists in each of the three fields, which are in various stages of waterflood redevelopment. The fields are
being studied for additional injection wells and infill producers, which we believe could enhance the waterflood upside.
Northeast
Landa Field
(also discussed above) — Located in Bottineau County, North Dakota, the field has produced primarily from the Mission Canyon Formation at depths of approximately 3,070 feet—3,100 feet. We hold 1,127 gross and 849 net acres.
Cumulative primary recovery to date is approximately 591,000 barrels of oil. Seven gross wells remain on production. This secondary recovery potential has been studied and confirmed for the eastern lobe in the Mission Canyon member of the Madison
Formation. Upon recognizing the potential and extent of the floodable reservoir, we launched a leasehold and production acquisition effort to enhance our position in the field. This effort has been successful and is continuing. We have completed
preliminary flood designs, but due to questions raised by certain working interest owners we were unable to voluntarily unitize the field in 2008. In the fourth quarter of 2008, we drilled a key evaluation well to collect electric logs and cores for
additional evidence. Core analysis and laboratory results should be available in the second quarter of 2009. At that time, we intend to commence unitization proceedings. We expect to have the field unitized and begin water-flood installation in
2009.
Odem Field
(also discussed above) — We hold 6,500 gross and 3,250 net acres by production from multiple Frio Sands. We
believe numerous proved and non-proved behind-pipe zones exist for recompletion into shallower Frio intervals. We have 3-D seismic data over the properties. Certain wells that were budgeted for 2008 have been deferred in favor of other
opportunities.
Oklahoma
— During 2008, Catena, a wholly-owned subsidiary of the Company, participated in the formation of an
affiliated partnership in order to acquire certain producing oil and gas properties and undeveloped acreage located throughout Oklahoma. We directly purchased 18% of the interests, while the partnership purchased the remaining 82%. We believe we can
exploit exploration and development opportunities associated with the acreage and in acres in close proximity to those acquired. Lower gas prices and increased differentials have reduced gas prices in many mid-continent areas to less than $3.00 per
Mcf and accordingly, drilling economics have been adversely impacted. The undeveloped acreage includes approximately 100 drilling locations. Most of these locations are held by production and therefore do not have expiring lease terms. However, if
the combination of high drilling and development and low prices continues this will cause us to defer or even abandon these potential drilling projects. We are high-grading drilling locations and have scheduled the drilling of the first five wells.
Additional drilling is expected to be scheduled as prices stabilize and drilling costs decline. The Olson 1-21, was recently drilled and completed in Roger Mills County to an approximate total depth of 13,800 feet. We have a 26.67% working interest
in this new productive well.
Quarantine Bay Field
(also discussed above) — Including 939 gross and 329 net acres acquired in
January 2009, we hold 14,535 gross and 1,281 net acres above 10,500 feet and 5,214 net acres below that depth. Upside in this field consists of numerous behind-pipe opportunities due to the multiple stacked sand reservoirs, along with proved
undeveloped and rate acceleration locations in the section above 10,500 feet. In addition, we believe deeper exploration potential exists. We have a 33% working interest in the field, with a 24.75% net revenue interest below 10,500 feet. In
cooperation with the operator, we acquired 35 square miles of 3-D seismic data to image and define prospect leads primarily below 10,500 feet. Schlumberger was engaged to reprocess the 3-D seismic data and provide initial interpretive geological and
geophysical services. Geophysical and subsurface evaluation is continuing and we have isolated several prospects, the majority of which are on acreage that is held by production operations. At least one exploration well with multiple objectives
below 10,500 feet is expected to be drilled in 2009, pending commodity prices and estimated drilling costs.
27
RipRap Coulee Field
— This field is a Bakken Shale play in eastern Montana. It involves
horizontal drilling at vertical depths of about 10,000 feet. Currently, we own 997 gross and 498 net leasehold acres in this prospect.
Roth-Leonard Fields
— These fields are located in Bottineau County, North Dakota. The fields produce from the same Mississippian Madison stratigraphic porosity as the Sherman and Wayne Fields and have similar water production
and pressure histories indicating that they are also horizontal infill drilling candidates (see “Sherman/Wayne Fields” below). We hold 1,374 gross and 1,353 net acres. We have a 100% working interest and 84.9% net revenue interest.
Sherman/Wayne Fields
(also discussed above) — We hold 1,090 gross and 967 net acres and operate the field. All of the wells
are on rod pump with seven of the wells being horizontal producers. Upside, in this field, consists of two proved undeveloped horizontal infill locations. We drilled two horizontal locations in 2008 and established commercial production. Further
upside potential from horizontal drilling could result if we are able to unitize acreage with adjacent leases.
St. Martinville Field
(also discussed above) — The field has produced over 14 million barrels of oil at depths ranging from 3,000 feet to 9,500 feet since its discovery several decades ago, and has not been evaluated with a modern 3-D survey. We hold 1,322
gross and 1,283 net acres in the field. A successful well was drilled in late 2005 to a depth of 4,700 feet that initially flowed over 100 Bbls/d, is still producing 30 Bbls/d and has several behind-pipe zones. One additional well is presently
budgeted. A 3-D seismic survey is in process with interpretation to begin in the second half of 2009.
Starbuck and Southwest Starbuck
Fields
(also discussed above) — The Starbuck field was unitized effective November 1, 2007, and includes 6,619 gross and 6,354 net acres. We immediately began our waterflood installation and have a 96% working interest and 83% net
revenue interest. Phase one, including four injection wells, water plant and flow lines, was completed in early 2008, when initial water injection began. As a result of the recent increase in the Starbuck Madison Unit production, which is believed
to be initial secondary recovery response, phase two of the three phase capital plan was initiated and completed in March 2009. Using our base case, we estimate 1.4 million Bbls recoverable with a development cost of approximately $4.00 to
$5.00 per barrel. Recoverable reserve estimates range from 1.0 million Bbls to 2.4 million Bbls. The flood design includes two productive zones, the Midale (Mississippian Charles) and the Berentson (Mississippian Charles B-1) zone, which
are being flooded separately. The Starbuck Midale has produced 584,000 barrels of oil and the Berentson has produced 754,000 barrels on primary recovery, for total field production of 1,267,000 barrels of oil. Fourteen gross wells are still
producing. The flood installation has been designed to capture and accelerate recovery of existing primary reserves, as well as capture incremental water flood reserves. At the adjacent Southwest Starbuck Field, we have completed Phase One of the
water flood plan which included drilling one injection well and installing a water plant and flow lines. Initial water injection commenced in mid-January, 2009. The plant and flow lines will also serve the south end of the Starbuck Madison Unit. The
initial flood design includes 560 gross acres where we have a 97.52% working interest and a 75.42% net revenue interest. We estimate that an incremental 170,000 Bbls are recoverable, net to our interest.
Title to Properties
It is customary
in the oil and gas industry to make a limited review of title to undeveloped oil and gas leases at the time they are acquired. It is also customary to obtain more extensive title examinations prior to the commencement of drilling operations on
undeveloped leases or prior to the acquisition of producing oil and gas properties. With respect to the future acquisition of both undeveloped and proved properties, we plan to conduct title examinations on such properties in a manner consistent
with industry and banking practices. We have obtained title opinions, title reports or otherwise conducted title investigations covering substantially all of our producing properties and believe we have satisfactory title to such properties in
accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, overriding royalty interests, and other burdens which we believe do not materially interfere with the use or affect
the value of such properties. Substantially all of our oil and gas properties are and may continue to be mortgaged to secure borrowings under bank credit facilities (see Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations – Liquidity and Capital Resources”).
28
|
Item 3.
|
Legal Proceedings
|
We are not party
to, nor any of our properties subject to, any material pending legal proceedings. We know of no material legal proceedings contemplated or threatened against us.
|
Item 4.
|
Submission of Matters to a Vote of Security Holders
|
Our Annual Meeting of Stockholders was held on October 30, 2008. The items of business noticed and transacted at the meeting were:
|
|
•
|
|
The election of seven nominees to serve on our Board of Directors and until our next Annual Meeting of Stockholders.
|
The vote tabulation with respect to each nominee was as follows:
|
|
|
|
|
|
|
|
|
Shares
Voted For
|
|
Shares
Withheld
|
|
Frank A. Lodzinski
|
|
15,058,749
|
|
185,985
|
|
Collis P. Chandler, III
|
|
15,056,749
|
|
187,985
|
|
Christopher W. Hunt
|
|
14,940,202
|
|
304,532
|
|
Jay F. Joliat
|
|
14,744,860
|
|
499,874
|
|
Scott R. Stevens
|
|
14,752,023
|
|
492,711
|
|
Michael A. Vlasic
|
|
15,059,749
|
|
184,985
|
|
Nicholas L. Voller
|
|
15,050,414
|
|
194,320
|
Each nominee was elected to continue to serve on our Board of Directors. There
were not any solicitations in opposition to our nominees.
29
PART II
|
Item 5.
|
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
Our common stock trades on the NASDAQ Global Market under the Symbol “GEOI.” The following tables set forth for the period
indicated the low and high trade prices for our common stock as reported by the NASDAQ Capital Market. These trade prices may represent prices between dealers and do not include retail markup, markdowns or commissions.
|
|
|
|
|
|
|
|
|
|
|
High
|
|
Low
|
|
2008
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$
|
15.29
|
|
$
|
5.61
|
|
Third Quarter
|
|
$
|
20.74
|
|
$
|
9.62
|
|
Second Quarter
|
|
$
|
29.08
|
|
$
|
14.51
|
|
First Quarter
|
|
$
|
15.35
|
|
$
|
8.00
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$
|
9.68
|
|
$
|
6.62
|
|
Third Quarter
|
|
$
|
7.13
|
|
$
|
5.60
|
|
Second Quarter
|
|
$
|
7.64
|
|
$
|
6.01
|
|
First Quarter
|
|
$
|
6.97
|
|
$
|
5.40
|
As of March 20, 2009, there were approximately 600 holders of record of our
common stock. We believe that there are also approximately 3,000 additional beneficial owners of our common stock held in “street name.”
Dividend Policy
Amounts shown in our historical financial statements as stockholder distributions in 2006
and 2007 are comprised of distributions by Southern Bay to its partners.
We have never paid dividends on our common stock
and do not intend to pay a dividend in the foreseeable future. Furthermore, our amended credit agreement with our bank restricts the payment of cash dividends. The payment of cash future dividends on common stock, if any, will be reviewed
periodically by our Board of Directors and will depend upon, among other things, our financial condition, funds available for operations, the amount of anticipated capital and other expenditures, our future business prospects and any restrictions
imposed by our present or future bank credit arrangements.
30
Equity Compensation Plan Information
The following sets forth information as of March 25, 2009, concerning our compensation plan under which shares of our common stock are authorized for issuance.
|
|
|
|
|
|
|
|
|
|
PLAN CATEGORY
|
|
NUMBER OF SECURITIES TO
BE ISSUED UPON
EXERCISE
OF OUTSTANDING OPTIONS,
WARRANTS AND RIGHTS
|
|
WEIGHTED AVERAGE
EXERCISE PRICE OF
OUTSTANDING OPTIONS,
WARRANTS AND RIGHTS
|
|
NUMBER OF SECURITIES
REMAINING AVAILABLE
FOR FUTURE ISSUANCE
|
|
Equity compensation plans approved by security holders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amended and Restated 2004 Employees’ Stock Incentive Plan
|
|
2,000,000
|
|
$
|
9.39
|
|
690,000
|
|
|
|
|
|
|
Equity compensation plans not approved by security holders:
|
|
N/A
|
|
|
N/A
|
|
N/A
|
In 2007, employee options exercised totaled 35,208 shares at $2.37 and 40,500
shares at $2.31. There were not any employee options exercised during 2008.
31
|
Item 6.
|
Selected Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
A. Summary of Operating Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbls)
|
|
|
743
|
|
|
392
|
|
|
184
|
|
|
Natural gas (MMcf)
|
|
|
2,962
|
|
|
1,648
|
|
|
577
|
|
|
Barrel of oil equivalent (MBOE)
|
|
|
1,236
|
|
|
667
|
|
|
280
|
|
|
Average realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per bbl)
|
|
$
|
82.42
|
|
$
|
67.20
|
|
$
|
54.61
|
|
|
Natural gas (per Mcf)
|
|
$
|
8.12
|
|
$
|
6.19
|
|
$
|
6.83
|
|
|
|
|
|
|
|
B. Summary of Operations
(in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
|
$
|
85,263
|
|
$
|
36,518
|
|
$
|
13,978
|
|
|
Total other revenues
|
|
|
9,343
|
|
|
3,597
|
|
|
2,827
|
|
|
Lease operation and workover expenses
|
|
|
26,432
|
|
|
12,910
|
|
|
4,636
|
|
|
Severance taxes
|
|
|
7,517
|
|
|
2,880
|
|
|
1,066
|
|
|
Depletion and depreciation
|
|
|
16,007
|
|
|
7,507
|
|
|
3,382
|
|
|
Pretax earnings
|
|
|
21,291
|
|
|
7,949
|
|
|
4,280
|
|
|
Income tax expense (1)
|
|
|
7,769
|
|
|
4,880
|
|
|
33
|
|
|
Net earnings (loss)
|
|
|
13,522
|
|
|
3,069
|
|
|
4,247
|
|
|
Net earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.87
|
|
$
|
0.25
|
|
$
|
0.87
|
|
|
Diluted
|
|
$
|
0.86
|
|
$
|
0.25
|
|
$
|
0.87
|
|
|
|
|
|
|
|
C. Summary Balance Sheet Data at Year End
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
181,580
|
|
$
|
181,443
|
|
$
|
31,229
|
|
|
Total assets
|
|
|
243,534
|
|
|
240,358
|
|
|
50,667
|
|
|
Working capital
|
|
|
11,883
|
|
|
7,371
|
|
|
(1,689
|
)
|
|
Long-term debt
|
|
|
40,000
|
|
|
96,000
|
|
|
5,000
|
|
|
Stockholder’s equity
|
|
|
140,995
|
|
|
68,032
|
|
|
23,660
|
|
|
(1)
|
The 2006 consolidated financial statements were those of Southern Bay, which, as a partnership, was generally not subject to federal and state income taxes.
|
32
|
Item 7.
|
Management’s Discussion and Analysis of Financial Conditions and Results of Operations
|
The following discussion should be read in conjunction with the consolidated financial statements and related notes thereto reflected in
the index to the consolidated financial statements in this report.
Merger – Change in Management, Control and Business Strategy
As discussed elsewhere in this report, we underwent a substantial change in ownership, management, voting control, assets and business
strategy as a result of the acquisition of Southern Bay and Chandler (via the Merger) and a purchase of working interests in a Chandler-operated project, which closed in April 2007. For financial reporting purposes, the Merger was accounted for as a
reverse acquisition of GeoResources, Inc. by Southern Bay. Therefore, the results of operations and cash flows presented herein for the year ended December 31, 2008, are those attributable to the combined entities. The results of operations and
cash flows for the year ended December 31, 2007, are those attributable to the former Southern Bay entity for the entire twelve months and those of the combined entity for the period from April 18, 2007, through December 31, 2007. The
results of operations and cash flows for the year ended December 31, 2006, are those attributable to the former Southern Bay entity.
General
We are an independent oil and gas company engaged in the acquisition and development of oil and gas reserves through an
active and diversified program which includes purchases of reserves, re-engineering, development, and exploration activities. As further discussed in this report, future growth in assets, earnings, cash flows and share values will be dependent upon
our ability to effectively compete for capital and acquire, discover and develop commercial quantities of oil and gas reserves that can be produced at a profit, and assemble an oil and gas reserve base with a market value exceeding its acquisition,
development and production costs.
We continue to implement our business strategy to acquire, discover and develop oil and
gas reserves and achieve continued growth. Management continues to focus on reducing operating and administrative costs on a per unit basis. In addition, we have attempted to mitigate downward price volatility by the use of commodity price hedging.
The current volatile price environment for oil and natural gas is significant, and management cannot predict the prices that will be available during the life of our current business plan. Following is a brief outline of our current plans:
|
|
•
|
|
Acquire oil and gas properties with significant producing reserves and development and exploration potential;
|
|
|
•
|
|
Solicit industry partners in acquisitions, on a promoted basis, in order to diversify, reduce average cost and generate operating fees;
|
|
|
•
|
|
Implement re-engineering and development programs within existing fields;
|
|
|
•
|
|
Pursue exploration projects and increase direct participation in projects over time. Solicit industry partners, on a promoted basis, for internally generated
projects;
|
|
|
•
|
|
Selectively divest assets to upgrade our producing property portfolio and to lower corporate wide “per-unit” operating and administrative costs, and
focus on existing fields and new projects with greater development and exploitation potential;
|
|
|
•
|
|
Continue activities directed toward reducing per-unit operating and general and administrative costs on a long-term sustained basis; and
|
|
|
•
|
|
Obtain additional capital through the issuance of equity securities and/or through debt financing.
|
While the impact and success of our corporate plans cannot be predicted with accuracy, our goal is to replace production and further
increase our reserve base at an acquisition or finding cost that will yield attractive rates of return.
In addition to our
fundamental business strategy, we intend to actively pursue corporate acquisitions and mergers. Management believes that opportunities may become available to acquire corporate entities or otherwise effect business combinations, particularly as a
result of recent lower commodity prices and the contraction in equity and debt financing markets. We intend to consider any such opportunities which may become available and are beneficial to stockholders. The primary financial considerations in the
evaluation of any such potential transactions
33
include, but are not limited to: (1) the ability of small cap oil and gas companies to gain recognition and favor in the public markets; (2) share
appreciation potential; (3) shareholder liquidity; and (4) capital formation and cost of capital to effect growth.
Recent Property
Acquisitions and Divestitures
During 2008, we expanded our acreage positions and drilling inventory, implemented our
drilling programs, and began the process of high-grading the assets resulting from the Merger and significant acquisitions of 2007. We sold or abandoned certain properties which, collectively had net production at the time of sale of 316 Bbls/d and
742 Mcfe/d, but were outside our focus areas, had limited development potential, short remaining productive lives, high maintenance requirements or significant plugging and abandonment obligations. We also acquired producing and undeveloped
properties, principally in the Williston Basin and in Oklahoma. A summary of this activity is as follows:
|
|
•
|
|
In January, 2008, we sold all of our interest in the Grand Canyon Unit, a property acquired in the Merger. This property, located in Otsego County, Michigan, was
sold to an unaffiliated party for $6.6 million in cash. At the date of sale, the carrying value of this property was equal the sales price; therefore, no gain or loss was recognized on the sale.
|
|
|
•
|
|
In February, 2008, we acquired producing properties from an unaffiliated party in the Williston Basin of North Dakota and Montana for $7.9 million cash. The
acquired properties are operated by us.
|
|
|
•
|
|
In February, 2008, we sold our interests in certain non-core oil and gas properties located in Louisiana to unaffiliated parties for $1.8 million and recognized
gains of $430,000.
|
|
|
•
|
|
In May, 2008, we sold seven non-core fields in Louisiana and Texas for approximately $11.8 million. We recognized a net gain of $1.5 million related to these
sales.
|
|
|
•
|
|
In May, 2008, Catena Oil & Gas LLC (“Catena”), a wholly-owned subsidiary, participated in the formation of OKLA Energy Partners LP
(“OKLA”) in order to acquire certain producing oil and gas properties and undeveloped acreage located throughout Oklahoma. The acquisition totaled $61.7 million. Catena directly purchased 18% of the interests and OKLA purchased the
remaining 82%. Catena, the general partner for OKLA, has a 2% partnership interest. Under the terms of the partnership agreement, Catena’s general partner interest can increase to approximately 36% pending certain performance hurdles.
|
|
|
•
|
|
In September, 2008, we acquired producing properties in Oklahoma from an unaffiliated party for $3.6 million in cash.
|
|
|
•
|
|
During 2008, we identified an exploration opportunity in the Paradox Basin and began leasing in Colorado and Utah targeting the Gothic shale as a newly emerging
resource play with multiple objectives. In the fourth quarter of 2008, we sold a majority of our interest for $6 million and recognized a gain of $2.5 million. We retained an option to participate, up to a 12.5% working interest, in any future
drilling on the acreage.
|
34
Results of Operations
Year ended December 31, 2008, compared to the year ended December 31, 2007.
We recorded net
income of $13,522,000 and $3,069,000 for the years ended December 31, 2008, and 2007, respectively. The $10,453,000 increase in net income resulted primarily from the following factors.
|
|
|
|
|
|
|
Net amounts contributing to increase (decrease) in net income (in 000s):
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
48,745
|
|
|
Lease operating expenses
|
|
|
(12,096
|
)
|
|
Production taxes
|
|
|
(4,637
|
)
|
|
Exploration expense
|
|
|
(2,439
|
)
|
|
Re-engineering and workovers
|
|
|
(1,426
|
)
|
|
Impairment of oil and gas properties
|
|
|
(8,339
|
)
|
|
General & administrative expense (G&A)
|
|
|
(655
|
)
|
|
Depletion, depreciation and amortization expenses (DD&A)
|
|
|
(8,500
|
)
|
|
Net interest income (expense)
|
|
|
(3,283
|
)
|
|
Hedge ineffectiveness
|
|
|
410
|
|
|
Gain / (loss) on derivative contracts
|
|
|
(563
|
)
|
|
Gain / (loss) on sale of property
|
|
|
4,313
|
|
|
Other income—net
|
|
|
1,812
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
13,342
|
|
|
Provision for income taxes
|
|
|
(2,889
|
)
|
|
|
|
|
|
|
|
Net increase
|
|
$
|
10,453
|
|
|
|
|
|
|
|
The following discussion applies to the above changes.
Oil and Natural Gas Sales
. Net revenues from oil and gas sales increased $48,745,000, or 133%. Properties acquired from AROC Energy
LP in October 2007, accounted for approximately $41,182,000 of the increase. The remaining $7,563,000 increase resulted primarily from an increase in commodity prices and increase in production volumes. Price and production comparisons are set forth
in the following table. Properties acquired from AROC Energy LP accounted for increased production of approximately 1,063,000 Mcf of gas and approximately 789,000 barrels of oil during 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent
increase
(decrease)
|
|
|
Year Ended
December 31,
|
|
|
|
2008
|
|
2007
|
|
Gas Production (MMcf)
|
|
80
|
%
|
|
|
2,962
|
|
|
1,648
|
|
Oil Production (MBbl)
|
|
90
|
%
|
|
|
743
|
|
|
392
|
|
Barrel of Oil Equivalent (MBOE)
|
|
85
|
%
|
|
|
1,236
|
|
|
667
|
|
Average Price Gas Before Hedge Settlements (per Mcf)
|
|
27
|
%
|
|
$
|
8.36
|
|
$
|
6.56
|
|
Average Price Oil Before Hedge Settlements (per Bbl)
|
|
30
|
%
|
|
$
|
94.88
|
|
$
|
73.06
|
|
Average Realized Price Gas (per Mcf)
|
|
31
|
%
|
|
$
|
8.12
|
|
$
|
6.19
|
|
Average Realized Price Oil (per Bbl)
|
|
23
|
%
|
|
$
|
82.42
|
|
$
|
67.20
|
Lease Operating Expenses
. Our lease operating expenses increased from
approximately $10,818,000 for the year ended December 31, 2007 to $22,914,000 for 2008, an increase of $12,096,000 or 112%. Properties acquired from AROC Energy LP accounted for $9,146,000 of the increase. On a unit-of-production basis, barrel
of oil equivalent (“BOE”) costs increased by $2.32 or 14% as a result of higher costs due to unprecedented demand for personnel, materials, services and rigs caused by high commodity prices during most of 2008.
35
Re-engineering and workover
. Our re-engineering and workover costs increased by
$1,426,000 from $2,092,000 in 2007 to $3,518,000 in 2008, due to an increased emphasis on restoring and enhancing existing production capabilities.
Production Taxes
. Our production taxes increased by $4,637,000 or 161%, due to increased production volumes and revenues. The production taxes we pay are generally calculated as a percentage of oil and natural
gas sales revenue before the effects of hedging. We take full advantage of all credits and exemptions allowed in our various jurisdictions. Our production taxes for 2008 and 2007 were 7.9% and 7.3%, respectively, of oil and gas sales before the
effects of hedging. The 2008 rate increased slightly from 2007 mainly due to change in our portfolio of producing properties.
Exploration and Impairment Costs
. Our exploration costs were $2,592,000 for the year ended December 31, 2008, and $153,000 for the year ended December 31, 2007. In 2008, we drilled four gross exploratory dry holes with
costs incurred through December 31, 2008, of $1,948,000, wrote-off undeveloped properties with a cost of $483,000 and incurred geological costs of $161,000. In 2007, we incurred $153,000 for geological and geophysical data. In 2008, we recorded
a non-cash impairment charge of $8,339,000 due to the write-down of proved properties. The book value of these properties exceeded our estimate of future cash flows based on our current view of future commodity prices. We had no impairments in 2007.
General and Administrative Expenses
- Our G&A costs increased $655,000 due primarily to overall business
expansion as well as increases in salaries and other overhead expenses, partially offset by cost reductions resulting from the centralization of certain job functions.
Depreciation, Depletion and Amortization
- The increase in DD&A expenses attributable to the properties acquired from AROC Energy LP was $5,618,000. The remaining increase of
$2,882,000 was due to higher DD&A in the fourth quarter of 2008 due to lower reserve estimates at year-end, which was caused by lower commodity prices.
Interest Income and Expense
- Interest expense increased by $2,904,000 due to higher average debt levels during the year ended December 31, 2008, compared to 2007. During the first
ten months of 2007, the Company had a long-term debt balance of less than $10 million. In October, 2007, the Company borrowed $96 million in conjunction with the AROC Energy LP acquisition. During 2008, the Company paid down this balance to $40
million. Interest income decreased by $379,000 during the year ended December 31, 2008, compared to 2007, due to lower interest rates on average invested cash balances.
Hedge Ineffectiveness
. During the year ended December 31, 2008, the gain from hedge ineffectiveness was $123,000, compared to an expense of $287,000 for 2007. In 2008, our derivatives
that are accounted for as cash flow hedges increased in value from a net liability to a net asset; therefore, the ineffective portion of these derivatives resulted in a gain on our income statement. In 2007, our derivatives that were accounted for
as cash flow hedges decreased in value. Therefore, the ineffective portion of the derivatives resulted in a loss on our income statement.
Loss on Derivative Contracts
. In December, 2008, we split up a $50 million notional value interest rate swap that was previously accounted for as a cash flow hedge. The swap was split up into a $10 million swap
and $40 million notional amount swap. We continued hedge accounting for the $40 million swap and accounted for the $10 million swap as a trading security. We recognized $563,000 of losses related to this $10 million interest rate swap.
Other Income
. Other income increased by $1,812,000 during the year ended December 31, 2008, compared to 2007. The increase
resulted from increases in partnership management fees of $756,000, increases in partnership income of $877,000 and increases in property operating income of $179,000. Additionally, during 2008, we sold a number of non-core properties and recognized
a gain of $4,362,000 versus gains of only $49,000 in 2007.
Income Tax Expense
. Our provision for income taxes for
the year ended December 31, 2008, was $7,769,000 compared to $4,880,000 for 2007. Our income tax expense increased significantly as a result of higher pre-tax earnings. Our effective tax rate for 2008 was approximately 36.5%. Our effective tax
rate for 2007, after
36
excluding a non-recurring charge of $2,214,000, was approximately 34%. As previously stated, the 2006 consolidated financial statements, as presented herein,
are those of Southern Bay which, as a partnership, was generally not subject to federal and state income taxes. Deferred income tax expense for 2007 included a non-recurring charge of $2,214,000. GAAP requires that when an entity’s tax status
changes from non-taxable to taxable, the deferred taxes related to differences in the GAAP basis of net assets and their tax basis, be recognized in the period of that change in status. The increase in our effective tax rate from year to year was
due to a 1% increase in our federal rate as well as the additional income from our Northern Region which is taxable at the state level.
Year ended
December 31, 2007, compared to the year ended December 31, 2006.
We recorded net income of $3,069,000 and
$4,247,000 for the years ended December 31, 2007, and 2006, respectively. The $1,178,000 decrease in net income resulted primarily from the following factors:
|
|
|
|
|
|
|
Net amounts contributing to increase (decrease) in net income (in 000s):
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
22,540
|
|
|
Lease operating expenses
|
|
|
(6,566
|
)
|
|
Production taxes
|
|
|
(1,814
|
)
|
|
Exploration expense
|
|
|
405
|
|
|
Re-engineering and workovers
|
|
|
(1,708
|
)
|
|
Impairment of oil and gas properties
|
|
|
184
|
|
|
General & administrative expense (G&A)
|
|
|
(3,709
|
)
|
|
Depletion, depreciation and amortization expenses (DD&A)
|
|
|
(4,125
|
)
|
|
Net interest income (expense)
|
|
|
(1,549
|
)
|
|
Hedge ineffectiveness
|
|
|
(680
|
)
|
|
Gain / (loss) on sale of property
|
|
|
(286
|
)
|
|
Other income—net
|
|
|
977
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
3,669
|
|
|
Provision for income taxes
|
|
|
(4,847
|
)
|
|
|
|
|
|
|
|
Net increase
|
|
$
|
(1,178
|
)
|
|
|
|
|
|
|
Net revenues from oil and gas sales increase $22,540,000, or 161%. Properties
acquired in the AROC acquisition accounted for $11,043,000 of this increase and the Merger accounted for $8,066,000 of the increase. Higher prices, as well as the acquisition and development of properties during the year, accounted for the remaining
increase of $3,431,000. Properties acquired in the AROC acquisition accounted for increased production of approximately 374,000 Mcf of gas and approximately 91,000 barrels of oil. Properties acquired in the Merger accounted for increased production
of approximately 244,000 Mcf of gas and approximately 105,000 barrels of oil. Prices and production comparisons are set forth in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent
increase
(decrease)
|
|
|
Year Ended
December 31,
|
|
|
|
2007
|
|
2006
|
|
Gas Production (MMcf)
|
|
186
|
%
|
|
|
1,648
|
|
|
577
|
|
Oil Production (MBbl)
|
|
113
|
%
|
|
|
392
|
|
|
184
|
|
Barrel of Oil Equivalent (MBOE)
|
|
138
|
%
|
|
|
667
|
|
|
280
|
|
Average Price Gas Before Hedge Settlements (per Mcf)
|
|
(7
|
)%
|
|
$
|
6.56
|
|
$
|
7.03
|
|
Average Price Oil Before Hedge Settlements (per Bbl)
|
|
14
|
%
|
|
$
|
73.06
|
|
$
|
63.82
|
|
Average Realized Price Gas (per Mcf)
|
|
(9
|
)%
|
|
$
|
6.19
|
|
$
|
6.83
|
|
Average Realized Price Oil (per Bbl)
|
|
23
|
%
|
|
$
|
67.20
|
|
$
|
54.61
|
Lease Operating Expenses, Workover Costs and Production Taxes
. Our lease
operating expenses and workover costs increased $8,274,000. This increase was due primarily to properties acquired in the AROC acquisition and properties acquired in the Merger. On a unit-of-production basis, BOE costs increase 18%. The
37
increase was a result of the acquisition and development of oil and gas properties in 2007 and a high demand for personnel, materials, services and rigs
caused by high commodity prices. On a BOE basis, production volumes increase 138%. Accordingly, lease operating expenses increased primarily as a result of additional production volumes attributable to the AROC acquisition and to the Merger. Due to
increased production volumes and increased revenues, production taxes increased by $1,814,000 or 170%.
Exploration
Costs
. Exploration costs were $153,000 for the year ended December 31, 2007, and $558,000 for the year ended December 31, 2006. We drilled two unsuccessful exploratory wells in 2006 and none in 2007, but we spent $153,000 for
geological and geophysical data in 2007.
General and Administrative Expenses
. General and administrative costs
increased $3,709,000 due primarily to non-recurring costs associated with the Merger and consulting fees associated with the Merger and consulting fees associated with compliance with the Sarbanes-Oxley Act, as well as to overall business expansion
related to the Merger. Expenses associated with the Merger included bonus and stock-based compensation totaling $524,000, legal, accounting and proxy services of $295,000; and a NASDAQ listing fee of $95,000 for entry into the National Global
Market. In 2007, we also incurred fees and costs of $264,000 in connection with readiness for Sarbanes-Oxley compliance.
Depreciation, Depletion and Amortization.
The increase in DD&A expense attributable to the properties acquired in the Merger was $1,215,000. The remaining increase of $2,910,000 was due to the AROC acquisition, as well as
property acquisitions by Southern Bay prior to the Merger, partially offset by lower net capitalized costs on other properties.
Interest Income and Expense
. Interest expense increased by $1,628,000 due to high debt levels in 2007. In October, 2007, we borrowed $96 million to acquire the limited partner interest in the AROC acquisition. Interest on that debt
was $1,436,000 in 2007. Interest income increased $79,000 due to larger invested cash balances in 2007, as well as interest on notes receivable arising from the sale of non-core properties and equipment in 2007.
Hedge Ineffectiveness
. For 2007, loss from hedge ineffectiveness was $287,000 compared to a gain of $393,000 for 2006. This
difference of $680,000 resulted from an increase in the liability associated with the mark-to-market valuation of our hedge contracts. This increase was due to additional hedging in the fourth quarter of 2007, as well as to higher product prices in
2007 and continuing into 2008.
Other Income
. Other income, net of other expenses, increased by $977,000. This
increase was due to higher property operating income in 2007, partially offset by non-recurring income in 2006 resulting from reductions in contingent liabilities and allowance for bad debts.
Income Tax Expense
. Income tax expense for 2007 was $4,880,000 compared to $33,000 for 2006. As previously stated, the 2006
consolidated financial statements as presented herein are those of Southern Bay, which as a partnership, was generally not subject to federal and state income taxes. The small amount reflected as income tax expense for 2006 represents a Texas margin
tax which was calculated using gross revenue less certain deductions and was further reduced to reflect the percent of business derived from Texas. This tax is require by GAAP to be accounted for as an income tax at the entity level. In addition,
deferred income tax expense for 2007 included a non-recurring charge of $2,214,000. GAAP requires that when an entity’s tax status changes from non-taxable to taxable, the deferred taxes related to differences in the GAAP basis of net assets
and their tax basis, be recognized in the period of that change in status.
Hedging Activities
In an attempt to reduce our sensitivity to oil and gas price volatility and secure favorable debt financing, we have and will likely
continue to enter into hedging transactions which may include fixed price swaps, price collars, puts and other derivatives. We believe our hedging strategy should result in greater predictability of internally generated funds, which in turn can be
dedicated to capital development projects and corporate obligations. The following is a summary of our current oil and gas hedge contracts.
38
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Annual
Volume
|
|
Floor
Price
|
|
Ceiling /Swap Price
|
|
Crude Oil Contracts (Bbls):
|
|
|
|
|
|
|
|
|
|
Swap contracts:
|
|
|
|
|
|
|
|
|
|
2009
|
|
368,000
|
|
|
|
|
$
|
76.00
|
|
2010
|
|
322,000
|
|
|
|
|
$
|
74.71
|
|
2011
|
|
282,000
|
|
|
|
|
$
|
74.37
|
|
Forward sales contracts:
|
|
|
|
|
|
|
|
|
|
2009 (added Mar. 9, 09)
|
|
81,000
|
|
|
|
|
$
|
40.80
|
|
2010 (added Mar. 9, 09)
|
|
27,000
|
|
|
|
|
$
|
40.80
|
|
Natural Gas Contracts (Mmbtu)
|
|
|
|
|
|
|
|
|
|
Swap contracts:
|
|
|
|
|
|
|
|
|
|
2009 (added Feb. 26, 09)
|
|
450,000
|
|
|
|
|
$
|
4.86
|
|
2010 (added Feb. 26, 09)
|
|
150,000
|
|
|
|
|
$
|
4.86
|
|
Costless collars contracts:
|
|
|
|
|
|
|
|
|
|
2009
|
|
275,530
|
|
$
|
7.00
|
|
$
|
10.75
|
|
2010
|
|
1,287,000
|
|
$
|
7.00
|
|
$
|
9.90
|
|
2011
|
|
1,079,000
|
|
$
|
7.00
|
|
$
|
9.20
|
The fair market value of the hedge contracts in place at December 31, 2008,
was an asset of $14,609,000, of which $8,200,000 was classified as a current asset and $6,409,000 was classified as a long-term asset. Realized hedge settlements included in oil and gas revenues were costs of $9,970,000 and $2,910,000 for the years
ended December 31, 2008, and 2007, respectively. Due to hedge ineffectiveness on these hedge contracts during the years ended December 31, 2008, and 2007, we recognized a gain of $123,000 and a loss of $287,000, respectively.
Based on the estimated fair market value of our derivatives, designated as hedges at December 31, 2008, we expect to reclassify
net gains on commodity derivatives of $8.2 million into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.
At December 31, 2008, a 10% change in per unit commodity prices would cause the total fair value of our commodity derivative
financial instruments to increase by $10 to $12 million or decrease by $8 to $10 million with similar increases or decreases in other comprehensive income (loss) included in stockholders’ equity in the balance sheet. Since we have designated
all of our commodity derivative instruments as cash flow hedges and therefore the change in market value of the effective portion of the hedge is included in other comprehensive income, a 10% change in fair value would not have a significant effect
on net income. However, if our hedges did not qualify for hedge accounting treatment, our net income for 2008 would have increased by $20.5 million.
Additionally, should commodity prices increase or decrease in the future periods by 10%, our realized settlement gains (losses) on commodity derivatives, which are included in oil and gas revenues, would increase or
decrease by approximately $3 to $4 million in 2009.
In connection with the borrowing from our bank to fund the October,
2007, AROC acquisition, we also entered into a two-year interest rate swap contract on $50 million of the debt, to protect us against interest rate increases. During 2008, we extended the term of this interest rate swap through October, 2010, and
broke the swap up into two pieces, a $40 million swap and a $10 million swap. We account for the $40 million swap as a cash flow hedge while the $10 million swap is accounted for as a trading security. The value of these swaps is a liability of
$2,817,000 of which $1,572,000 is classified as a current liability. We also recognized a loss of $563,000 on the $10 million swap.
39
Based on the estimated fair market value of our derivatives designated as hedges at
December 31, 2008, we expect to reclassify net losses on our $40 million interest rate swap derivative of $1.3 million into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlements may
differ materially.
We do not engage in speculative trading activities and do not hedge all available or anticipated
quantities of our production. In implementing our hedging strategy we seek to:
|
|
•
|
|
Effectively manage cash flow to minimize price volatility and generate internal funds available for capital development projects and additional acquisitions;
|
|
|
•
|
|
Ensure our ability to support our exploration activities as well as administrative and debt service obligation; and
|
|
|
•
|
|
Allow certain quantities to float, particularly in months with historically increased price potential.
|
We believe that speculation and trading activities are inappropriate for us, but also that management of realized prices is a necessary
part of our strategy.
Estimating the fair value of derivative instruments requires complex calculations, including the use
of a discounted cash flow technique, estimates of risk and volatility, and subjective judgment in selecting an appropriate discount rate. In addition, the calculations use future market commodity prices, which although posted for trading purposes,
are merely the market consensus of forecasted price trends. The results of the fair value calculation cannot be expected to represent exactly the fair value of our commodity hedges. We currently obtain fair value positions from our counterparties
and compare that value to our internally calculated value. Our practice of comparing our value to that of our counterparties, who are more specialized and knowledgeable in preparing these complex calculations, reduces our risk of error and
approximates the fair value of the contracts, as the fair value obtained from our counterparties would be the cost to us to terminate a contract at that point in time.
Administrative and Operating Costs
On an ongoing basis, we focus on cost-containment
efforts related to administrative and operating costs. However, we must continue to attract and retain competent management, technical and administrative personnel to successfully pursue our business strategy and fulfill our contractual obligations.
Liquidity and Capital Resources
We expect to finance future acquisition, development and exploration activities through working capital, cash flows from operating activities, our bank credit facility, sale of non-strategic assets, various means of
corporate and project finance and possibly through issuance of additional securities. In addition, we intend to continue to partially finance our drilling activities through the sale of participations to industry or institutional partners on a
promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate capital costs. Financing activities during 2008 have resulted in a net reduction of debt of $56 million from the outstanding debt of $96
million at December 31, 2007. During 2007, we borrowed an additional $3 million, assumed $1.8 million of debt in the Merger, and repaid the entire balance outstanding of our bank debt of $9.8 million in late June, 2007. In October, 2007, we
borrowed $96 million to finance the AROC Energy LP acquisition. During the first quarter of 2008, we repaid $10 million in debt using cash flows from operations. During the second quarter, we completed a private placement of common stock and
warrants to acquire common stock and used the net proceeds of $32 million plus cash flows from operations to reduce our debt by an additional $36 million. In the fourth quarter, we repaid $10 million in debt using cash flows from operations.
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
(Millions)
|
|
|
Balances Outstanding, beginning of year
|
|
$
|
96.0
|
|
|
$
|
5.0
|
|
|
$
|
0.1
|
|
|
Borrowings
|
|
|
—
|
|
|
|
99.0
|
|
|
|
7.0
|
|
|
Assumption of debt in Merger
|
|
|
—
|
|
|
|
1.8
|
|
|
|
—
|
|
|
Repayments of debt
|
|
|
(56.0
|
)
|
|
|
(9.8
|
)
|
|
|
(2.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances Outstanding, end of year
|
|
$
|
40.0
|
|
|
$
|
96.0
|
|
|
$
|
5.0
|
|
|
Issuance of common stock
|
|
$
|
32.2
|
|
|
$
|
23.5
|
|
|
$
|
—
|
|
|
Distributions to stockholders (1)
|
|
$
|
—
|
|
|
$
|
(4.0
|
)
|
|
$
|
(1.0
|
)
|
|
(1)
|
The amount shown as stockholder distributions in 2007 and 2006 are comprised of distributions by Southern Bay to its partners prior to the Merger.
|
Credit Facility
At December 31, 2008, we had a $100 million borrowing base, with available borrowing capacity of $60 million in accordance with our Amended Credit Agreement with our bank. The borrowing base is redetermined in
October and April of each year. On March 13, 2009, in connection with the borrowing base redertermination for April 2009, the Company was advised by its lead bank that it will recommend that the $100 million borrowing base be extended to the
next redetermination. Approval is required by the bank group and its presently expected in early April.
Cash Flows From Operating Activities
For 2008, net cash provided by operating activities was $42.3 million, up $21.5 million from 2007. This increase was
directly attributable to the increase in production resulting from acquisition and development activities and increases in oil and gas prices, partially offset by increased general and administrative expense associated with operating a larger
company.
Cash Flows From Investing Activities
Cash applied to oil and gas capital expenditures was $51.8 million for 2008, $110.1 million for 2007, and $14.7 million for 2006. In 2008, we realized cash of $26.8 million from the sale of non-core properties. In
2007, we collected $2.4 million from the sale of non-core properties. During 2008, we invested $978,000 in a newly formed oil and gas limited partnership for which we are the general partner. In 2007, we invested $1.6 million in a different oil and
gas limited partnership for which we are also the general partner.
Capital Budget
In early 2008, we developed and reported a two year capital budget totaling $61.5 million. As the year progressed we expanded our
portfolio of projects, including both new and expanded projects. The projects were also modified based on performance and the effects of our acquisition and divestiture activities. The overall regional focus and profile of our portfolio remained
consistent with our business strategy. In anticipation of increasing our capital spending, commensurate with our then current level of cash flows and profitability due to historically high commodity prices, in the third quarter of 2008, we updated
our projected expenditures for the detailed review of our management and Board of Directors. While our intent, at that time, was to formally plan to increase our capital spending, the rapid and significant reductions in commodity prices caused us to
re-evaluate and in some cases, re-direct our capital spending. The table below is presented simply to disclose the nature and diversity of opportunities currently in our portfolio. However, considering the current commodity prices, we now expect to
return to our original capital budget and spend approximately $60 to $64 million over the course of 2009 and 2010. The remaining $19 to $23 million presented below are for projects that we anticipate undertaking in the near future; however,
considering the significant volatility in commodity prices we have not yet set a date certain for
41
the projects. These deferred projects are largely held by production and most can be deferred without exposure to lease expiration under present operating
conditions. Our current estimate of $60 to $64 million is predicated on prices equal to or better than the NYMEX forward curve, our hedge positions, reasonable success once the projects are undertaken and costs that are consistent with our
estimates. However, we are committed to generally limiting our capital spending to the Company’s cash flows, although in certain limited circumstances, we may utilize our borrowing capacity for development or lease saving operations. We
absolutely will not use our borrowing capacity for exploratory drilling. Additionally, in the opinion of management, we have sufficient cash flows and liquidity to fulfill all lease obligations.
Inventory of Planned Exploration and Development Projects
|
|
|
|
|
|
|
|
($ Millions)
|
|
Southern District
|
|
|
|
|
Austin Chalk drilling and development (1) (2)
|
|
$
|
6.2
|
|
Other development drilling (2)
|
|
|
14.8
|
|
Waterflood expansion
|
|
|
1.3
|
|
Exploratory drilling (3)
|
|
|
8.2
|
|
Re-engineering (4)
|
|
|
4.1
|
|
Acreage, seismic and other (5)
|
|
|
6.4
|
|
Northern District
|
|
|
|
|
Horizontal development drilling (2) (6)
|
|
|
11.0
|
|
Other development drilling (2)
|
|
|
9.8
|
|
Waterflood and associated drilling
|
|
|
4.7
|
|
Bakken Shale drilling (7)
|
|
|
12.7
|
|
Re-engineering (4)
|
|
|
1.0
|
|
Acreage, seismic and other (5)
|
|
|
2.8
|
|
|
|
|
|
|
Total
|
|
$
|
83.0
|
|
|
|
|
|
Notes
:
|
(1)
|
Continuation of an ongoing horizontal drilling and development program with an affiliated institutional partnership. We believe we can spud a new well every
60-75 days, utilizing one rig for a 3-4 year period. At present, we believe we have at least 15 drilling locations, the majority of which are expected to be dual laterals. The dual lateral configuration reduces the number of wells but also increases
reserve recoveries and favorably impacts finding and development costs. In addition, without further significant declines in commodity prices and development costs, we expect to re-enter numerous well bores and extend existing laterals or drill
additional laterals. None of the possible reentries are included in the above table as all such opportunities are held by production and have no critical timing. We may consider deploying a second drilling rig as drilling costs come down.
|
|
(2)
|
Includes both proved undeveloped and non-proved reserve potential.
|
|
(3)
|
Principally South Louisiana and the Texas Gulf Coast.
|
|
(4)
|
Includes activities related to existing fields intended to enhance production and lower operating expenses. These expenditures include replacement, repairs or
additional flowlines, facilities, and/or compression as well as the modification of the down-hole lift method, recompletions and side-track drilling.
|
|
(5)
|
Potential expenditures associated with further expansion of acreage and prospect inventory generally within close proximity of our existing fields.
|
|
(6)
|
Includes eight horizontal development wells or additional lateral wells within existing fields where we have interests ranging from 66% to 100%.
|
|
(7)
|
Includes 20 wells operated by our joint venture partner where our working interest may range from 4% to 10%. This participating working interest varies based on
acreage contributed to the approved drilling units. It also includes numerous wells where our working interest is 1% or less. While not material financially, management has generally elected to participate in all such drilling within our focus area
primarily to collect valuable technical data related to the drilling operations and reservoir characteristics. Also, it includes one Bakken Shale test well in Montana that we presently hold a 50% working interest.
|
42
The table above does not include all contemplated projects or inventory in our portfolio
but is representative of the bulk of such activities. In summary, our drilling and development activities include diversified opportunities intended to develop reserves and increase production. The current exploration and development schedule
presented in the table above includes (i) 32 wells which have assigned proved undeveloped reserves and the potential for the development of non-proved reserves (excluding numerous smaller non-operated interest which may be developed);
(ii) seven exploratory test wells including two potentially high impact exploratory wells at Quarantine Bay, Plaquemines Parish, Louisiana; (iii) 20 Bakken Shale wells (excluding minor non-operated interests); (iv) water flood
installation and expansion opportunities; and (v) seismic and acreage expenditures intended to further expand our portfolio.
The budget, as well as the timing of expenditures, is subject to change as we re-evaluate alternative projects and further expand our portfolio. Further, because much of our opportunity is held by production we may shift our expenditures
between regions and projects (such as development versus exploration) in an attempt to maximize cash flow and take advantage of regional differences in net commodity prices and service costs. Furthermore, our budget may be accelerated or deferred,
pending commodity prices, drilling and service rig availability and cost and adequate staffing to effectively manage activities and control costs. Finally, certain expenditures may be deferred in favor of new opportunities.
We believe projected expenditures will result in increased production, cash flows and reserve value and will further expose us to
potential upside from exploration. We further believe any deferral of certain projects will not result in any material loss. Should we be unable to acquire new properties, capital expenditures associated with existing properties could be increased.
New Accounting Standards
On December 31, 2008, the SEC published the revised rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in existing oil and gas rules to
make them consistent with the petroleum resources management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include
nontraditional resources in reserves, the use of new technology to determine reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determining reserves. The pricing to be used in determining reserves
is a 12-month average price. We are required to comply with the amended disclosure requirement for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early
adoption is not permitted. We are currently assessing the impact that the adoption will have on our disclosures, operating results, financial position and cash flows.
In March, 2008, the FASB issued Statement No. 161,
Disclosure about Derivative Instruments and Hedging Activities – an amendment to FASB Statement No. 133
(“SFAS
161”). The adoption of SFAS 161 is not expected to have an impact our consolidated financial statements, other than additional disclosures. SFAS 161 expands interim and annual disclosures about derivative and hedging activities that are
intended to better convey the purpose of derivative use and the risks managed. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008.
In December, 2007, the FASB issued Statement No. 160,
Noncontrolling Interests in Consolidated Financial Statements – an
amendment of ARB No. 51
(“SFAS 160”). This statement amends ARB No. 51 and intends to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated
financial statements by establishing accounting and reporting standards on the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. SFAS 160 is effective for fiscal years, and interim periods, beginning on or
after December 15, 2008. The Company does not believe that this statement will have a material impact on its consolidated financial statements.
In December, 2007, the FASB issued Statement No. 141R,
Business Combinations
(“SFAS 141R”). SFAS 141R may have an impact on our consolidated financial statements when effective, but the nature
and magnitude of
43
the specific effects will depend upon the nature, terms, and size of the acquisitions that we consummate after the effective date. SFAS 141R establishes
principles and requirements for how the acquirer of a business recognizes and measures in its financial statements, the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also
provides guidance for recognizing and measuring goodwill acquired in business combinations and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of business combinations.
SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company intends to adopt SFAS 141R effective January 1, 2009, and apply its provisions prospectively.
In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement No. 159,
The Fair Value Option for
Financial Assets and Financial Liabilities
(“SFAS 159”). This new standard permits an entity to make an irrevocable election at specific election dates to measure most financial assets and financial liabilities at fair value. The fair
value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS 159 established presentation and disclosure
requirements intended to help financial statement users understand the effect of the entity’s election on earnings. SFAS 159 was effective as of the beginning of the first fiscal year beginning after November 15, 2007. We elected not to
adopt the fair value option provision allowed under SFAS 159.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial
statements. The preparation of these statements requires us to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at
the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather,
politics, global economics, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies is detailed in Note A to our consolidated financial statements. We have outlined below certain of these
policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.
Oil and Gas Properties
We use the
successful efforts method of accounting for oil and gas operations. Under this method, costs to acquire oil and gas properties, drill successful exploratory wells, drill and equip development wells, and install production facilities are capitalized.
Exploration costs, including unsuccessful exploratory wells, geological, geophysical as well as cost of carrying and retaining unproved properties are charged to operations as incurred. Depreciation, depletion and amortization (“DD&A”)
of the capitalized costs associated with proved oil and gas properties are computed using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively, as estimated by independent
petroleum engineers. Oil and gas properties are periodically assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group.
Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. Long-lived assets
committed by management for disposal are accounted for at the lower of cost or fair value, less cost to sell. All of our properties are located within the continental United States and the Gulf of Mexico.
Oil and Natural Gas Reserve Quantities
Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion, impairment of our oil and natural gas properties, and asset retirement obligations. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating
conditions. Reserve quantities and future cash flows included in this report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:
|
|
•
|
|
The quality and quantity of available data;
|
44
|
|
•
|
|
The interpretation of that data;
|
|
|
•
|
|
The accuracy of various mandated economic assumptions; and
|
|
|
•
|
|
The judgments of the persons preparing the estimates.
|
Our proved reserves information included in this report is based on estimates prepared by our independent petroleum engineers, Cawley, Gillespie & Associates, Inc. The independent
petroleum engineers evaluated 100% of our estimated proved reserve quantities and their related future net cash flows as of December 31, 2008. Estimates prepared by others may be higher or lower than our estimates. Because these estimates
depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. We continually make revisions to reserve estimates
throughout the year as additional information becomes available. We make changes to depletion rates, impairment calculations, and asset retirement obligations in the same period that changes to reserve estimates are made.
Depreciation, Depletion and Amortization (“DD&A”)
Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. If the estimates of total
proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and
produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.
Impairment of Oil and Gas Properties
We review the value of our oil and gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by
comparing the pretax future net undiscounted cash flows to the net book value at the end of each period. If the net capitalized cost exceeds undiscounted future cash flows, the cost of the property is written down to “fair value,” which is
determined based on expected future flows using discounted rates commensurate with the risks involved, using prices and costs consistent with those used for internal decision making. Different pricing assumptions or discount rates could result in a
different calculated impairment. We provide for impairments on significant undeveloped properties when we determine that the property will not be developed or a permanent impairment in value has occurred.
Asset Retirement Obligation
Our
asset retirement obligations (“AROs”) consist primarily of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration in
accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the
carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to
be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the
timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged
to expense through DD&A over the life of the oil and gas field.
Derivative Instruments and Hedging Activity
We periodically enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility. We use hedging
to help ensure that we have adequate cash flows to fund our capital programs and manage price risks and returns on some of our acquisitions and drilling programs. Our decision on the quantity and price at which we choose to hedge our production
is based, in part, on our view of current and future market
45
conditions. While the use of these hedging arrangements limits the downside risk of adverse price movements, they may also limit future revenues from
favorable price movements. We primarily utilize swaps and costless collars, which are placed with major financial institutions. The oil and natural gas reference prices of these commodity derivative contracts are based upon crude oil and
natural gas futures, which have a high degree of historical correlation with actual prices we receive. All derivative instruments are recorded on the consolidated balance sheet at fair value. Changes in the derivatives’ fair value are
recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the fair value gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the
hedge is effective and is reclassified to gain (loss) on oil and natural gas hedging activities line item in our consolidated statements of income in the period that the hedged production is delivered. Hedge effectiveness is measured quarterly
based on the relative changes in the fair value between the derivative contract and the hedged item over time.
Our
costless collars are valued based on the counterparty’s marked-to-market statements, which are validated by observable transactions for the same or similar commodity options using the NYMEX futures index. Our swaps are valued based on a
discounted future cash flow model. Our primary input for the model is the NYMEX futures index. Our model is validated by the counterparty’s marked-to-market statements. The discount rate used in determining the fair values of these instruments
includes a measure of nonperformance risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
Our results of operations each period can be impacted by our ability to estimate the level of correlation between future
changes in the fair value of the hedge instruments and the transactions being hedged, both at the inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and
location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that
affect these factors, many of which are beyond our control. If our derivative contracts would not qualify for cash flow hedge treatment, then our consolidated statements of income could include large non-cash fluctuations, particularly in
volatile pricing environments, as our contracts are marked to their period end market values.
The use of hedging
transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We evaluate the ability of our counterparties to perform at the inception of a hedging relationship and on a periodic
basis as appropriate.
Income Taxes and Uncertain Tax Positions
We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes.
We record deferred tax assets and liabilities to
account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely
than not that some portion or all of the deferred tax assets will not be realized, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions
are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). In July 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109
(“FIN 48”), which requires income tax positions to meet a more-likely-than-not recognition threshold to be recognized in
the financial statements. Under FIN 48, tax positions that previously failed to meet the more-likely-than-not threshold should be recognized in the first subsequent financial reporting period in which that threshold is met. Previously
recognized tax positions that no longer meet the more-likely-than-not threshold should be derecognized in the first subsequent financial reporting period in which that threshold is no longer met. Prior to 2007, we recorded contingent income tax
liabilities to the extent they were probable and could be reasonably estimated. We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax
laws and regulations in various taxing jurisdictions. If we ultimately determine that the payment of these liabilities will be unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine the
liability no longer applies. Conversely, we record additional tax charges in a period in which we determine that a recorded tax liability is less than we expect the ultimate assessment to be.
46
Revenue Recognition
We predominantly derive our revenue from the sale of produced oil and gas. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment from one to three months after
delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is
received. Historically, however, differences have been insignificant.
Accounting for Business Combinations
Our business has grown substantially through acquisitions, and our business strategy is to continue to pursue acquisitions as
opportunities arise. We have accounted for all of our business combinations to date using the purchase method, which is the only method permitted under SFAS No. 141,
Business Combinations,
and involves the use of significant
judgment.
Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon
the fair value of the consideration given. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the cost of an
acquired entity, if any, over the net amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is
allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets.
Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used
to determine fair values, including market prices (where available), appraisals, comparisons to transactions for similar assets and liabilities, and present value of estimated future cash flows, among others. Since these estimates involve the
use of significant judgment, they can change as new information becomes available.
Effects of Inflation and Pricing
We experienced increased costs during 2008, 2007 and 2006 due to increased demand for oil field products and services. The oil and
gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put significant 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
the 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.
Off Balance Sheet Arrangements
We have no off balance sheet arrangements, special purpose entities, financing partnerships or guarantees.
|
Item 7A.
|
Quantitative and Qualitative Disclosures About Market Risk
|
We are exposed to market risk from changes in commodity prices. In the normal course of business, we enter into derivative transactions, including commodity price collars, swaps and floors to mitigate our exposure to
commodity price movements. We do not participate in these transactions for trading or speculative purposes. While the use of these arrangements limits the benefit to us of increases in the price of oil and natural gas, it also limits the downside
risk of adverse price movements.
47
The following is a list of contracts outstanding at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transaction Date
|
|
Transaction
Type
|
|
Beginning
|
|
Ending
|
|
Price Per Unit
|
|
|
Remaining
Annual Volumes
|
|
Fair Value
Outstanding
as of
December 31,
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October-07
|
|
Collar
|
|
01/01/09
|
|
12/31/09
|
|
$
|
7.00 - $10.75
|
|
|
|
275,530 Mmbtu
|
|
$
|
165
|
|
|
October-07
|
|
Collar
|
|
01/01/10
|
|
12/31/10
|
|
$
|
7.00 - $9.90
|
|
|
|
1,287,000 Mmbtu
|
|
|
772
|
|
|
October-07
|
|
Collar
|
|
01/01/11
|
|
12/31/11
|
|
$
|
7.00 - $9.20
|
|
|
|
1,079,000 Mmbtu
|
|
|
648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,585
|
|
|
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October-07
|
|
Swap
|
|
01/01/09
|
|
12/31/09
|
|
$
|
76.00
|
|
|
|
368,000 Bbls
|
|
|
8,035
|
|
|
October-07
|
|
Swap
|
|
01/01/10
|
|
12/31/10
|
|
$
|
74.71
|
|
|
|
322,000 Bbls
|
|
|
3,497
|
|
|
October-07
|
|
Swap
|
|
01/01/11
|
|
12/31/11
|
|
$
|
74.37
|
|
|
|
282,000 Bbls
|
|
|
1,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,024
|
|
|
Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct-07/Dec-09
|
|
Swap
|
|
10/10/07
|
|
10/16/10
|
|
|
4.29375
|
%
|
|
$
|
40 Million Notional
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30-day LIBOR
|
|
|
(2,254
|
)
|
|
Oct-07/Dec-09
|
|
Swap
|
|
12/16/08
|
|
10/16/10
|
|
|
4.29375
|
%
|
|
$
|
10 Million Notional
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30-day LIBOR
|
|
|
(563
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,817
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
11,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 8.
|
Financial Statements and Supplementary Data
|
See “Index to Consolidated Financial Statements and Supplementary Information” of Page F-1.
|
Item 9.
|
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
|
None.
48
|
Item 9A(T).
|
Controls and Procedures
|
Our Chief
Executive Officer and Chief Financial Officer have implemented, or caused to be implemented, our disclosure controls and procedures to ensure that material information relating to the Company is communicated adequately to our Chief Executive Officer
and our Chief Financial Officer through the end of the reporting period addressed by this report. As of the end of the reporting period reflected herein, our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our
disclosure controls and procedures, and based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this report,
are effective in alerting them on a timely basis to material information relating to the Company that is required to be included in our reports filed or submitted under the Securities Exchange Act of 1934.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act, as amended). Our
internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
the our financial statements for external purposes in accordance with the U.S. GAAP.
While we believe that our existing
internal control framework and procedures over financial reporting have been effective in accomplishing our objectives, we intend to continue the practice of reevaluating, refining, and expanding its internal controls over financial reporting.
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.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, our management used criteria established in
Internal Control-Integrated Framework
issued
by the Committee of Sponsoring Organization of the Treadway Commission (COSO). Based on our assessment, we believe that, as of December 31, 2008, our internal control over financial reporting is effective based on those criteria. This report
does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to
temporary rules of the SEC that permit us to provide only management’s report in this report.
Changes in Internal Control over Financial Reporting
Our management has also evaluated our internal controls over financial reporting, and there have been no significant
changes in our internal controls or in other factors that could significantly affect those controls during the quarter ended December 31, 2008.
|
Item 9B.
|
Other Information
|
None.
49
PART III
|
Item 10.
|
Directors, Executive Officers and Corporate Governance
|
Directors, Executive Officers and Corporate Governance
Information concerning our executive officers and
directors is set forth below:
|
|
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position(s) with
The Company
|
|
Director/
Officer
Since
|
|
Frank A. Lodzinski
|
|
59
|
|
President, Chief Executive Officer and Director (1)
|
|
2007
|
|
|
|
|
|
|
Collis P. Chandler, III
|
|
40
|
|
Executive Vice President and Chief Operating Officer - Northern Region and Director (1)
|
|
2007
|
|
|
|
|
|
|
Francis M. Mury
|
|
57
|
|
Executive Vice President and Chief Operating Officer - Southern Region
|
|
2007
|
|
|
|
|
|
|
Robert J. Anderson
|
|
46
|
|
Vice President, Business Development, Acquisitions and Divestitures
|
|
2007
|
|
|
|
|
|
|
Howard E. Ehler
|
|
64
|
|
Vice President and Chief Financial Officer
|
|
2007
|
|
|
|
|
|
|
Christopher W. Hunt
|
|
41
|
|
Director (2) (3) (4)
|
|
2007
|
|
|
|
|
|
|
Jay F. Joliat
|
|
52
|
|
Director (2) (3) (4)
|
|
2007
|
|
|
|
|
|
|
Scott R. Stevens
|
|
37
|
|
Director (3) (4)
|
|
2007
|
|
|
|
|
|
|
Michael A. Vlasic
|
|
48
|
|
Director (1)
|
|
2007
|
|
|
|
|
|
|
Nicholas L. Voller
|
|
58
|
|
Director (2)
|
|
2004
|
|
(1)
|
Member of the Executive Committee.
|
|
(2)
|
Member of the Audit Committee.
|
|
(3)
|
Member of the Nominating Committee.
|
|
(4)
|
Member of the Compensation Committee.
|
Frank A. Lodzinski
has been President, Chief Executive Officer and Director of the Company since the Merger on April 17, 2007. He has 38 years of oil and gas industry experience. In 1984, he formed Energy Resource Associates,
Inc., which acquired controlling interests in oil and gas properties and limited partnerships. Subsequently, certain assets were sold and in 1992 the partnership interests were exchanged for common shares of Hampton Resources Corporation (NASDAQ:
“HPTR”), which Mr. Lodzinski joined as president. In 1995, Hampton was sold to Bellwether Exploration Company. In 1996, he acquired Cliffwood Oil & Gas Corporation and in 1997, Cliffwood shareholders acquired controlling
interest in Texoil, Inc. (NASDAQ: “TXLI”), where Mr. Lodzinski served as CEO and president. In 2001, Texoil was sold to Ocean Energy, Inc. Mr. Lodzinski was then appointed CEO and President of AROC, Inc., which was a financially
distressed company. He and his management team took the company private, recapitalized the company and implemented a turn-around and liquidation plan. In late 2003, AROC completed an asset monetization, which resulted in a sizable liquidity event
for preferred and common shareholders. Mr. Lodzinski subsequently formed Southern Bay Energy, LLC, and in 2005 acquired certain assets from AROC. Mr. Lodzinski is a certified public accountant and holds a BSBA degree in Accounting and
Finance from Wayne State University in Detroit, Michigan.
50
Collis P. Chandler, III
has been Executive Vice President and Chief Operating Officer –
Northern Region and Director of the Company since the Merger on April 17, 2007. He has been President and sole owner of Chandler Energy, LLC since its inception in July 2000. From 1988 to July 2000, Mr. Chandler served as Vice President of
The Chandler Company, a privately-held exploration company operating primarily in the Rocky Mountains. His responsibilities over the 12-year period included involvement in exploration, prospect generation, acquisition, structure and promotion as
well as direct responsibility for all land functions including contract compliance, lease acquisition and administration. Mr. Chandler received a Bachelor of Science Degree from the University of Colorado, Boulder, in 1992.
Francis M. Mury
has been Executive Vice President and Chief Operating Officer – Southern Region of the Company since the Merger on
April 17, 2007. He has been active in the oil and gas industry since 1974. He was employed by AROC Inc. as Executive Vice President from May 2001 through December 2004. Since January 2005, he has been employed by Southern Bay Energy LLC as
Executive Vice President. Mr. Mury worked for Texaco, Inc. from July 1974 through March 1979, ending his tenure there as a petroleum field engineer. From April 1979 through December 1985, he worked for Wainoco Oil & Gas as a production
engineer and drilling superintendent. From January 1986 to November 1989 he worked for Diasu Oil & Gas as an operations manager. He has worked with Mr. Lodzinski since 1989, including at Hampton Resources Corporation, where he served
as Vice President – Operations from January 1992 through May 1995, and Texoil, Inc. where he served as Executive Vice President from November 1997 through February 2001. His experience extends to all facets of petroleum engineering, including
reservoir engineering, drilling and production operations and further into petroleum economics, geology, geophysics, land and joint operations. Geographical areas of experience include the Gulf Coast (offshore and onshore), east and west Texas,
Mid-Continent, Florida, New Mexico, Oklahoma, Wyoming, Pennsylvania and Michigan. Mr. Mury received a degree in Computer Science (1974) from Nicholls State University, Thibodeaux, Louisiana.
Robert J. Anderson
has been Vice President, Business Development, Acquisitions and Divestitures of the Company since the Merger on April 17,
2007. He is a Petroleum Engineer with 19 years of diversified domestic and international experience with both major oil companies (ARCO International/Vastar Resources) and independent oil companies (Hunt Oil/Huguton Energy/Anadarko Petroleum). From
October 2000 through February 2004, he was employed by Anadarko Petroleum Corporation as a petroleum engineer. From March 2004 through December 2004 he was employed by AROC Inc. as Vice President, Acquisitions and Divestitures. He joined Southern
Bay Energy, LLC in January 2005 as Vice President, Acquisitions and Divestitures. His professional experience includes acquisition evaluation, reservoir and production engineering and field development, and project economics, budgeting and planning.
Mr. Anderson’s domestic acquisition and divestiture experiences include the Gulf Coast of Texas and Louisiana (offshore and onshore), east and west Texas, north Louisiana, Mid-Continent and the Rockies. His international experience
includes Canada, South America and Russia. He has an undergraduate degree in Petroleum Engineering from the University of Wyoming (1986) and also holds an MBA, Corporate Finance, from the University of Denver (1988).
Howard E. Ehler
has been Vice President and Chief Financial Officer of the Company since the Merger on April 17, 2007. He was employed as
Vice President and Chief Financial Officer of AROC Inc. from May 2001 through December 2004. Since January 2005, Mr. Ehler has been employed by Southern Bay Energy, LLC as Vice President and Chief Financial Officer. He previously served as Vice
President of Finance and Chief Financial Officer for Midland Resources, Inc. from March 1997 through October 1998. From November 1999 through April 2001 he performed independent accounting and auditing services in oil and gas as a sole practitioner
in public accounting. He was employed in public accounting with various firms for over 21 years, including practice with Grant Thornton, where he was admitted to the partnership. He has substantive experience in oil and gas banking, finance,
accounting and reporting. In addition, his experience includes partnership administration, tax, budgets and forecasts and cash management. Mr. Ehler holds an Accounting Degree from Texas Tech University (1966) and has been a certified
public accountant since 1970.
Christopher W. Hunt
has been a Director of the Company since the Merger on April 17, 2007. He
has been a founder and president of Knightsbridge Capital, LLC, a private investment firm in Denver, Colorado, since 2002.
51
Prior to founding Knightsbridge Capital, Mr. Hunt served as a vice president at the Anschutz Corporation, from 1997 to 2001, where he provided
financial, investment and merger and acquisition services for that company’s investment portfolio and served in the Denver and London, England, offices. Previously, Mr. Hunt served in the private investment group of Bechtel Enterprises in
San Francisco, California, from 1996 to 1997. Mr. Hunt holds a Bachelor’s Degree from Yale University (1990) and a Master’s Degree in Business from the J. L. Kellogg School of Management at Northwestern University (1995).
Jay F. Joliat
has been a Director of the Company since the Merger on April 17, 2007. He has, for more than the past five
years, been an independent investor and developer in commercial, industrial and garden style apartment real estate and development, residential home building, restaurant ownership and management, as well as venture private equity in generic
pharmaceuticals, medical devices and oil and gas. He previously formed and managed his own investment management company early in his career and was formerly employed by E. F. Hutton and Dean Witter Reynolds. He holds a Bachelor of Arts Degree in
Management and Finance from the Oakland University (1982) and was awarded a Certified Investment Management Analyst certificate in 1983 after completion of the IMCA program at the Wharton School of Business of the University of Pennsylvania.
From 1996 through 2003, Mr. Joliat served on the Board of Directors of Caraco Pharmaceutical Laboratories Ltd., a company with a class of equity securities registered under the Securities Exchange Act of 1934, and served in various capacities
on the audit, executive and compensation committees.
Scott R. Stevens
has been a Director of the Company since the Merger on
April 17, 2007. He has served on the Board of Managers of Southern Bay Energy, LLC since March 2005. He is a Vice President of Wachovia Capital Partners, which he originally joined in 1999. Wachovia Capital Partners was the principal investing
arm of the Wachovia Corporation and is now a division of Wells Fargo Bank. He is a graduate of the University of North Carolina at Chapel Hill and has an MBA from the Graduate School of Business at Stanford University.
Michael A. Vlasic
has been a Director of the Company since the Merger on April 17, 2007. He has served on the Board of Managers of Southern
Bay Energy, LLC since its inception in 2004. He previously was a director of Texoil, Inc., a company with a class of equity securities registered under the Securities Exchange Act of 1934, where he served on the executive committee from 1997 until
its sale to Ocean Energy Inc. in 2001. For more than the past five years he has been Chief Executive Manager of Vlasic Investments LLC. He is a graduate of Brown University.
Nicholas L. Voller
has been a Director of the Company since March 2004. For over the past five years, he has been a partner with Voller Brakey Stillwell and Suess, P.C., a CPA firm located
in Williston, North Dakota. He holds and Accounting Degree from the University of North Dakota (1972).
There is no family
relationship between or among our executive officers and directors. Our directors are elected at every annual meeting of our shareholders and hold office for a one-year term or until their successors have been elected and qualified.
Committees of our Board of Directors
To assist in carrying out its duties, our Board of Directors has delegated certain authority to an Audit Committee, Nominating Committee, Compensation Committee, and Executive Committee whose functions are described below:
Audit Committee
Members: Directors Joliat (Chairman), Hunt
and Voller
Number of Meetings in 2008: Four
Functions:
|
|
•
|
|
Assists the Board in fulfilling its oversight responsibilities as they relate to the Company’s accounting policies, internal controls, financial reporting
practices and legal and regulatory compliance;
|
|
|
•
|
|
Hires the independent auditors;
|
|
|
•
|
|
Monitors the independence and performance of the Company’s independent auditors and internal auditors;
|
|
|
•
|
|
Maintains, through regularly scheduled meetings, a line of communication between the Board and the Company’s financial management, internal auditors and
independent auditors; and
|
|
|
•
|
|
Oversees compliance with the Company’s policies for conducting business, including ethical business standards.
|
52
The Board of Directors adopted an Audit Committee Charter in 2000 and subsequently
amended and restated the Charter in March, 2004, which is available on our website at
www.georesourcesinc.com
.
Our
Board of Directors has determined that Mr. Voller qualifies as an “audit committee financial expert” as that term is defined in the NASDAQ and SEC rules.
Our common stock is quoted on the Nasdaq Stock Market. Pursuant to Nasdaq rules, the Audit Committee is to be comprised of three or more directors as determined by the Board of Directors, each of
whom shall be “independent”. Our Board of Directors has determined that all members of the Audit Committee are independent, as defined in the listing standards of the Nasdaq Stock Market and the rules of the SEC.
Nominating Committee
Members: Directors
Stevens (Chairman), Hunt and Joliat
Number of Meetings in 2008: One.
On April 17, 2007, the Board of Directors adopted a resolution appointing a Nominating Committee comprised solely of directors who
meet the independence requirements set forth in NASDAQ Rule 4200 and within the meaning of the rules and regulations of the SEC. On July 9, 2007, the Board of Directors approved a charter for the Nominating Committee which is available on our
website,
www.georesourcesinc.com
. All of the research regarding director nominees for the 2007 annual meeting was performed by the entire Board of Directors sitting as a nominating committee prior to the April 17, 2007. After formation
of the Nominating Committee in 2007 and the information was then referred to the Nominating Committee. The Committee followed the Board’s previous policy of nominating board candidates based on whom they believe will be effective in serving the
long-term interests of the Company and its shareholders. Candidates were evaluated based upon their backgrounds and the need for any required expertise on the Board and its committees.
Our Nominating Committee will consider a candidate for a director position proposed by a shareholder. A candidate must be highly
qualified in terms of business experience and be both willing and expressly interested in serving on the Board. A shareholder wishing to propose a candidate for the Board’s consideration should forward the candidate’s name and information
about the candidate’s qualifications to the GeoResources, Inc., Board of Directors, Nominating Committee, Attn: Chairman, 110 Cypress Station Drive, Suite 220, Houston, Texas 77090-1629. Submissions must include sufficient biographical
information concerning the recommended individual, including age, employment history for at least the past five years indicating employer’s names and description of the employer’s business, educational background and any other biographical
information that would assist the Nominating Committee in determining the qualifications of the individual. The Nominating Committee will consider all candidates, whether recommended by shareholders or members of management. The Nominating
Committee will consider recommendations received by a date not later than 120 calendar days before the date our proxy statement was released to shareholders in connection with the prior year’s annual meeting for nomination at that annual
meeting. The Board will consider nominations received beyond that date at the annual meeting subsequent to the next annual meeting.
Compensation
Committee
Members: Directors Joliat (Chairman), Hunt and Stevens
Number of Meeting in 2008: Two
On April 17, 2007, the Board of Directors adopted a
resolution appointing a Compensation Committee comprised solely of directors who meet the independence requirements set forth in NASDAQ Rule 4200 and within the meaning of the rules and regulations of the SEC. On July 9, 2007, the
Board of Directors approved a charter for the Compensation Committee which is available on our website,
www.georesourcesinc.com
. The primary function of this Committee is to review and approve executive compensation and benefit
programs. Additionally, this Committee approves the compensation of the Chief Executive Officer, Chief Financial Officer, and any other officers deemed appropriate. The Compensation Committee does not anticipate utilizing any compensation
consultants at this time. Our Chief Executive Officer is expected to recommend to the Compensation Committee the compensation for other executive officers and recommend director compensation.
53
Executive Committee
Under the current Bylaws, Article III, Section 12, the Chairman of the Board can appoint other committees in addition to the three current standing committees: Audit, Compensation, and
Nomination. On April 17, 2007, the Chairman appointed an Executive Committee to be a working committee, assigned with regular tasks outlined by our Board of Directors. The Chairman of this committee is Frank A. Lodzinski, with members Collis P.
Chandler and Michael A. Vlasic. The Board of Directors has not adopted a charter for the Executive Committee.
Code of Ethics
Our Board of Directors has adopted a Code of Business Ethics (“Code”), which is posted on our website,
www.georesourcesinc.com
. Our shareholders may also obtain a copy of our Code by requesting it in writing at 110 Cypress Station Drive, Suite 220, Houston, Texas 77090-1629 or by calling (281) 537-9920.
Our Code provides general statements of our expectations regarding ethical standards that we expect our directors, officers and employees
to adhere to while acting on our behalf. Among other things, the Code provides that:
|
|
•
|
|
We will comply with all laws, rules and regulations;
|
|
|
•
|
|
Our directors, officers, and employees are to avoid conflicts of interest and are prohibited from competing with us or personally exploiting our corporate
opportunities;
|
|
|
•
|
|
Our directors, officers, and employees are to protect our assets and maintain our confidentiality;
|
|
|
•
|
|
We are committed to promoting values of integrity and fair dealing; and
|
|
|
•
|
|
We are committed to accurately maintaining our accounting records under generally accepted accounting principles and timely filing our periodic reports.
|
Our code also contains procedures for employees to report, anonymously or otherwise, violations of the
Code.
Section 16(a) Beneficial Ownership Reporting Compliance
Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to the Company under Rule 16a-3(d) during 2008, we are not aware of any director, officer, or beneficial owner of more
than 10% of our common stock that failed to file on a timely basis reports required by Section 16(a) of the Exchange Act during the year except for Wachovia Capital Partners 2005, LLC, who did not file five of its Form 4s timely. All of these
filings disclosed a series of related transactions by Wachovia Capital Partners 2005, LLC over the course of seven days in June, 2008.
|
Item 11.
|
Executive Compensation
|
Compensation Discussion and Analysis
Overview
The following Compensation Discussion and Analysis describes the material elements of compensation for the named executive officers identified in the Summary Compensation Table below. As more fully described below, the Compensation
Committee of the Board of Directors reviews and recommends to the full Board of Directors the total direct compensation programs for our named executive officers. Our Chief Executive Officer, Frank A. Lodzinski, reviews the base salary,
discretionary annual bonus and long-term compensation levels for the other named executive officers.
Compensation Philosophy and Objectives
Our compensation philosophy is to encourage growth in our oil and natural gas reserves and production, encourage growth in
cash flow and profitability, and enhance shareholder value through a compensation program that attracts and retains highly qualified executive officers. To achieve these goals, the compensation committee believes that the compensation of executive
officers should reflect our growth while ensuring fairness among the executive management team by recognizing the contributions each individual executive makes to our success.
54
The compensation committee believes compensation should include the following components:
|
|
•
|
|
A base salary that is commensurate with other small, independent oil and gas companies and provides a living wage for our executive officers;
|
|
|
•
|
|
Discretionary annual incentive compensation to reward hard work, individual responsibility and productivity, reserve growth, performance and profitability; and
|
|
|
•
|
|
Long-term incentive compensation in the form of stock options.
|
The compensation committee periodically reviews data about the compensation of executives in the oil and gas industry but does not conduct an in-depth review of comparable companies. Based on
this review, we believe that the elements of our executive compensation program are comparable to those offered by our industry competitors.
Elements of Our Compensation Program
The compensation program for our executive officers is composed
of three principal components: base salary, discretionary annual incentive compensation and long-term incentive compensation in the form of stock options.
Base Salary
. Base salaries (paid in cash) for our executives are established based on the scope and responsibilities, taking into account what we believe to be a fair working salary for executives in these
positions, as well as competitive market compensation paid by peer companies for similar positions. All of our named executive officers have worked with or for our Chief Executive Officer, Frank A. Lodzinski, for several years. From time to time, we
review our executives’ base salaries in comparison to salaries for executives in similar positions with similar responsibilities at comparable companies. Base salaries are reviewed annually and adjusted from time to time to realign salaries
after taking into account individual responsibilities, performance, experience and other criteria. We rely on the advice of Mr. Lodzinski in setting base salaries for our named executive officers other than him.
The compensation committee reviews, taking into account the Chief Executive Officer’s recommendations, the base salaries for the
named executive officers, except for the Chief Executive Officer, in the first quarter of each year. New base salary amounts are based on an evaluation of individual performance and expected future performance. On February 3, 2009, the
compensation committee approved base salaries for our named executive officers commencing at the discretion of the Chief Executive Officer, Frank A. Lodzinski, but no earlier than April 1, 2009.
Discretionary Annual Incentive Compensation
. The compensation committee recommends to the Board, and the Board subsequently
approves, any annual bonuses for each named executive officer. On February 3, 2009, the compensation committee approved payment of bonuses to executive officers for 2008.
Long Term Incentive Compensation
. We believe the use of stock options creates an ownership culture that encourages the long-term performance of our executive officers. In March 2007, our
shareholders approved the GeoResources, Inc. Amended and Restated 2004 Employees’ Stock Incentive Plan (the “2004 Plan”). In October 2007, we issued options to the named executive officers as set forth in the table below. On the grant
date all of these options were not in the money and the option exercise prices are escalated. Also on February 3, 2009, the Compensation Committee approved stock option grants to the named executive officers to purchase our common stock
pursuant to our 2004 Plan. Fifty percent of the stock options are exercisable at $8.50 per share and fifty percent are exercisable at $10.00 per share. The stock options vest equally between the two exercise prices in equal annual installments over
a period of four years from the date of grant. The options have a term of 10 years and are subject to the terms and conditions of the 2004 Plan. These options were not “in the money” at the date of grant in order to provide incentive for
the named executive officers to continue to work diligently to increase the shareholder value through their ongoing full-time efforts. All of the above options will vest upon a change in control of the Company. We have no employment agreements with
our named executive officers.
55
Recent Actions
. The 2008 bonus payments, 2009 base salaries and the February 2009,
stock option grants are set forth in the table below.
|
|
|
|
|
|
|
|
|
Officer
|
|
2008
Bonus
Amount
($)
|
|
2009
Base
Salary
($)
|
|
Stock Option
(Common Stock)
(#)
|
|
Frank A. Lodzinski,
Principal Executive Officer and Chairman of the Board of Directors
|
|
|
|
|
|
|
|
|
20,000
|
|
200,000
|
|
100,000
|
|
|
|
|
|
|
Collis P. Chandler, III,
Executive Vice President and Chief Operating Officer – Northern Division
|
|
|
|
|
|
|
|
|
17,500
|
|
160,000
|
|
50,000
|
|
|
|
|
|
|
Francis M. Mury,
Executive Vice President and Chief Operating Officer – Southern Division
|
|
|
|
|
|
|
|
|
17,500
|
|
165,000
|
|
50,000
|
|
|
|
|
|
|
Howard E. Ehler,
Principal Financial Officer and Principal Accounting Officer
|
|
|
|
|
|
|
|
|
17,500
|
|
160,000
|
|
50,000
|
|
|
|
|
|
|
Robert J. Anderson,
Vice President, Business Development – Acquisitions and Divestitures
|
|
|
|
|
|
|
|
|
17,500
|
|
160,000
|
|
50,000
|
In 2007, the Merger with Southern Bay was completed and a significant amount of
work was performed by all named executive officers. However, the compensation committee, upon the advice of the Chief Executive Officer, determined that no bonus would be paid to the named executive officers other than to Jeffery P. Vickers, the
former Principal Executive Officer and Principal Accounting Officer, who was instrumental in completing the Merger. For 2008, all of the named executive officers contributed significantly to the Company’s success and the Company completed
acquisitions, divested non-core properties, and achieved several other strategic objectives for the year. Accordingly, the 2008 bonus payments will be made if the Company’s cash flow is sufficient as determined in the sole discretion of the
Chief Executive Officer.
Other Benefits
. All employees may participate in our 401(k) Retirement Savings Plan, or
401(k) Plan, established many years ago. Each employee may make before tax contributions in accordance with the Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for
retirement in a tax efficient manner. Our matching contribution is an amount equal to 100% of the employee’s elective deferral contribution not to exceed 4% of the employee’s compensation.
All full time employees, including our named executive officers, may participate in our health and welfare benefit programs, including
medical, dental and vision care coverage, disability insurance and life insurance.
Accounting and Tax Considerations
Our option award policies have been impacted by the implementation of Statement of Financial Accounting Standards No. 123(R), which
we adopted on January 1, 2006.
We have structured our compensation program to comply with Internal Revenue Code
Sections 162(m) and 409A. Under Section 162(m) of the Internal Revenue Code, a limitation is placed on the tax deduction of any publically-held corporation for individual compensation to certain executives of such corporation exceeding
$1,000,000 in any taxable year, unless the compensation is performance-based. If an executive officer is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such benefits do not comply with
56
Section 409A, then the benefits are taxable in the first year they are not subject to substantial risk of forfeiture. In such case, the executive
officer is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefit included in income. We have no individuals with non-performance based compensation paid in excess of the Internal Revenue Code
Section 162(m) tax deduction limit.
57
Summary Compensation Table
The following table presents the aggregate compensation earned by our named executive officers for the three fiscal years ended December 31, 2008. We do not have any employment contracts
with any of our named executive officers. There has been no compensation awarded to, earned by or paid to any employees required to be reported in any table or column in the fiscal years covered by any table, other than what is set forth in the
following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name and Principal Position
|
|
Year
|
|
Salary
($)
|
|
Bonus
($)
|
|
Stock
Awards
($)
|
|
Option
Awards
($)
|
|
Nonequity
Incentive Plan
Compensation
($)
|
|
All Other
Compensation
($)
|
|
Total ($)
|
|
Frank A. Lodzinski,
Principal Executive Officer and Chairman of the Board of Directors (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
162,500
|
|
—
|
|
—
|
|
118,500
|
|
—
|
|
—
|
|
281,000
|
|
|
2007
|
|
150,000
|
|
—
|
|
—
|
|
27,055
|
|
—
|
|
—
|
|
177,055
|
|
|
|
|
|
|
|
|
|
|
|
Collis P. Chandler, III,
Executive Vice President and Chief Operating Officer – Northern Division (1)
|
|
2008
|
|
150,000
|
|
—
|
|
—
|
|
79,000
|
|
—
|
|
—
|
|
229,000
|
|
|
2007
|
|
100,000
|
|
—
|
|
—
|
|
18,995
|
|
—
|
|
—
|
|
118,995
|
|
|
|
|
|
|
|
|
|
|
|
Francis M. Mury,
Executive Vice President and Chief Operating Officer – Southern Division (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
143,750
|
|
22,500
|
|
—
|
|
79,000
|
|
—
|
|
—
|
|
245,250
|
|
|
2007
|
|
125,000
|
|
—
|
|
—
|
|
17,561
|
|
—
|
|
—
|
|
142,561
|
|
|
|
|
|
|
|
|
|
|
|
Howard E. Ehler,
Principal Financial Officer and Principal Accounting Officer (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
120,000
|
|
27,500
|
|
—
|
|
55,300
|
|
—
|
|
—
|
|
202,800
|
|
|
2007
|
|
105,000
|
|
—
|
|
—
|
|
11,862
|
|
—
|
|
—
|
|
116,862
|
|
|
|
|
|
|
|
|
|
|
|
Robert J. Anderson,
Vice President, Business Development – Acquisitions and Divestitures (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
135,000
|
|
27,500
|
|
—
|
|
59,250
|
|
—
|
|
—
|
|
221,750
|
|
|
2007
|
|
120,000
|
|
—
|
|
—
|
|
12,812
|
|
—
|
|
—
|
|
132,812
|
|
|
|
|
|
|
|
|
|
|
|
Jeff P. Vickers,
Vice President Northern Division (April 17, 2007 – September 30, 2008) Principal Executive and Principal
Accounting Officer (2006 – April 16, 2007).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
104,858
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
104,858
|
|
|
2007
|
|
129,483
|
|
46,478
|
|
—
|
|
—
|
|
—
|
|
—
|
|
175,961
|
|
|
2006
|
|
127,887
|
|
—
|
|
—
|
|
—
|
|
10,372
|
|
6,393
|
|
144,652
|
|
(1)
|
These individuals were not named executive officers prior to the April 17, 2007, Merger.
|
The amounts disclosed for option awards are the dollar amounts recognized in the financial statements in accordance with FAS 123R.
The material terms of option grants are set forth below the table “Outstanding Equity Awards at Fiscal Year-End.”
58
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name
(a)
|
|
Number of
Securities
Underlying
Unexercised/
Exercisable
Options
|
|
% of Total
Options
Granted to
Employees
in Fiscal
Year
(c)
|
|
|
Option
Exercise
Price
($)
(d)
|
|
Option
Expiration
Date
(e)
|
|
Number
of Shares
or Units
of Stock
That
Have Not
Vested
(#)
(f)
|
|
Market Value
of Unexercised
In-The-
Money
Options/ SARs
at Year-End
($)
(g) **
|
|
Equity
Incentive
Plan
Awards:
Number of
Unearned
Shares,
Units
or
Other
Rights That
Have Not
Vested
(#)
(i)
|
|
Equity
Incentive Plan
Awards:
Market or
Payout Value
of Unearned
Shares, Units
or Other
Rights
That
Have Not
Vested
($)
(j)
|
|
Frank A. Lodzinski,
|
|
75,000
|
|
19.9
|
%
|
|
$
|
8.27
|
|
Oct 10, 2017
|
|
75,000
|
|
31,500
|
|
|
|
|
|
CEO
|
|
37,500
|
|
19.9
|
%
|
|
$
|
9.56
|
|
Oct 10, 2017
|
|
37,500
|
|
N/A
|
|
|
|
|
|
|
|
37,500
|
|
19.9
|
%
|
|
$
|
9.56
|
|
Oct 10, 2017
|
|
37,500
|
|
N/A
|
|
N/A
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
Howard E. Ehler,
|
|
35,000
|
|
9.3
|
%
|
|
$
|
8.27
|
|
Oct 10, 2017
|
|
35,000
|
|
14,700
|
|
|
|
|
|
CFO
|
|
17,500
|
|
9.3
|
%
|
|
$
|
9.56
|
|
Oct 10, 2017
|
|
17,500
|
|
N/A
|
|
|
|
|
|
|
|
17,500
|
|
9.3
|
%
|
|
$
|
9.56
|
|
Oct 10, 2017
|
|
17,500
|
|
N/A
|
|
N/A
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
Collis P. Chandler, III
|
|
50,000
|
|
13.2
|
%
|
|
$
|
8.27
|
|
Oct 10, 2017
|
|
50,000
|
|
21,000
|
|
|
|
|
|
|
|
25,000
|
|
13.2
|
%
|
|
$
|
9.56
|
|
Oct 10, 2017
|
|
25,000
|
|
N/A
|
|
|
|
|
|
|
|
25,000
|
|
13.2
|
%
|
|
$
|
9.56
|
|
Oct 10, 2017
|
|
25,000
|
|
N/A
|
|
N/A
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
Francis M. Mury
|
|
50,000
|
|
13.2
|
%
|
|
$
|
8.27
|
|
Oct 10, 2017
|
|
50,000
|
|
21,000
|
|
|
|
|
|
|
|
25,000
|
|
13.2
|
%
|
|
$
|
9.56
|
|
Oct 10, 2017
|
|
25,000
|
|
N/A
|
|
|
|
|
|
|
|
25,000
|
|
13.2
|
%
|
|
$
|
9.56
|
|
Oct 10, 2017
|
|
25,000
|
|
N/A
|
|
N/A
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
Robert J. Anderson
|
|
37,500
|
|
9.9
|
%
|
|
$
|
8.27
|
|
Oct 10, 2017
|
|
37,500
|
|
15,750
|
|
|
|
|
|
|
|
18,750
|
|
9.9
|
%
|
|
$
|
9.56
|
|
Oct 10, 2017
|
|
18,750
|
|
N/A
|
|
|
|
|
|
|
|
18,750
|
|
9.9
|
%
|
|
$
|
9.56
|
|
Oct 10, 2017
|
|
18,750
|
|
N/A
|
|
N/A
|
|
N/A
|
|
**
|
Valued at market close price on December 31, 2008 of $8.69 per share
|
Option Grants in Last Two Fiscal Years
. During 2008 we granted 25,000 options to non-officer employees under the Amended and
Restated 2004 Employees’ Stock incentive Plan (the “2004 Plan”). We granted an aggregate of 765,000 stock options in October 2007 of which 495,000 were to the above named executive officers. If within the duration of any of the
remaining outstanding options there is a corporate merger consolidation, acquisition of assets or other reorganization and if such transaction affects the optioned stock, the optionee will thereafter be entitled to receive, upon exercise of his
option, those shares or securities that he would have received had the option been exercised prior to the transaction and the optionee had been a shareholder with respect to such shares. One-half of the options are exercisable on October 10, 2009,
and an additional 25% are exercisable on each yearly anniversary thereafter, until October 10, 2011, when 100% of the options are exercisable.
The Compensation Committee for our Board of Directors administers the outstanding options.
Options Granted Subsequent to Year-end
. On February 3, 2009, the Compensation Committee of the Board of Directors granted additional options to officers and board members under the 2004 Plan to purchase an additional 500,000
shares of our common stock. These options vest at the rate of 25% per year beginning February 3, 2010, at exercise prices of $8.50 for 250,000 shares $10.00 for the remaining 250,000 shares. These options, if not exercised, will expire
February 3, 2020. The closing price of our stock on the date of the grant was $7.62.
In 2007, our shareholders
adopted the 2004 Plan. The 2004 Plan reserves 2,000,000 shares of our common stock for either nonstatutory options or incentive stock options that may be granted pursuant to the terms of the Plan. Of the 2,000,000 reserved shares, 690,000 shares
remained outstanding as
59
of March 25, 2009. Under the terms of the 2004 Plan, the option price can not be less than 100% of the fair market value of the common stock of the
Company on the date of grant, and if the optionee owns more than 10% of the voting stock, the option price per share can not be less than 110% of the fair market value.
Director Compensation
The following table sets forth all compensation paid to our
directors in 2008.
|
|
|
|
|
Name of Director
|
|
Fees Earned or
Paid In Cash
($)
|
|
Frank A. Lodzinski
|
|
—
|
|
Collis P. Chandler, III
|
|
—
|
|
Christopher W. Hunt
|
|
—
|
|
Jay F. Joliat
|
|
—
|
|
Michael A. Vlasic
|
|
—
|
|
Scott R. Stevens
|
|
—
|
|
Nick L. Voller
|
|
—
|
Non-Employee Director Compensation
On February 3, 2009, the Compensation Committee of the Board of Directors of the Company adopted a compensation structure for
non-employee directors effective for fiscal 2009. Each non-employee director will receive annual compensation of $23,000; each member of the Audit Committee will receive an additional $8,000 per year; and each member of the Compensation Committee
will receive an additional $4,000 per year. Additionally, each non-employee director was granted stock options under the 2004 Plan to purchase 40,000 shares of common stock with exercise prices of $8.50 for 20,000 shares and $10.00 per share for the
remaining 20,000 shares. The stock options vest equally between the two exercise prices in equal annual installments over a period of four years from the date of grant. The options have a term of 10 years and are subject to the terms and conditions
of the 2004 Plan. The February 3, 2009, closing price of our common stock was $7.62 per share.
Employment Contracts and Termination of
Employment Agreements
We have no employment contracts in place with any of our executive officers who serve at the
will of the Board of Directors. We also have no compensatory plan or arrangement with respect to any executive officer where such plan or arrangement will result in payments to such officer upon or following his resignation, retirement, or other
termination of employment with us and our subsidiaries, or as a result of a change-in-control of the Company or a change in the executive officers’ responsibilities following a change-in-control.
60
|
Item 12.
|
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
|
The following table sets forth the number of shares of our common stock beneficially owned by each of our officers and directors and by
all directors and officers as group and certain beneficial owners as of March 20, 2009. Unless otherwise indicated, the stockholders listed in this table have sole voting and investment powers with respect to the shares indicated.
|
|
|
|
|
|
|
|
|
|
CLASS OF
SECURITIES
|
|
NAME AND ADDRESS OF BENEFICIAL OWNER (1)
|
|
AMOUNT OF SHARES
AND NATURE OF
BENEFICIAL
OWNERSHIP
|
|
PERCENT
OF CLASS
|
|
|
Common Stock,
$.01 par value
|
|
Frank A. Lodzinski (2) (3) (4) (11)
110 Cypress Station Drive - Suite 220
Houston, Texas 77090
|
|
3,457,126
|
|
21.3
|
%
|
|
|
|
|
|
|
Common Stock,
$.01 par
value
|
|
Collis P. Chandler, III (5)
475 Seventeenth Street - Suite 1210
Denver, CO 80202
|
|
1,620,711
|
|
10.0
|
%
|
|
|
|
|
|
|
Common Stock,
$.01 par
value
|
|
Francis M. Mury (6) (11)
110 Cypress Station Drive - Suite 220
Houston, TX 77090
|
|
100,000
|
|
*
|
|
|
|
|
|
|
|
Common Stock,
$.01 par
value
|
|
Howard E. Ehler (7) (11)
110 Cypress Station Drive - Suite 220
Houston, TX 77090
|
|
40,053
|
|
*
|
|
|
|
|
|
|
|
Common Stock,
$.01 par
value
|
|
Robert J. Anderson (8) (11)
110 Cypress Station Drive - Suite 220
Houston, TX 77090
|
|
63,266
|
|
*
|
|
|
|
|
|
|
|
Common Stock,
$.01 par
value
|
|
Christopher W. Hunt
200
Filmore Street - No. 408
Denver, CO 80206
|
|
45,000
|
|
*
|
|
|
|
|
|
|
|
Common Stock,
$.01 par
value
|
|
Jay F. Joliat (9)
36801
Woodward Avenue - Suite 301
Birmingham, MI 48009
|
|
500,000
|
|
3.1
|
%
|
|
|
|
|
|
|
Common Stock,
$.01 par
value
|
|
Scott R. Stevens (10)
301 South College Street - 12
th
Floor
Charlotte, NC 28288
|
|
—
|
|
*
|
|
|
|
|
|
|
|
Common Stock,
$.01 par
value
|
|
Michael A. Vlasic (4)
38710 Woodward Avenue
Bloomfield Hills, MI 48304
|
|
4,806,536
|
|
29.6
|
%
|
|
|
|
|
|
|
Common Stock,
$.01 par
value
|
|
Nick Voller
222
University Avenue
Williston, ND 58801
|
|
—
|
|
*
|
|
|
|
|
|
|
|
Common Stock,
$.01 par value
|
|
Officers and Directors (11)
as a Group - (ten persons)
|
|
7,310,323
|
|
45.0
|
%
|
|
|
|
Direct and Indirect
|
|
|
|
|
|
|
|
|
|
Common Stock, $.01 par value
|
|
Wachovia Capital Partners 2005 LLC (10)
301 South College Avenue
Charlotte, NC 28288
|
|
1,688,860
|
|
10.4
|
%
|
61
|
|
|
|
|
|
|
|
|
|
CLASS OF
SECURITIES
|
|
NAME AND ADDRESS OF BENEFICIAL OWNER (1)
|
|
AMOUNT OF SHARES
AND NATURE OF
BENEFICIAL
OWNERSHIP
|
|
PERCENT
OF CLASS
|
|
|
Common Stock,
$.01 par value
|
|
Vlasic FAL, L.P. (4)
110
Cypress Station Drive - Suite 220
Houston, Texas 77090
|
|
3,318,536
|
|
20.4
|
%
|
|
|
|
|
|
|
Common Stock,
$.01 par value
|
|
Chandler Energy, LLC (5)
475 Seventeenth Street - Suite 1210
Denver, CO 80202
|
|
1,620,711
|
|
10.0
|
%
|
|
(1)
|
Unless otherwise indicated, the shares are held directly in the names of the named beneficial owners and each person has sole voting and sole investment power
with respect to the shares.
|
|
(2)
|
Includes 108,357 shares of common stock owned by Mr. Lodzinski, 26,400 shares held by Mr. Lodzinski’s spouse.
|
|
(3)
|
Includes 3,833 shares of common stock held by officers and employees pursuant to a shareholders agreement
|
|
(4)
|
Vlasic FAL, L.P., a Texas limited partnership, is managed by VL Energy LLC, a Texas limited liability company and general partner. All of the membership interest
in VL Energy LLC are owned by Frank A. Lodzinski. Mr. Lodzinski and Mr. Vlasic indirectly own all of the limited partnership interests of Vlasic FAL L.P., through limited liability companies that they control, and that each of
Mr. Lodzinski and Mr. Vlasic own in part, with the remaining owners consisting primarily of family members. The entity controlled by Mr. Vlasic that is the limited partner of Vlasic FAL, L.P. has the right to remove the general
partner at any time. Vlasic FAL, L.P. directly owns 3,318,536 shares of the Company, or 20.4% of the issued and outstanding common stock of the Company. Based on the legal structure of Vlasic FAL, L.P., Mr. Lodzinski and Mr. Vlasic
are beneficial owners of all of the shares of common stock held by Vlasic FAL, L.P., and share the right to vote and dispose of these shares. In addition, the total shares shown for Mr. Vlasic include 1,488,000 shares held by VILLCo Energy, LLC
for which Mr. Vlasic serves as Chief Executive Manager.
|
|
(5)
|
Includes 1,595,711 shares of common stock held in the name of Chandler Energy, LLC, which is solely owned by Mr. Chandler. Includes 25,000 shares that
are held by Chandler Energy, LLC pursuant to a shareholders agreement with certain former employees of Chandler Energy, LLC.
|
|
(6)
|
Includes 583 shares of common stock that have not yet vested pursuant to a shareholders agreement between Mr. Mury, Southern Bay Oil & Gas, L.P.
and VL Energy, L.L.C.
|
|
(7)
|
Includes 4,261 shares of common stock held by Mr. Ehler in an Individual Retirement Account and includes 667 shares of common stock that have not yet vested
pursuant to a shareholders agreement between Mr. Ehler, Southern Bay Oil & Gas, L.P. and VL Energy, L.L.C.
|
|
(8)
|
Includes 21,304 shares of common stock held by Mr. Anderson in an Individual Retirement Account and includes 667 shares of common stock that have not yet
vested pursuant to a shareholders agreement between Mr. Anderson, Southern Bay Oil & Gas, L.P. and VL Energy, L.L.C.
|
|
(9)
|
Includes 290,887 shares of common stock owned directly by Mr. Joliat and 184,050 shares of common stock which is owned through trusts of which
Mr. Joliat is trustee. Includes 25,063 shares of common stock owned by Mr. Joliat’s wife.
|
|
(10)
|
Mr. Stevens is a member of the managing member of Wachovia Capital Partners 2005, LLC, which owns 1,688,860 shares of the Company’s common stock.
Mr. Stevens disclaims beneficial ownership of all such securities, except to the extent of his pecuniary interest therein. These securities may be deemed to be beneficially owned by (a) Wachovia Capital Partners GP I, LLC, the
managing member of Wachovia Capital Partners 2005, LLC, and (b) Scott B. Pepper, Fredrick W. Eubank, II and L. Watts Hamrick, III, the managers of Wachovia Capital Partners GP I, LLC. Each of Messrs. Pepper, Eubank and Hamrick disclaims
beneficial ownership of such securities except to the extent of his pecuniary interest therein.
|
|
(11)
|
This number includes only the 3,318,536 shares of common stock in the name of Vlasic FAL, L.P. once, in which Mr. Vlasic and Mr. Lodzinski may be each
considered beneficial owners of those shares. Additionally, this number only counts the shares of common stock once that have not vested for Mr. Anderson, Mr. Ehler and Mr. Mury, who share control of these shares with
Mr. Lodzinski until they have vested.
|
|
Item 13.
|
Certain Relationships and Related Transactions and Director Independence
|
In July 2007, the Company acquired certain oil and gas properties from officers and key employees for $1,075,000, including cash of $856,000 and the issuance of 30,406 shares of common stock at
$7.19 per share. Also, in July 2007, the Company issued 100,000 shares of common stock for cash of $719,000 to three individuals, including two members of the board of directors and an affiliate of one of our directors.
62
Accounts receivable at December 31, 2008 and 2007, includes $2,311,000 and
$3,360,000 respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at December 31, 2008, also includes $594,000 due from OKLA Energy Partners LP. Both of these partnerships are oil and gas limited partnerships for
which a subsidiary of the Company serves as general partner. These amounts represent the limited partnerships’ share of property operating expenditures incurred by operating subsidiaries of the Company on their behalf, as well as accrued
management fees. Accounts payable at December 31, 2008 and 2007, includes $9,333,000 and $9,538,000, respectively, due to the SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at December 31, 2008, also
includes $977,000 due to OKLA Energy for oil and gas revenues collected on its behalf.
The Company earned partnership
management fees during the years ended December 31, 2008, 2007, and 2006 of $1,725,000, $969,000, and $260,000 respectively.
Subsidiaries of the Company operate the majority of oil and gas properties in which the two limited partnerships have an interest. Under this arrangement, the Company collects revenues from purchasers and incurs property operating and
development expenditures on each partnership’s behalf. These revenues are paid monthly to each partnership, which in turn reimburses the Company for the partnership’s share of expenditures.
Independence of Directors
The rules
of the Nasdaq Stock Market require that a majority of our Board of Directors be independent directors, as defined in Nasdaq Rule 4200(a)(15). In March 2006, April 2007, and October 2008, we reviewed the independence of our directors. During
these reviews, our Board of Directors considered transactions and relationships between each director, or any member of his family, and the Company and our subsidiaries. As a result of this review, the Board of Directors has determined that a
majority of the directors serving on the Board are independent under Nasdaq Rules. Our independent directors are: Messrs. Hunt, Joliat, Stevens and Voller.
63
|
Item 14.
|
Principal Accountant Fees and Services
|
During 2008, 2007 and 2006, we paid the following fees to our principal accountants:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Audit Fees
|
|
$
|
312,565
|
|
$
|
239,475
|
|
$
|
36,375
|
|
Audit Related Fees
|
|
|
—
|
|
|
—
|
|
|
1,665
|
|
Tax Fees
|
|
|
—
|
|
|
—
|
|
|
6,527
|
|
All Other Fees
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
312,565
|
|
$
|
239,475
|
|
$
|
44,567
|
|
|
|
|
|
|
|
|
|
|
|
To help assure independence of the independent auditors, the Audit Committee of
our Board of Directors has established a policy whereby all audit, review, attest and non-audit engagements of the principal auditor or other firms must be approved in advance by the Audit Committee; provided, however, that de minimis non-audit
services may instead be approved in accordance with applicable Securities and Exchange Commission rules. This policy is set forth in our Audit Committee Charter. Of the fees shown above in the table, which were paid to our principal accountants,
100% were approved by the Audit Committee.
64
|
Item 15.
|
Exhibits and Financial Statement Schedules
|
EXHIBIT INDEX
FOR
Form 10-K for the year ended December 31, 2008.
|
|
|
|
|
3.1
|
|
Amended and Restated Articles of Incorporation dates June 10, 2003, incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-KSB for the year ended
December 31, 2003.
|
|
|
|
|
3.1(a)
|
|
Articles of Amendment to the Articles of Incorporation, incorporated by reference as Annex C to the Registrant’s definitive Proxy Statement dated February 23, 2007, and
filed with the Commission on February 23, 2007.
|
|
|
|
|
3.1(b)
|
|
Articles of Amendment to Articles of Incorporation, dated November 6, 2007. (5)
|
|
|
|
|
3.2
|
|
Bylaws, as amended March 2, 2004, incorporated by reference to Exhibit 3.2 of Registrant’s Form 10-KSB for the year ended December 31, 2003.
|
|
|
|
|
10.15
|
|
Agreement and Plan of Merger dated September 14, 2006, among GeoResources, Inc., Southern Bay Energy Acquisition, LLC, Chandler Acquisition, LLC, Southern Bay Oil & Gas,
L.P., Chandler Energy, LLC and PICA Energy, LLC (including Amendment No. 1 dated February 16, 2007). Incorporated by reference as Annex A to the Registrant’s Definitive Proxy Statement dated February 23, 2007 and filed with the Commission on
February 23, 2007.
|
|
|
|
|
10.19
|
|
June 7, 2001 Lease Agreement by and between AROC, Inc. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090.
(3)
|
|
|
|
|
10.20
|
|
First Amendment to June 7, 2001 Lease Agreement by and between AROC, Inc. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas
77090, dated November 10, 2003. (3)
|
|
|
|
|
10.21
|
|
Assignment and Assumption by Southern Bay Energy, L.L.C. of June 7, 2001 Lease Agreement by and between AROC, Inc. and BGK Texas Property Management, Inc. for 110 Cypress
Station Drive, Suite 220, Houston, Texas 77090, dated April 19, 2005. (3)
|
|
|
|
|
10.22
|
|
Unconditional Guaranty of June 7, 2001 Lease Agreement by and between Southern Bay Energy, L.L.C. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite
220, Houston, Texas 77090, dated April 19, 2005. (3)
|
|
|
|
|
10.23
|
|
Second Amendment to June 7, 2001 Lease Agreement by and between Southern Bay Energy, L.L.C. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220,
Houston, Texas 77090, dated April 19, 2005. (3)
|
|
|
|
|
10.24
|
|
Third Amendment to June 7, 2001 Lease Agreement by and between Southern Bay Energy, L.L.C. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220,
Houston, Texas 77090, dated April 9, 2007. (3)
|
|
|
|
|
10.26
|
|
January 31, 2000 Office Building Lease by and between 475-17
th
Street,
CO. and Collis P. Chandler III for 475 17th Street Building, Suite 860, 475 17th Street, Denver, Colorado 80202. (3)
|
|
|
|
|
10.27
|
|
First Amendment to January 31, 2000 Office Building Lease by and between 475-17
th
Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated September 28, 2001. (3)
|
|
|
|
|
10.28
|
|
Second Amendment to January 31, 2000 Office Building Lease by and between 475-17
th
Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated October 23, 2002. (3)
|
|
|
|
|
10.29
|
|
Third Amendment to January 31, 2000 Office Building Lease by and between 475-17
th
Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated June 28, 2004. (3)
|
|
|
|
|
10.30
|
|
Credit Agreement dated September 26, 2007 between the Registrant and Wachovia Bank National Association. (2)
|
|
|
|
|
10.31
|
|
Limited Partner Interest Purchase and Sale Agreement dated October 16, 2007 between the Registrant and TIFD III-X, LLC (2)
|
65
|
|
|
|
|
10.32
|
|
Amended and Restated Credit Agreement dated October 16, 2007 between the Registrant and Wachovia Bank National Association (2)
|
|
|
|
|
10.33
|
|
Amended and Restated Credit Agreement dated October 16, 2007 between the Registrant and Wachovia Bank National Association (2)
|
|
|
|
|
10.34
|
|
Form of Purchase Agreement (4)
|
|
|
|
|
10.35
|
|
Form of Warrant (4)
|
|
|
|
|
10.36
|
|
Form of Registration Rights Agreement (4)
|
|
|
|
|
10.37
|
|
Agreement of Limited Partnership for OKLA Energy Partners LP dated May 20, 2008 (6)
|
|
|
|
|
10.38
|
|
Lease Agreement by and between Southern Bay Energy, L.L.C. and Cypress Court Operating Associates, L.P. for office space at 110 Cypress Station Drive, Suite 220, Houston,
Texas 77090, dated September 25, 2008. (7)
|
|
|
|
|
14.1
|
|
Code of Business Conduct and Ethics adopted March 2, 2004, incorporated by reference to Exhibit 14.1 of Registrant’s Form 10-KSB for fiscal year ended December 31, 2003.
|
|
|
|
|
21.1
|
|
Subsidiaries of the Registrant. (3)
|
|
|
|
|
23.1
|
|
Consent of Grant Thornton LLP. (1)
|
|
|
|
|
24.1
|
|
Power of Attorney (5)
|
|
|
|
|
31.1
|
|
Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)
|
|
|
|
|
31.2
|
|
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)
|
|
|
|
|
32.1
|
|
Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)
|
|
|
|
|
32.2
|
|
Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)
|
|
(2)
|
Filed with the Registrant’s Form 10-QSB for the quarter ended September 30, 2007.
|
|
(3)
|
Filed with the Registrant’s Form 10-QSB for the quarter ended June 30, 2007.
|
|
(4)
|
Filed with the Registrant’s Form 8-K on June 11, 2008.
|
|
(5)
|
Filed with the Registrant’s Form 10-KSB for the year ended December 31, 2007.
|
|
(6)
|
Filed with the Registrant’s Form 10-Q for the quarter ended June 30, 2008.
|
|
(7)
|
Filed with the Registrant’s Form 10-Q for the quarter ended September 30, 2008.
|
66
GEORESOURCES, INC. and SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION
CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of GeoResources, Inc.:
We have audited the accompanying consolidated balance sheets of GeoResources, Inc. (a Colorado corporation) and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements in income,
stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2008. 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
auditing 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.
The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures
that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes,
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 consolidated
financial statements referred to above present fairly, in all material respects, the financial position of GeoResources, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.
/s/ Grant Thornton LLP
Houston, Texas
March 25,
2009
F-2
GEORESOURCES, INC and SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In
thousands, except share and per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
13,967
|
|
|
$
|
24,430
|
|
|
Accounts Receivable
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
|
|
11,439
|
|
|
|
20,365
|
|
|
Joint interest billings and other
|
|
|
7,172
|
|
|
|
3,913
|
|
|
Affiliated partnerships
|
|
|
2,905
|
|
|
|
3,360
|
|
|
Notes receivable
|
|
|
120
|
|
|
|
600
|
|
|
Derivative financial instruments
|
|
|
8,200
|
|
|
|
—
|
|
|
Income taxes receivable
|
|
|
2,165
|
|
|
|
—
|
|
|
Prepaid expenses and other
|
|
|
3,923
|
|
|
|
1,430
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
49,891
|
|
|
|
54,098
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
204,536
|
|
|
|
187,640
|
|
|
Unproved properties
|
|
|
2,409
|
|
|
|
5,142
|
|
|
Office and other equipment
|
|
|
1,025
|
|
|
|
995
|
|
|
Land
|
|
|
96
|
|
|
|
96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
208,066
|
|
|
|
193,873
|
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(26,486
|
)
|
|
|
(12,430
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net property and equipment
|
|
|
181,580
|
|
|
|
181,443
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in oil and gas limited partnerships
|
|
|
3,266
|
|
|
|
1,880
|
|
|
Derivative financial instruments
|
|
|
6,409
|
|
|
|
—
|
|
|
Deferred financing costs and other
|
|
|
2,388
|
|
|
|
2,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
243,534
|
|
|
$
|
240,358
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these statements.
F-3
GEORESOURCES, INC and SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2008
|
|
2007
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
10,750
|
|
$
|
11,374
|
|
|
Accounts payable to affiliated partnerships
|
|
|
10,310
|
|
|
9,538
|
|
|
Revenue and royalties payable
|
|
|
11,701
|
|
|
14,567
|
|
|
Drilling advances
|
|
|
2,169
|
|
|
882
|
|
|
Accrued expenses
|
|
|
1,506
|
|
|
3,839
|
|
|
Derivative financial instruments
|
|
|
1,572
|
|
|
6,527
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
38,008
|
|
|
46,727
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
40,000
|
|
|
96,000
|
|
|
Deferred income taxes
|
|
|
17,868
|
|
|
6,476
|
|
|
Asset retirement obligations
|
|
|
5,418
|
|
|
7,827
|
|
|
Derivative financial instruments
|
|
|
1,245
|
|
|
15,296
|
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
|
Common stock, par value $0.01 per share; authorized 10,000,000 shares; issued and outstanding: 16,241,717 shares in 2008 and 14,703,383 in
2007
|
|
|
162
|
|
|
147
|
|
|
Additional paid-in capital
|
|
|
112,523
|
|
|
79,690
|
|
|
Accumulated other comprehensive income (loss)
|
|
|
7,283
|
|
|
(19,310
|
)
|
|
Retained earnings
|
|
|
21,027
|
|
|
7,505
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders’ equity
|
|
|
140,995
|
|
|
68,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
243,534
|
|
$
|
240,358
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these statements.
F-4
GEORESOURCES, INC. and SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In
thousands, except share and per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
2006
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
|
$
|
85,263
|
|
|
$
|
36,518
|
|
$
|
13,978
|
|
|
Partnership management fees
|
|
|
1,725
|
|
|
|
969
|
|
|
260
|
|
|
Property operating income
|
|
|
1,430
|
|
|
|
1,251
|
|
|
1,076
|
|
|
Gain on sale of property and equipment
|
|
|
4,362
|
|
|
|
49
|
|
|
335
|
|
|
Partnership income
|
|
|
1,061
|
|
|
|
184
|
|
|
91
|
|
|
Interest and other
|
|
|
765
|
|
|
|
1,144
|
|
|
1,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
94,606
|
|
|
|
40,115
|
|
|
16,805
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
22,914
|
|
|
|
10,818
|
|
|
4,252
|
|
|
Severance taxes
|
|
|
7,517
|
|
|
|
2,880
|
|
|
1,066
|
|
|
Re-engineering and workovers
|
|
|
3,518
|
|
|
|
2,092
|
|
|
384
|
|
|
Exploration expense
|
|
|
2,592
|
|
|
|
153
|
|
|
558
|
|
|
Impairment of oil and gas properties
|
|
|
8,339
|
|
|
|
—
|
|
|
184
|
|
|
General and administrative expense
|
|
|
7,168
|
|
|
|
6,513
|
|
|
2,804
|
|
|
Depreciation, depletion and amortization
|
|
|
16,007
|
|
|
|
7,507
|
|
|
3,382
|
|
|
Hedge ineffectiveness
|
|
|
(123
|
)
|
|
|
287
|
|
|
(393
|
)
|
|
Loss on derivative contracts
|
|
|
563
|
|
|
|
—
|
|
|
—
|
|
|
Interest
|
|
|
4,820
|
|
|
|
1,916
|
|
|
288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expense
|
|
|
73,315
|
|
|
|
32,166
|
|
|
12,525
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
21,291
|
|
|
|
7,949
|
|
|
4,280
|
|
|
|
|
|
|
|
Income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
866
|
|
|
|
1,472
|
|
|
—
|
|
|
Deferred
|
|
|
6,903
|
|
|
|
3,408
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,769
|
|
|
|
4,880
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
13,522
|
|
|
$
|
3,069
|
|
$
|
4,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share (basic)
|
|
$
|
0.87
|
|
|
$
|
0.25
|
|
$
|
0.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share (diluted)
|
|
$
|
0.86
|
|
|
$
|
0.25
|
|
$
|
0.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
15,598,244
|
|
|
|
12,404,771
|
|
|
4,858,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
15,751,185
|
|
|
|
12,404,771
|
|
|
4,858,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these statements
F-5
GEORESOURCES, INC. and SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY and COMPREHENSIVE INCOME (LOSS)
Years Ended December 31, 2008, 2007 and 2006
(In thousands except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
Additional
Paid-in
Capital
|
|
Retained
Earning
|
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
|
Total
|
|
|
|
|
Shares
|
|
Par value
|
|
|
|
|
|
Balance, January 1, 2006
|
|
4,858,000
|
|
$
|
49
|
|
$
|
16,427
|
|
$
|
5,219
|
|
|
$
|
(4,134
|
)
|
|
$
|
17,561
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
4,247
|
|
|
|
|
|
|
|
4,247
|
|
|
Change in fair market value of hedged positions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
648
|
|
|
|
648
|
|
|
Net realized hedging losses charged to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,807
|
|
|
|
1,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity based compensation expense
|
|
|
|
|
|
|
|
422
|
|
|
|
|
|
|
|
|
|
|
422
|
|
|
Stockholder distributions
|
|
|
|
|
|
|
|
|
|
|
(1,023
|
)
|
|
|
|
|
|
|
(1,023
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
4,858,000
|
|
|
49
|
|
|
16,849
|
|
|
8,443
|
|
|
|
(1,679
|
)
|
|
|
23,662
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For cash
|
|
3,529,500
|
|
|
35
|
|
|
22,597
|
|
|
|
|
|
|
|
|
|
|
22,632
|
|
|
Merger transaction, including cash of $886
|
|
6,285,477
|
|
|
63
|
|
|
39,473
|
|
|
|
|
|
|
|
|
|
|
39,536
|
|
|
For properties
|
|
30,406
|
|
|
—
|
|
|
218
|
|
|
|
|
|
|
|
|
|
|
218
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
3,069
|
|
|
|
|
|
|
|
3,069
|
|
|
Change in fair market value of hedged positions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,541
|
)
|
|
|
(20,541
|
)
|
|
Net realized hedging losses charged to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,910
|
|
|
|
2,910
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,562
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity based compensation expense
|
|
|
|
|
|
|
|
553
|
|
|
|
|
|
|
|
|
|
|
553
|
|
|
Stockholder distributions
|
|
|
|
|
|
|
|
|
|
|
(4,007
|
)
|
|
|
|
|
|
|
(4,007
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
14,703,383
|
|
|
147
|
|
|
79,690
|
|
|
7,505
|
|
|
|
(19,310
|
)
|
|
|
68,032
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For cash, net of issuance costs of $2,313
|
|
1,533,334
|
|
|
15
|
|
|
32,172
|
|
|
|
|
|
|
|
|
|
|
32,187
|
|
|
For services
|
|
5,000
|
|
|
—
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
13,522
|
|
|
|
|
|
|
|
13,522
|
|
|
Change in fair market value of hedged positions, net of taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,019
|
|
|
|
20,019
|
|
|
Net realized hedging losses charged to income, net of taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,574
|
|
|
|
6,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity based compensation expense
|
|
|
|
|
|
|
|
626
|
|
|
|
|
|
|
|
|
|
|
626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
16,241,717
|
|
$
|
162
|
|
$
|
112,523
|
|
$
|
21,027
|
|
|
$
|
7,283
|
|
|
$
|
140,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these statements.
F-6
GEORESOURCES, INC. and SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands, except share and per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
13,522
|
|
|
$
|
3,069
|
|
|
$
|
4,247
|
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
16,007
|
|
|
|
7,507
|
|
|
|
3,382
|
|
|
Exploratory dry holes and unproved property impairments
|
|
|
2,241
|
|
|
|
—
|
|
|
|
—
|
|
|
Impairment of properties
|
|
|
8,339
|
|
|
|
—
|
|
|
|
184
|
|
|
Gain on sale of property and equipment
|
|
|
(4,362
|
)
|
|
|
(49
|
)
|
|
|
(335
|
)
|
|
Accretion of asset retirement obligations
|
|
|
391
|
|
|
|
232
|
|
|
|
88
|
|
|
Unrealized loss on derivative contracts
|
|
|
563
|
|
|
|
—
|
|
|
|
—
|
|
|
Hedge ineffectiveness (gain) loss
|
|
|
(123
|
)
|
|
|
287
|
|
|
|
(393
|
)
|
|
Partnership income
|
|
|
(1,061
|
)
|
|
|
(184
|
)
|
|
|
(91
|
)
|
|
Partnership distributions
|
|
|
653
|
|
|
|
204
|
|
|
|
—
|
|
|
Deferred income taxes
|
|
|
6,903
|
|
|
|
3,408
|
|
|
|
33
|
|
|
Non-cash compensation
|
|
|
661
|
|
|
|
553
|
|
|
|
422
|
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in accounts receivable
|
|
|
3,958
|
|
|
|
(13,872
|
)
|
|
|
3,306
|
|
|
Decrease in notes receivable
|
|
|
480
|
|
|
|
—
|
|
|
|
—
|
|
|
Decrease (increase) in prepaid expense and other
|
|
|
(1,990
|
)
|
|
|
(347
|
)
|
|
|
110
|
|
|
Increase (decrease) in accounts payable and accrued expense
|
|
|
(3,844
|
)
|
|
|
20,056
|
|
|
|
(1,801
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
42,338
|
|
|
|
20,864
|
|
|
|
9,152
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of property and equipment
|
|
|
26,789
|
|
|
|
2,419
|
|
|
|
335
|
|
|
Additions to property and equipment
|
|
|
(51,824
|
)
|
|
|
(110,148
|
)
|
|
|
(14,725
|
)
|
|
Investment in oil and gas limited partnership
|
|
|
(978
|
)
|
|
|
(1,632
|
)
|
|
|
—
|
|
|
Cancelation of hedge contracts
|
|
|
(2,975
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Increase in other assets
|
|
|
—
|
|
|
|
(565
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(28,988
|
)
|
|
|
(109,926
|
)
|
|
|
(14,390
|
)
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock
|
|
|
32,187
|
|
|
|
23,518
|
|
|
|
—
|
|
|
Distributions to stockholders
|
|
|
—
|
|
|
|
(4,007
|
)
|
|
|
(1,023
|
)
|
|
Issuance of long-term debt
|
|
|
—
|
|
|
|
99,000
|
|
|
|
7,000
|
|
|
Reduction of long-term debt
|
|
|
(56,000
|
)
|
|
|
(9,800
|
)
|
|
|
(2,100
|
)
|
|
Debt issuance costs
|
|
|
—
|
|
|
|
(1,436
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(23,813
|
)
|
|
|
107,275
|
|
|
|
3,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(10,463
|
)
|
|
|
18,213
|
|
|
|
(1,361
|
)
|
|
Cash and cash equivalents at beginning of period
|
|
|
24,430
|
|
|
|
6,217
|
|
|
|
7,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
13,967
|
|
|
$
|
24,430
|
|
|
$
|
6,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
5,073
|
|
|
$
|
835
|
|
|
$
|
154
|
|
|
Income taxes paid
|
|
$
|
3,970
|
|
|
$
|
1,533
|
|
|
|
—
|
|
|
Non-cash net assets acquired in merger transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GeoResources
|
|
|
|
|
|
$
|
23,827
|
|
|
|
|
|
|
PICA Energy, LLC
|
|
|
|
|
|
$
|
11,703
|
|
|
|
|
|
|
Yuma property interests
|
|
|
|
|
|
$
|
3,120
|
|
|
|
|
|
|
Other property interests
|
|
|
|
|
|
$
|
218
|
|
|
|
|
|
The accompanying notes are an integral part of these statements.
F-7
GEORESOURCES, INC. and SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2008, 2007 and 2006
NOTE A: Organization and Summary of Significant Accounting Policies
Merger
On April 17, 2007, pursuant to the terms
of an Agreement and Plan of Merger (“Merger Agreement”), GeoResources, Inc. (“GeoResources” or the “Company”), a Colorado corporation, acquired Southern Bay Oil & Gas, L.P. (“Southern Bay”), a Texas
limited partnership, PICA Energy, LLC (“PICA”), a Colorado limited liability company and subsidiary of Chandler Energy LLC, and certain oil and gas properties in exchange for 10,690,000 shares of common stock (the “Merger”).
These transactions resulted in a change in stockholder control of the Company. As a result of the Merger, the former Southern Bay partners received a majority of the outstanding common stock of the Company and thus, obtained voting control of the
Company. Accordingly, for financial reporting purposes, the Merger was accounted for as a reverse acquisition of GeoResources and PICA by Southern Bay. Therefore, the results of operations and cash flows as presented herein for the year ended
December 31, 2008 are those attributable to the combined entities. The results of operations and cash flows for the year ended December 31, 2007 are those attributable to the former Southern Bay entity for the entire twelve months and
those of the combined entity for the period from April 18, 2007, through December 31, 2007. The results of operations and cash flows for the year ended December 31, 2006, are those attributable to the former Southern Bay entity.
Organization and Basis of Presentation
GeoResources operates a single business segment involved in the acquisition, development and production of, and exploration for, crude oil, natural gas and related products primarily in Texas, Louisiana, Oklahoma, North Dakota, Montana and
Colorado.
Summary of Significant Accounting Policies
Basis of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly-owned
subsidiaries. Intercompany accounts and transactions have been eliminated. The Company’s investments in oil and gas limited partnerships for which it serves as general partner are accounted for under the equity method.
All events described or referred to as prior to April 18, 2007, relate to Southern Bay as the accounting acquirer.
Prior Year Reclassification
Certain
reclassifications have been made to prior period amounts to conform to current period presentation of revenues and royalties payable in the Consolidated Balance Sheet as of December 31, 2007.
Cash and Cash Equivalents
Cash and cash equivalents
consists of all demand deposits and funds invested in highly liquid investments with an original maturity of three months or less.
The
Company maintains its cash and cash equivalents at financial institutions. The combined account balances at several institutions typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is
a concentration of credit risk related to amounts on deposit in excess of FDIC insurance coverage. Management believes that this risk is not significant.
F-8
Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for oil and gas operations whereby cost to acquire mineral investments in oil and gas properties, to drill successful exploratory wells, to drill and
equip development wells, and to install production facilities are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. The Company’s acquisition
and development costs of proved oil and gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively, as estimated by independent petroleum
engineers.
Oil and gas properties are assessed for impairment whenever changes in facts and circumstances indicate a possible significant
deterioration in the future cash flow expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to its estimated
fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair
value of impaired assets is determined based on expected future cash flows using discount rates commensurate with the risks involved and using prices and costs consistent with those used for internal decision making. Long-lived assets committed by
the Company for disposal are accounted for at the lower of cost or fair value, less cost to sell. The Company recognized impairments of $9,194,000 for the year ended December 31, 2008. Impairments of $8,339,000 were recognized on proved
properties and are classified as impairments on the Company’s income statement. The remaining $855,000 of impairments resulted from the write-off of unproved properties during the second and fourth quarters of 2008 and is included in
exploration expense on the Company’s Consolidated Statement of Income. The Company recognized no impairments and $184,000 for the years ended December 31, 2007 and 2006, respectively.
Office and Other Property
Acquisitions and
improvements of office and other property are capitalized at cost; maintenance and repairs are expensed as incurred. Depreciation of equipment is calculated using the straight-line method over the assets estimated useful lives of 5-7 years.
Leasehold improvements are amortized over the remaining term of the lease. When assets are sold, retired, or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and a gain or loss is recognized.
Net Income Per Common Share
Basic net
income per common share is computed based on the weighted average shares of common stock outstanding. Net income per share computations to reconcile basic and diluted net income for 2008, 2007 and 2006 consist of the following (in thousands except
per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
Net income available for common
|
|
$
|
13,522
|
|
$
|
3,069
|
|
$
|
4,247
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares
|
|
|
15,598
|
|
|
12,405
|
|
|
4,858
|
|
Effect of dilutive securities - options
|
|
|
153
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares
|
|
|
15,751
|
|
|
12,405
|
|
|
4,858
|
|
|
|
|
|
|
Earning per share
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.87
|
|
$
|
0.25
|
|
$
|
0.87
|
|
Diluted
|
|
$
|
0.86
|
|
$
|
0.25
|
|
$
|
0.87
|
Options to purchase 25,000 shares were excluded from the diluted earnings per share calculation in
2008 because the options’ exercise prices exceeded the average market price of the common shares during the period.
F-9
On February 3, 2009, the Compensation Committee of the Board of Directors granted additional options
to officers and board members to purchase an additional 500,000 share of the Company’s common stock, for further information see Note D below.
Stock-Based Compensation
Effective January 1, 2006, the Company accounts for stock-based compensation in accordance
with SFAS No. 123(R), “Share-Based Payment.” SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.
Fair Value of Financial Instruments
The carrying
amount of cash and cash equivalents, accounts receivable and payable and revenue royalties payable are estimated to approximate their fair values due to the short maturities of these instruments. The Company’s long-term debt obligation bears
interest at floating market rates, so carrying amounts and fair values are approximately the equal. Derivative financial instruments are carried at fair value.
Income Taxes
Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes
are based on temporary differences between the amount of taxable income and pretax financial income and between the tax bases of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets and liabilities are
included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. Tax positions are evaluated for recognition and measurement,
with deferred tax balances recorded at their anticipated settlement amounts. A valuation allowance is provided for deferred tax assets not expected to be realized.
Other Comprehensive Income (Loss)
The Company follows SFAS No. 130, “Reporting Comprehensive Income”, which
established standards for reporting and display of comprehensive income and its components in a full set of general-purpose financial statements. Other comprehensive income (loss) at December 31, 2008, 2007 and 2006 consists of unrealized gains
(losses) of commodity hedges qualifying as cash flow hedges in accordance with SFAS No. 133.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. Oil and gas reserve estimates, which are the basis for units-of-production depletion, are inherently imprecise and are expected to change as future information becomes available.
Derivative Instruments and Hedging Activities
The
Company enters into derivative contracts, primarily options, collars and swaps, to hedge future crude oil and natural gas production, as well as interest rates, in order to mitigate the risk of downward movements of oil and gas market prices and the
upward movement of interest rates. As required, the Company follows SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended. Under SFAS No. 133, all derivatives are recognized on the balance sheet
and measured at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on
the derivative is deferred in other comprehensive income to the extent the hedge is effective for cash flow hedges. To qualify for hedge accounting, the derivative must qualify either as a fair value, cash flow or foreign currency hedge.
F-10
The hedging relationship between the hedged instruments and hedged transactions must be highly effective
in achieving the offset of changes in fair values and cash flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis. The Company measures hedge effectiveness on a quarterly basis. Hedge accounting is
discontinued prospectively when a hedging instrument becomes ineffective. The Company assesses hedge effectiveness based on total changes in the fair value of options used in cash flow hedges rather than changes in intrinsic value only. As a result,
changes in the entire value of option contracts are deferred in accumulated other comprehensive income until the hedged transaction affects earnings to the extent such contracts are effective. 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.
Gains and losses resulting from hedge settlements are included in oil and gas revenues and are included in realized prices in the period that the related production is delivered. Gains and losses on hedging instruments that represent hedge
ineffectiveness and gains and losses on derivative instruments that do not qualify for hedge accounting are included in other revenues or expenses in the period in which they occur. The resulting cash flows are reported as cash flows from operating
activities.
Asset Retirement Obligations
In accordance with the requirements of Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations (“ARO”), the Company recognizes the present value of the estimated
future abandonment costs of its oil and gas properties in both assets and liabilities. If a reasonable estimate of the fair value can be made, the Company will record a liability for legal obligations associated with the future retirement of
tangible long-lived assets that result from the acquisition, construction, development and/or normal operation of the assets. The fair value of a liability for an asset retirement obligation is recognized in the period in which the liability is
incurred. The fair value is measured using expected future cash outflows (estimated using current prices that are escalated by an assumed inflation rate) discounted at the Company’s credit-adjusted risk-free interest rate. The liability is then
accreted each period until it is settled or the asset is sold, at which time the liability is reversed and any gain or loss resulting from the settlement of the obligation is recorded. The initial fair value of the asset retirement obligation is
capitalized and subsequently depreciated or amortized as part of the carrying amount of the related asset.
The Company has recorded asset
retirement obligations related to its oil and gas properties. There are no assets legally restricted for the purpose of settling asset retirement obligations.
Revenue Recognition
Revenues represent income from production and delivery of oil and gas, recorded net of royalties. The
Company follows the sales method of accounting for gas imbalances. A liability is recorded only if the Company’s takes of gas volumes exceed its share of estimated recoverable reserves from the respective well or field. No receivables are
recorded for those wells where the Company has taken less than its ownership share of production. Volumetric production is monitored to minimize imbalances, and such imbalances were not significant at December 31, 2008, 2007 or 2006.
Accounts Receivable
The Company sells
crude oil and natural gas to various customers. In addition, the Company participates with other parties in the operation of crude oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers
of crude oil and natural gas or participants in crude oil and natural gas wells for which subsidiaries of the Company serve as the operator. Generally, operators of crude oil and natural gas properties have the right to offset future revenues
against unpaid charges related to operated wells. Crude oil and natural gas sales are generally unsecured.
As is common industry practice,
the Company generally does not require collateral or other security as a condition of sale, rather relying on credit approval, balance limitation and monitoring procedures to control the credit use on accounts receivable. The allowance for doubtful
accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any
F-11
collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current
economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance.
Accounts receivable allowance for bad debt was $150,000 at December 31, 2008 and 2007.
Recently Issued Accounting Pronouncements
On
December 31, 2008, the SEC published the revised rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in existing oil and gas rules to make them consistent with the
petroleum resources management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in
reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used in determining reserves. To determine reserves companies must use a 12-month average price. The
Company is required to comply with the amended disclosure requirement for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted.
We are currently assessing the impact that the adoption will have on the Company’s disclosures, operating results, financial position and cash flows.
In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement No. 161,
Disclosure about Derivative Instruments and Hedging Activities – an amendment to FASB Statement
No. 133
(“SFAS 161”). The adoption of SFAS 161 is not expected to have an impact on the Company’s consolidated financial statements, other than additional disclosures. SFAS 161 expands interim and annual disclosures about
derivative and hedging activities that are intended to better convey the purpose of derivative use and the risks managed. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008.
In December 2007, the FASB issued Statement No. 160,
Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB
No. 51
(“SFAS 160”). This statement amends ARB No. 51 and intends to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements
by establishing accounting and reporting standards on the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. SFAS 160 is effective for fiscal years, and interim periods, beginning on or after December 15,
2008. The Company does not believe that this statement will have a material impact on its consolidated financial statements.
In December
2007, the FASB issued Statement No. 141R,
Business Combinations
(“SFAS 141R”). SFAS 141R may have an impact on the Company’s consolidated financial statements when effective, but the nature and magnitude of the specific
effects will depend upon the nature, terms, and size of the acquisitions that the Company consummates after the effective date. SFAS 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its
financial statements, the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also provides guidance for recognizing and measuring goodwill acquired in business combinations and
determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of business combinations. SFAS 141R is effective for financial statements issued for fiscal years beginning after
December 15, 2008. The Company intends to adopt SFAS 141R effective January 1, 2009, and apply its provisions prospectively.
In
February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement No. 159,
The Fair Value Option for Financial Assets and Financial Liabilities
(“SFAS 159”). This new standard permits an entity to make
an irrevocable election at specific election dates to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied
to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS 159 established presentation and disclosure requirements intended to help financial statement users understand the effect of the entity’s election on
earnings. SFAS 159 was effective as of the beginning of the first fiscal year beginning after November 15, 2007. The Company elected not to adopt the fair value option provision allowed under SFAS 159.
F-12
NOTE B: Significant Acquisitions
Merger
The net assets of the acquired GeoResources and PICA as well as certain other acquired
oil and gas properties pursuant to the Merger, which occurred on April 17, 2007, were recorded at fair value using the purchase method of accounting, as required by generally accepted accounting principles. Such net assets consisted of cash and
other current assets and liabilities, oil and gas properties, certain mineral leases and options, and debt. The fair value of the net assets acquired in these purchases was based on the average trading price of GeoResources common stock immediately
before and after the public announcement of the Merger Agreement, of $6.29 per share.
The following is a summary of the assets acquired
and liabilities assumed in the Merger (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GeoResources
|
|
PICA
|
|
Other Oil
& Gas
Properties
|
|
Total
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets, including cash of $886
|
|
$
|
1,858
|
|
$
|
1,591
|
|
$
|
—
|
|
$
|
3,449
|
|
Oil and gas properties
|
|
|
34,347
|
|
|
12,457
|
|
|
3,266
|
|
|
50,070
|
|
Mining leases
|
|
|
2,000
|
|
|
—
|
|
|
—
|
|
|
2,000
|
|
Drilling rig and equipment
|
|
|
1,500
|
|
|
—
|
|
|
—
|
|
|
1,500
|
|
Other assets
|
|
|
405
|
|
|
426
|
|
|
—
|
|
|
831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,110
|
|
|
14,474
|
|
|
3,266
|
|
|
57,850
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
1,817
|
|
|
518
|
|
|
—
|
|
|
2,335
|
|
Long-term debt
|
|
|
50
|
|
|
1,750
|
|
|
—
|
|
|
1,800
|
|
Deferred income taxes
|
|
|
12,511
|
|
|
—
|
|
|
—
|
|
|
12,511
|
|
Asset retirement obligations
|
|
|
1,462
|
|
|
60
|
|
|
146
|
|
|
1,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,840
|
|
|
2,328
|
|
|
146
|
|
|
18,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets
|
|
$
|
24,270
|
|
$
|
12,146
|
|
$
|
3,120
|
|
$
|
39,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AROC Energy Acquisition
October 16, 2007, the Company, through a wholly-owned subsidiary, entered into an agreement to purchase (“Purchase Agreement”) all of the limited partnership interest in AROC
Energy, L.P., an affiliated limited partnership for which the Company served as general partner. The limited partner was an unaffiliated entity. Prior to this transaction, the Company owned 2% of the partnership and the limited partner owned the
remaining 98%. This acquisition, which was accounted for as a purchase, included oil and gas properties located in Louisiana, the Gulf Coast, South Texas, the Permian Basin and the Black Warrior Basin.
Under the Purchase Agreement, the Company purchased the interest for a cash purchase price of $91,100,000 and paid $12,952,000 to cancel the limited
partnership’s oil and gas hedge contracts. These costs were funded with cash of $8,052,000 and borrowings of $96 million under the Amended Credit Agreement discussed in Note C. The Company also paid its bank a fee of $1,250,000 in connection
with the acquisition. The purchase of the interest was effective on the date of closing of the Purchase Agreement, October 16, 2007, and resulted in the Company’s total ownership percentage of 100% of the limited partnership. In November
2007, the Company dissolved the limited partnership.
F-13
The following is a summary of the underlying assets and liabilities attributable to the acquired interest
(in thousands):
|
|
|
|
|
|
Assets:
|
|
|
|
|
Current assets
|
|
$
|
13,385
|
|
Oil and gas properties
|
|
|
102,165
|
|
Other assets
|
|
|
479
|
|
|
|
|
|
|
|
|
|
116,029
|
|
Liabilities:
|
|
|
|
|
Current liabilities, excluding commodity hedges
|
|
|
2,119
|
|
Commodity hedges:
|
|
|
|
|
Extinguished
|
|
|
12,693
|
|
Retained
|
|
|
2,219
|
|
Asset retirement obligations
|
|
|
6,648
|
|
|
|
|
|
|
|
|
|
23,679
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
92,350
|
|
|
|
|
|
Other Acquisitions and Dispositions
In January 2007, Southern Bay formed two entities in connection with the acquisition of producing oil and gas properties located in southeast Texas. Catena Oil & Gas LLC
(“Catena”) was formed as an indirect wholly-owned subsidiary of Southern Bay and SBE Partners LP (“SBE”) was formed with Catena as general partner with a 2% partnership interest, and a large institutional investor as the sole
limited partner with a 98% partnership interest. In February, 2007 these entities paid cash of $82 million to acquire certain southeast Texas properties. Catena purchased 8% of the interests and SBE purchased the remaining 92%. Catena’s share
of the property purchase price was $6.6 million, and its general partner contribution to SBE was $1.6 million. Southern Bay funded these amounts with additional capital contributions from its partners of $5.0 million, borrowings under its bank
credit agreement of $3.0 million and working capital of $200,000. The Company’s investment in SBE is accounted for under the equity method of accounting.
In May 2008, Southern Bay, through Catena, formed an entity in connection with the acquisition of producing oil and gas properties located throughout Oklahoma. OKLA Energy Partners LP (“OKLA”) was formed
with Catena as general partner with a 2% partnership interest, and a large institutional investor as the sole limited partner with a 98% partnership interest. In May, 2008, these entities paid cash of $61.7 million to acquire certain Oklahoma
properties. Catena, purchased 18% of the interests and OKLA purchased the remaining 82%. Catena’s share of the property purchase price was $12.8 million, and its general partner contribution to OKLA was $978,000. The Company’s investment
in OKLA is accounted for under the equity method of accounting.
In January 2008, the Company sold all of its interest in the Grand Canyon
Unit, a property acquired in the Merger. This property, located in Otsego County, Michigan, was sold to an unaffiliated party for $6.6 million in cash. The carrying value of this property at the date of the sale was equal to the selling price;
therefore, no gain or loss was recognized on sale.
In February 2008, the Company acquired producing properties in the Williston Basin of
North Dakota and Montana from an unaffiliated party for $7.9 million in cash. The acquired properties are operated by the Company. The purchase price was allocated to oil and gas properties.
In February 2008, the Company sold its interests in certain non-core oil and gas properties located in Louisiana to unaffiliated parties for $1.8 million in cash and recognized gains of $430,000.
In May 2008, the Company closed certain property sales. These sales consisted of seven non-core fields in Louisiana and Texas and were
sold to unaffiliated parties for approximately $11.8 million. The Company recognized a gain of $1.5 million related to these sales.
F-14
In September 2008, the Company acquired certain producing properties in Oklahoma from an unaffiliated
party for $3.6 million in cash. The acquired properties are operated by the Company. The purchase price was allocated to oil and gas properties.
During 2008, the Company identified an exploration opportunity and began leasing in various counties in Colorado and Utah targeting the Gothic Shale as a newly emerging resource play with multiple other objectives. In November, 2008, the
Company sold the majority of its interest for $6 million and recognized a gain of $2.5 million. The Company retained an overriding royalty interest or the option to participate, under certain circumstances, for up to 12.5% working interest.
NOTE C: Long-term debt
On
September 26, 2007, the Company entered into a Credit Agreement with Wachovia Bank, as Administrative Agent and Issuing Bank and U.S. Bank as Lenders. This agreement provided for a Senior Secured Revolving Credit Facility in the maximum amount
of $100 million, with an initial borrowing base of $35 million.
On October 16, 2007, the Company entered into an Amended and Restated
Credit Agreement (“Amended Credit Agreement”) with Wachovia Bank (the “Bank”) as Administrative agent, Issuing Bank, Sole Lead Arranger and Sole Bookrunner. The Amended Credit Agreement provides for financing of up to $200
million to the Company. The initial borrowing base of the Amended Credit Facility was $110 million, subject to redetermination on April 1 and October 1 of each year. On September 30, 2008, the borrowing was reduced to $95 million due
to the sales of certain non-core oil and gas properties. On November 5, 2008, the borrowing base was increased to $100 million and the Amended Credit Agreement was amended to provide for interest rates at (a) LIBOR plus 1.75% to 2.50%, or
(b) the prime lending rate plus .75% to 1.50%, depending on the amount borrowed. Principal amounts outstanding under this Amended Credit Agreement are due and payable in full at maturity on October 16, 2010. The Amended Credit Agreement
also requires the payment of commitment fees to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.375% to 0.50% per year depending on the amount of borrowing base utilization. The Company is also required
to pay customary letter of credit fees. All of the obligations under the Amended Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets.
On October 16, 2007, the Company borrowed $96.0 million under the Amended Credit Agreement, in connection with the AROC Energy acquisition.
The Company also paid the Bank transaction fees of $1.25 million as well as underwriting fees and other loan costs totaling $1.25 million. At December 31, 2008, the outstanding principal balance was $40.0 million. The annual interest rate
in effect at December 31, 2008 was 2.97% on the entire amount of the outstanding principal.
Also, in October 2007, the Company
entered into an interest rate swap agreement with the Bank, providing a fixed rate of 4.29% on a notional $50,000,000 through October 16, 2010. During 2008, the Company broke the swap up into two pieces, a $40 million swap and a $10 million
swap. The $40 million swap is accounted for as a cash flow hedge while the $10 million swap is accounted for as a trading security. The fair market value of these swaps at December 31, 2008, was a liability of $2,817,000 of which $1,572,000 is
classified as a current liability. The Company also recognized a loss of $563,000 on the $10 million swap during 2008 and no gain or loss was recognized on the swap existing during 2007. The value of the swap at December, 31, 2007 was a liability of
$854,000, of which $476,000 was classified as a current liability.
At December 31, 2008, accumulated other comprehensive income
included unrecognized losses of $1,394,000, net of a tax benefit of $859,000, representing the inception to date change in mark-to-market value of the Company’s $40 million interest rate swap, designated as a hedge, as of the balance sheet
date. At December 31, 2007, accumulated other comprehensive income (loss) included $854,000 of unrecognized losses, representing the inception to date change in mark-to-market value of the Company’s $50 million interest rate swap. For the
year ended December 31, 2008, the Company recognized realized cash settlement losses of $656,000 related to its two swaps. The Company did not have any settlement losses related to its interest rate swap in 2007. Based on the estimated fair
market value of the Company’s $40 million derivative contract designated as a hedge at December 31, 2008, the Company expects to reclassify net losses of $1.3 million into earnings from accumulated other comprehensive income during the
next twelve months; however, actual cash settlement gains and losses recognized may differ materially.
F-15
The Amended Credit Agreement contains a number of covenants that, among other things, restrict, subject
to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and lease back transactions, pay dividends and distributions or repurchase its capital stock, engage in
mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates. In addition, the Amended Credit Agreement requires the maintenance of certain financial
ratios, contains customary affirmative covenants, and provides for customary events of default. The Company was in compliance with all covenants at December 31, 2008.
The principal outstanding under the Amended Credit Agreement was $40.0 million at December 31, 2008. The principal outstanding at December 31, 2007, was $96.0 million, which borrowing
was made in connection with the AROC Energy acquisition in October 2007. The remaining borrowing capacity under the Amended Credit Agreement at December 31, 2008, was $60.0 million. The maturity date for amounts outstanding under this agreement
is October 16, 2010.
The weighted average interest rate on borrowings outstanding during 2008, 2007, and 2006 was 6.42%, 7.63% and
8.21%, respectively.
Interest expense for 2008, 2007 and 2006 includes amortization of deferred financing costs of $491,000, $146,000 and
$47,000, respectively.
NOTE D: Stock Options, Performance Awards and Stock Warrants
In March 2007, the shareholders the Company approved the GeoResources, Inc, Amended and Restated 2004 Employees’ Stock Incentive Plan (the “Plan”), which authorizes the issuance of
options and other stock-based incentives to officers, employees, directors and consultants of the Company to acquire up to 2,000,000 shares of the Company’s common stock at prices which may not be less than the stock’s fair market value on
the date of grant. The options can be designated as either incentive options or nonqualified options.
On October 10, 2007, and
November 10, 2007, the Company granted options under the Plan to officers and key employees to purchase 755,000 and 10,000 shares of common stock, respectively. On June 19, 2008, the Company granted options to employees to purchase 25,000
shares of common stock. The following is a summary of the terms of these grants:
|
|
|
|
|
|
|
|
Vesting Date
|
|
Number of
Shares
|
|
Exercise Price
per Share
|
|
October 10, 2009
|
|
377,500
|
|
$
|
8.27
|
|
November 15, 2009
|
|
5,000
|
|
$
|
8.65
|
|
October 10, 2010
|
|
188,750
|
|
$
|
9.56
|
|
November 15, 2010
|
|
2,500
|
|
$
|
9.56
|
|
June 19, 2010
|
|
12,500
|
|
$
|
22.50
|
|
October 10, 2011
|
|
188,750
|
|
$
|
9.56
|
|
November 15, 2011
|
|
2,500
|
|
$
|
9.56
|
|
June 19, 2011
|
|
6,250
|
|
$
|
25.00
|
|
June 19, 2012
|
|
6,250
|
|
$
|
25.00
|
|
|
|
|
|
|
|
|
|
|
790,000
|
|
|
|
|
|
|
|
|
|
|
The closing market prices of the Company’s common stock on the date of the October and
November 2007 grants were $7.20 and $8.65, respectively. The closing market price of the Company’s common stock on the date of the June 2008 grant was $20.99.
On February 3, 2009, the Compensation Committee of the Board of Directors granted additional options to officers and board member to purchase an additional 500,000 shares of the Company’s common stock. These
options vest at the rate of 25% per year beginning February 3, 2010, at an exercise price of $8.50 for 250,000 shares and $10.00 for the remaining 250,000 shares. The closing price of the Company’s stock on February 3, 2009 was
$7.62.
F-16
The options, if not exercised, will expire 10 years from the date of grant.
A summary of the Company’s stock option activity for the year ended December 31, 2008 and 2007 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of Shares
|
|
Weighted
Average
Exercise Price
|
|
Weighted Average
Remaining Contractual
Life (year)
|
|
Aggregate Intrinsic
Value
|
|
Outstanding, January 1, 2007
|
|
—
|
|
|
|
|
|
|
|
|
|
Granted
|
|
765,000
|
|
$
|
8.92
|
|
|
|
|
|
|
Exercised
|
|
—
|
|
$
|
—
|
|
|
|
|
|
|
Forfeited
|
|
—
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, December 31, 2007
|
|
765,000
|
|
|
|
|
9.78
|
|
$
|
275,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
25,000
|
|
$
|
23.75
|
|
|
|
|
|
|
Exercised
|
|
—
|
|
$
|
—
|
|
|
|
|
|
|
Forfeited
|
|
—
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, December 31, 2008
|
|
790,000
|
|
|
|
|
8.81
|
|
$
|
158,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at year-end
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
—
|
|
|
|
|
|
|
|
|
|
2007
|
|
—
|
|
|
|
|
|
|
|
|
The Company accounts for these stock option under the provision of Statement of Financial
Accounting Standards No. 123R, “Share Based Payment” and accordingly, recognized compensation expense based upon the fair value of the options at the date of grant determined by the Black-Scholes option pricing model. For the years
ended December 31, 2008 and 2007 the Company recognized compensation expense of $626,000 and $131,000, respectively, related to these options. As of December 31, 2008, the future pre-tax expense of non-vested stock options is $1,025,000 to
be recognized through 2011.
During 2008 and 2007, the weighted-average fair value of the options granted during the year was $6.82 per
share and $2.14 per share, respectively, using the following assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
Risk-free interest rate
|
|
2.25
|
%
|
|
4.25
|
%
|
|
|
|
|
|
Dividend yield
|
|
None
|
|
|
None
|
|
|
|
|
|
|
Volatility
|
|
52
|
%
|
|
40
|
%
|
|
|
|
|
|
Expected life of option
|
|
4 Years
|
|
|
4 Years
|
|
|
|
|
|
In measuring compensation associated with these options, an annual pre-vesting forfeiture rate of
1% was used.
Partnership Equity Incentive Plan
Prior to the Merger, Southern Bay had an equity incentive plan to provide incentives to employees and independent contractors of Southern Bay by providing such persons with partnership interests designated as Class B units and Class C
units. Units issued under this plan were subject to vesting requirements and, in addition, Class C units did not participate in profits, losses or cash distributions until the Class A units had received certain minimum cash distributions. This
plan was terminated in connection with the Merger on April 17, 2007.
F-17
Southern Bay adopted the provisions of SFAS 123R, “Share-Based Paymnent” effective
January 1, 2006 and as a result, recognized compensation expense of $422,000 for 2006 and $422,000 in 2007, through the date of the Merger.
NOTE
E: Income Taxes
As a partnership, Southern Bay was generally not subject to federal or state income taxes on its taxable income. The
taxable income and deductions were reported by the partners in their respective returns. Therefore, except for the recognition of deferred Texas Margin Tax in 2006, no income taxes were reported by Southern Bay prior to the Merger.
The following table shows the components of the Company’s income tax provision for 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31
|
|
|
|
2008
|
|
2007
|
|
|
|
(in thousands)
|
|
Current:
|
|
|
|
|
|
|
|
Federal
|
|
$
|
695
|
|
$
|
1,348
|
|
State
|
|
|
171
|
|
|
124
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
866
|
|
|
1,472
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
|
|
|
|
|
Federal
|
|
|
6,186
|
|
|
3,103
|
|
State
|
|
|
717
|
|
|
305
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
6,903
|
|
|
3,408
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,769
|
|
$
|
4,880
|
|
|
|
|
|
|
|
|
The following is a reconciliation of taxes computed at the corporate federal statutory income tax
rate of 35% in 2008 and 34% in 2007 to the reported income tax provision for the years ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(in thousands)
|
|
|
Income before income taxes
|
|
$
|
21,291
|
|
|
$
|
7,949
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax computed at federal statutory rate
|
|
$
|
7,452
|
|
|
$
|
2,703
|
|
|
Statutory depletion in excess of tax basis
|
|
|
(562
|
)
|
|
|
—
|
|
|
Domestic production activities deduction
|
|
|
(113
|
)
|
|
|
—
|
|
|
Non-taxable Southern Bay income prior to Merger
|
|
|
—
|
|
|
|
(303
|
)
|
|
Deferred income taxes arising from change in tax status of Southern Bay
|
|
|
—
|
|
|
|
2,214
|
|
|
State income taxes, net of federal benefit
|
|
|
716
|
|
|
|
250
|
|
|
Expense not deductible for tax purposes and other
|
|
|
276
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
$
|
7,769
|
|
|
$
|
4,880
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
36.49
|
%
|
|
|
61.39
|
%
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes are recognized for the tax effects of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and tax purposes, as required by SFAS No. 109, and clarified by FIN 48. The deferred tax is measured using the enacted tax rates applicable to periods when these
differences are expected to reverse.
F-18
The deferred income tax provision for 2007 includes an initial charge of $2,214,000 attributable to
Southern Bay becoming at taxable entity in April 2007, concurrent with the Merger. Generally accepted accounting principles require the recognition of deferred taxes attributable to temporary differences existing at the date of a change in status of
an entity from nontaxable to taxable.
The following table shows the components of the Company’s net deferred tax liability at
December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(in thousands)
|
|
|
Deferred tax asset or (liability)
|
|
|
|
|
|
Current:
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
Oil and gas properties
|
|
|
(15,334
|
)
|
|
|
(9,457
|
)
|
|
Other property and equipment
|
|
|
(101
|
)
|
|
|
(37
|
)
|
|
Equity in limited partnerships
|
|
|
(249
|
)
|
|
|
(89
|
)
|
|
Asset retirement obligations
|
|
|
2,066
|
|
|
|
2,908
|
|
|
Stock-based compensation
|
|
|
204
|
|
|
|
—
|
|
|
Price-risk management liability
|
|
|
(4,488
|
)
|
|
|
—
|
|
|
Other
|
|
|
34
|
|
|
|
199
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(17,868
|
)
|
|
$
|
(6,476
|
)
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008 and 2007, the Company had statutory depletion available for
carryforward of approximately $5.1 million and $7.0 million, respectively, which may be used to offset future taxable income. The amount that may be used in any year is subject to limitations arising from a change in control resulting from the
Merger.
In June 2006, the Financial Accounting Standards Board (“FASB”) issued FIN 48,
Accounting for Uncertainty in Income
Taxes—an Interpretation of FASB Statement No. 109, Accounting for Income Taxes.
This interpretation addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the
financial statements. Under FIN 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical
merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48
also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures. The Company adopted the provisions of FIN 48 on January 1, 2007. There was no
cumulative effect adjustment to retained earnings, our financial condition or results of operations as a result of implementing FIN 48. The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or
results of operations as a result of implementing FIN 48. The amount of unrecognized tax benefits did not materially change during the years ended December 31, 2008 or 2007.
It is expected that the amount of unrecognized tax benefits may change in the next twelve months; however, we do not expect the change to have a significant impact on the results of operations or
the financial position of the Company.
The Company files a consolidated federal income tax return and various combined and separate
filings in several state and local jurisdictions.
The Company’s continuing practice is to recognize estimated interest and penalties
related to potential underpayment on any unrecognized tax benefits as a component of income tax expense in the Consolidated
F-19
Statements of Income. As of the date of adoption of FIN 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax
benefits, nor was any interest expense recognized during 2008. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to
December 31, 2009.
NOTE F: Derivative Financial Instruments
The Company enters into various crude oil and natural gas hedging contracts, primarily costless collars and swaps, in an effort to manage its exposure to product price volatility. Historically, prices received for oil
and gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated
future oil and gas production. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has designated its commodity derivative contracts
as cash flow hedges designed to achieve more predictable cash flows, as well as to reduce its exposure to price volatility. While the use of derivative instruments limits the downside risk of adverse price movements, they also limit future revenues
from favorable price movements. The Company does not enter into commodity derivative instruments for speculative or trading purposes.
At
December 31, 2008, accumulated other comprehensive income (loss) consisted of unrecognized gains of $8,677,000, net of taxes of $5,348,000, representing the inception to date change in mark-to-market value of the effective portion of the
Company’s open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 2007, accumulated other comprehensive income (loss) consisted of $18,456,000 of unrecognized losses. For the years ended
December 31, 2008, 2007 and 2006, the Company recognized realized cash settlement losses on commodity derivatives of $9,970,000, $2,910,000 and $1,807,000, respectively. Based on the estimated fair market value of the Company’s derivative
contracts designated as hedges at December 31, 2008, the Company expects to reclassify net gains of $8,200,000 into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and
losses recognized may differ materially.
On October 17, 2008, the Company paid $2,975,000 to cancel its 2009 natural gas swaps that
were previously accounted for as cash flow hedges. At the time of cancelation, accumulated other comprehensive (loss) contained $482,000 of acquisition to date change in mark-to-market of the effective portion of these commodity derivative
contracts. These accumulated losses will be amortized during 2009 and reduce net income by $482,000. The remainder of the cost to cancel was previously recognized as part of the AROC Energy acquisition or through ineffectiveness charges. The
canceled swaps were acquired as part of the AROC Energy acquisition discussed in Note B.
At December 31, 2008, the Company had hedged
its exposure to the variability in future cash flows from forecasted oil and gas production volumes as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Annual
Volume
|
|
Floor
Price
|
|
Ceiling /
Swap
Price
|
|
Crude Oil Contracts (Bbls):
|
|
|
|
|
|
|
|
|
|
Swap contracts:
|
|
|
|
|
|
|
|
|
|
2009
|
|
368,000
|
|
|
|
|
$
|
76.00
|
|
2010
|
|
322,000
|
|
|
|
|
$
|
74.71
|
|
2011
|
|
282,000
|
|
|
|
|
$
|
74.37
|
|
|
|
|
|
|
Natural Gas Contracts (Mmbtu)
|
|
|
|
|
|
|
|
|
|
Costless collars contracts:
|
|
|
|
|
|
|
|
|
|
2009
|
|
275,530
|
|
$
|
7.00
|
|
$
|
10.75
|
|
2010
|
|
1,287,000
|
|
$
|
7.00
|
|
$
|
9.90
|
|
2011
|
|
1,079,000
|
|
$
|
7.00
|
|
$
|
9.20
|
F-20
The fair market value of these hedge contracts at December 31, 2008 was an asset of $14,609,000 of
which $8,200,000 was classified as a current asset. The fair market value of the Company’s hedge contracts at December 31, 2007 was a liability of $20,969,000, of which $6,051,000 was classified as a current liability. During the year
ended December 31, 2008, the Company recognized a gain of $123,000 due to hedge ineffectiveness on these hedge contracts versus a loss of $287,000 during 2007. During the year ended December 31, 2006, the Company recognized a gain of
$393,000 due to hedge ineffectiveness.
The Company has also entered into an interest rate swap designated as a cash flow hedge as
discussed in Note C above.
NOTE G: Fair Value Disclosures
SFAS 157
– Effective January 1, 2008, the Company adopted Financial Accounting Standards Board (“FASB”) Statement No. 157,
Fair Value Measurements
(“SFAS 157”),
which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. The
implementation of SFAS 157 did not cause a change in the method of calculating fair value assets or liabilities. The primary impact from adoption was additional disclosures.
The Company elected to implement SFAS 157 with the one-year deferral permitted by FASB Staff Position No. FAS 157-2
Effective Date of FASB No. 157
(“FSP 157-2”), issued
February 2008, which defers the effective date of SFAS 157 for one year, until fiscal years beginning after November 15, 2008, for certain nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized
or disclosed at fair value in the financial statements on a recurring basis As it relates to the Company, the deferral applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair
value, impaired oil and gas property assessments, and the initial recognition of asset retirement obligations for which fair value is used. The Company does not believe that the implementation of the deferred provisions of SFAS 157 will cause the
Company to changes its method of calculation fair value of certain nonfinancial assets or liabilities. The Company expects that the primary impact from adoption of these remaining provisions will be additional disclosures.
In October 2008, the FASB issued FASB Staff Position No. FAS 157-3,
Determining the Fair Value of a Financial Asset When the Market for That Asset is
Not Active
(“FSP 157-3”), which clarifies the application of SFAS 157 in an inactive market and provides an example to demonstrate how the fair value of a financial assets is determined when the market for that financial asset is
inactive. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements. FSP 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued.
Fair Value Hierarchy
– SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value
measurements. The valuation hierarchy categorizes assets and liabilities at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
|
|
•
|
|
Level 1
– inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
|
|
|
•
|
|
Level 2
– inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs are observable
for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
|
|
|
•
|
|
Level 3
– inputs to the valuation methodology are unobservable and significant to the fair value measurement.
|
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of the input that is significant to the fair
value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or
F-21
liability. The following table presents information about the Company’s liabilities measured at fair value on a recurring basis as of December 31,
2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices
in Active
Markets for
Identical Assets
(Level
1)
|
|
Significant
Other
Observable
Inputs
(Level
2)
|
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Balances
as of
December 31,
2008
|
|
|
Current portion of derivative financial instrument asset (1)
|
|
—
|
|
$
|
8,200,000
|
|
|
—
|
|
$
|
8,200,000
|
|
|
|
|
|
|
|
|
Long-term portion of derivative financial instrument asset (1)
|
|
—
|
|
|
6,409,000
|
|
|
—
|
|
|
6,409,000
|
|
|
|
|
|
|
|
|
Current portion of derivative financial instrument liability (2)
|
|
—
|
|
|
(1,572,000
|
)
|
|
—
|
|
|
(1,572,000
|
)
|
|
|
|
|
|
|
|
Long-term portion of derivative financial instrument liability (3)
|
|
—
|
|
|
(1,245,000
|
)
|
|
—
|
|
|
(1,245,000
|
)
|
|
(1)
|
Commodity derivative instruments accounted for as cash flow hedges.
|
|
(2)
|
Includes a $40 million interest rate swap accounted for as a cash flow hedge ($1,258,000) and a $10 million interest rate swap accounted for as a trading
security ($314,000).
|
|
(3)
|
Includes a $40 million interest rate swap accounted for as a cash flow hedge ($996,000) and a $10 million interest rate swap accounted for as a trading security
($249,000).
|
Commodity Derivative Instruments
– Commodity derivative instruments consist of costless
collars and swaps for crude oil and natural gas. The Company’s costless collars are valued based on the counterparty’s marked-to-market statements, which are validated by observable transactions for the same or similar commodity options
using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is the NYMEX futures index. The
Company’s model is validated by the counterparty’s marked-to-market statements. The swaps are also designated as Level 2 within the valuation hierarchy. The discount rate used in determining the fair values of these instruments includes a
measure of nonperformance risk.
Interest Rate Swap
– The Company’s interest rate swap is valued using the
counterparty’s marked-to-market statement, which can be validated using modeling techniques that include market inputs such as publically available interest rate yield curves, and is designated as Level 2 within the valuation hierarchy.
At December 31, 2008, the Company has no assets or liabilities measured at fair value on a recurring basis that meet the definition
of Level 1 or Level 3.
NOTE H: Private Placement Offering
On June 5, 2008, the Company issued 1,533,334 shares of common stock and 613,336 warrants to purchase common stock to non-affiliated accredited investors pursuant to exemptions from registration under federal and
state securities laws. The shares of common stock were sold for $22.50 per share. The warrants have a term of five years with an exercise price of $32.43. The gross proceeds to the Company of $34.5 million were reduced by placement fees and issue
costs of $2.3 million.
F-22
NOTE I: Asset Retirement Obligations
The Company’s asset retirement obligations represent the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land
restoration, in accordance with applicable local, state and federal laws. In accordance with Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations
(“SFAS 143”), the Company determines
its obligation by calculating the present value of estimated cash flows related to plugging and abandonment obligations. The changes to the Asset Retirement Obligations (“ARO”) for oil and gas properties and related equipment during the
years ended December 31, 2008 and 2007, are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Balance, beginning of year
|
|
$
|
7,827
|
|
|
$
|
2,478
|
|
|
Additional liabilities incurred
|
|
|
158
|
|
|
|
5,681
|
|
|
Accretion expense
|
|
|
391
|
|
|
|
232
|
|
|
Costs incurred
|
|
|
(69
|
)
|
|
|
—
|
|
|
Disposals of properties
|
|
|
(3,019
|
)
|
|
|
(42
|
)
|
|
Revisions of estimates
|
|
|
130
|
|
|
|
(522
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
5,418
|
|
|
$
|
7,827
|
|
|
|
|
|
|
|
|
|
|
|
NOTE J: Concentration of Credit Risk
Credit risk represents the accounting loss which the Company would record if its customers failed to perform pursuant to the contractual terms. The Company’s largest customers are large
multinational companies. In addition, the Company transacts business with independent oil producers, crude oil trading companies and a variety of other entities. The Company’s credit policy and the relatively short duration of receivables
mitigate the risk of uncollected receivables.
In 2008, one purchaser accounted for 16% of the Company’s consolidated oil and gas
revenue, two more accounted for 11% each and two purchasers accounted for 10% each. In 2007, two purchasers accounted for 17% and 14% of consolidated oil and gas revenues. In 2006, four purchasers accounted for 27%, 18%, 15% and 12% of consolidated
oil and gas revenues. No other single purchaser accounted for 10% or more of our consolidated oil and gas revenues in 2008, 2007, or 2006. There are adequate alternate purchasers of our production such that we believe the loss of one or more of the
above purchasers would not have a material adverse effect on our results of operations or cash flows.
NOTE K: Commitments and Contingencies
Commitments
The Company is
obligated under non-cancelable operating leases for its office facilities as follow (in thousands):
|
|
|
|
|
|
2009
|
|
$
|
319
|
|
2010
|
|
|
176
|
|
2011
|
|
|
9
|
|
Thereafter
|
|
|
—
|
|
|
|
|
|
|
|
|
$
|
504
|
|
|
|
|
|
Total rental expense under operating leases for 2008, 2007 and 2006 was $324,000, $246,000 and
$164,000, respectively.
F-23
Contingencies
No significant legal proceedings are pending which are expected to have a material adverse effect on the Company. The Company is unaware of any potential claims or lawsuits involving environmental, operating or corporate matters which are
expected to have a material adverse effect on the Company’s financial position or results of operations.
NOTE L: Related Party Transactions
In July 2007, the Company acquired oil and gas properties from certain officers and key employees for $1,075,000, including cash of
$856,000 and the issuance of 30,406 shares of common stock at $7.19 per share. Also, in July 2007, the Company issued 100,000 shares of common stock for cash of $719,000 to three individuals, including two members of the board of directors and an
affiliate of one of the Company’s directors.
Accounts receivable at December 31, 2008 and 2007, includes $2,311,000 and
$3,360,000 respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at December 31, 2008, also includes $594,000 due from OKLA Energy Partners LP. Both of these partnerships are oil and gas limited partnerships for
which a subsidiary of the Company serves as general partner. These amounts represent the limited partnerships’ share of property operating expenditures incurred by operating subsidiaries of the Company on their behalf, as well as accrued
management fees. Accounts payable at December 31, 2008 and 2007, includes $9,333,000 and $9,538,000, respectively, due to the SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at December 31, 2008, also
includes $977,000 due to OKLA Energy for oil and gas revenues collected on its behalf.
The Company earned partnership management fees
during the years ended December 31, 2008, 2007, and 2006 of $1,725,000, $969,000, and $260,000 respectively.
Subsidiaries of the
Company operate the majority of oil and gas properties in which the two limited partnerships have an interest. Under this arrangement, the Company collects revenues from purchasers and incurs property operating and development expenditures on each
partnership’s behalf. These revenues are paid monthly to each partnership, which in turn reimburses the Company for the partnership’s share of expenditures.
F-24
NOTE M: Supplemental Financial Quarterly Results (unaudited):
The sum of the individual quarterly basic and diluted earnings (loss) per share amounts may not agree with year-to-date basic and diluted earnings (loss)
per share amounts as a result of each period’s computation being based on the weighted average number of common shares outstanding during that period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
2008
|
|
|
June 30,
2008
|
|
|
September 30,
2008
|
|
|
December 31,
2008
|
|
|
|
|
(in thousands, except per share data)
|
|
|
Year ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
|
$
|
22,463
|
|
|
$
|
25,118
|
|
|
$
|
21,763
|
|
|
$
|
15,919
|
|
|
Other revenues (1)
|
|
|
1,261
|
|
|
|
2,859
|
|
|
|
1,640
|
|
|
|
2,818
|
|
|
Operating expenses (2)
|
|
|
(12,255
|
)
|
|
|
(13,276
|
)
|
|
|
(12,193
|
)
|
|
|
(14,824
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
11,469
|
|
|
|
14,701
|
|
|
|
11,210
|
|
|
|
3,913
|
|
|
Other income (expense), net (3)
|
|
|
(4,649
|
)
|
|
|
(2,365
|
)
|
|
|
(1,583
|
)
|
|
|
(11,405
|
)
|
|
Income tax (expense) benefit
|
|
|
(2,596
|
)
|
|
|
(4,546
|
)
|
|
|
(3,828
|
)
|
|
|
3,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
4,224
|
|
|
$
|
7,790
|
|
|
$
|
5,799
|
|
|
$
|
(4,291
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income (loss) per share
|
|
$
|
0.29
|
|
|
$
|
0.51
|
|
|
$
|
0.36
|
|
|
$
|
(0.26
|
)
|
|
Diluted net income (loss) per share
|
|
$
|
0.29
|
|
|
$
|
0.50
|
|
|
$
|
0.35
|
|
|
$
|
(0.26
|
)
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
2007
|
|
|
June 30,
2007
|
|
|
September 30,
2007
|
|
|
December 31,
2007
|
|
|
|
|
(in thousands, except per share data)
|
|
|
Year ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
|
$
|
3,538
|
|
|
$
|
7,060
|
|
|
$
|
7,513
|
|
|
$
|
18,407
|
|
|
Other revenues (1)
|
|
|
452
|
|
|
|
840
|
|
|
|
817
|
|
|
|
344
|
|
|
Operating expenses (2)
|
|
|
(2,336
|
)
|
|
|
(5,136
|
)
|
|
|
(5,003
|
)
|
|
|
(10,975
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
1,654
|
|
|
|
2,764
|
|
|
|
3,327
|
|
|
|
7,776
|
|
|
Other income (expense), net
|
|
|
(861
|
)
|
|
|
(2,264
|
)
|
|
|
(981
|
)
|
|
|
(3,466
|
)
|
|
Income tax (expense)
|
|
|
(4
|
)
|
|
|
(1,849
|
)
|
|
|
(934
|
)
|
|
|
(2,093
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
789
|
|
|
$
|
(1,349
|
)
|
|
$
|
1,412
|
|
|
$
|
2,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income (loss) per share
|
|
$
|
0.15
|
|
|
$
|
(0.09
|
)
|
|
$
|
0.10
|
|
|
$
|
0.14
|
|
|
Diluted net income (loss) per share
|
|
$
|
0.15
|
|
|
$
|
(0.09
|
)
|
|
$
|
0.10
|
|
|
$
|
0.14
|
|
|
(1)
|
Partnership management fees, property operating income, gain (loss) on sale of property and partnership income.
|
|
(2)
|
Lease operating expense, production taxes, re-engineering & workover, exploration, and depreciation depletion and amortization.
|
|
(3)
|
Other Income (expense), net for the fourth quarter of 2008 included impairment expense of $8.3 million.
|
F-25
NOTE N: SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
1. Costs incurred related to oil and gas activities
The following two unaudited tables set forth costs incurred during the years ended December 31, 2008, 2007 and 2006.
Costs incurred in acquisition, development and exploration:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
(in thousands)
|
|
Acquisition cost
|
|
$
|
33,946
|
|
$
|
151,607
|
|
$
|
9,601
|
|
Development cost
|
|
$
|
16,974
|
|
$
|
3,618
|
|
$
|
5,261
|
|
Exploration cost
|
|
$
|
2,592
|
|
$
|
153
|
|
$
|
548
|
Capitalized cost of oil and gas properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(in thousands)
|
|
|
Proved properties
|
|
$
|
204,536
|
|
|
$
|
187,640
|
|
|
Unproved properties
|
|
|
2,409
|
|
|
|
5,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
206,945
|
|
|
|
192,782
|
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(26,218
|
)
|
|
|
(12,262
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized cost
|
|
$
|
180,727
|
|
|
$
|
180,520
|
|
|
|
|
|
|
|
|
|
|
|
The amounts included in unproved properties are projects for which the Company intends to commence
exploration or evaluation projects in the near future. Of the approximately $2.4 million in net unevaluated property costs at December 31, 2008, that are being excluded from the amortizable base, approximately $1.3 million was incurred in 2007
and $1.0 million was incurred in 2006. The Company will begin to amortize these costs when proved reserves are established or an impairment is determined.
2. Estimated Quantities of Proved Oil and Gas Reserves
The estimates of proved oil and gas reserves
are based on a report by independent petroleum engineers. The estimates at December 31, 2008, 2007 and 2006 were prepared by Cawley, Gillespie & Associates, Inc. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of mature producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. In addition, a portion of the Company’s
proved reserves is undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.
Proved
reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating
conditions existing as of the end of each respective year. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods.
F-26
Presented below is a summary of the changes in estimated proved reserves of the Company, all of which are
located in the United States, for the years ended December 31, 2008, 2007 and 2006:
Oil and Gas Reserve Quantities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
Gas (Mcf)
|
|
|
Proved reserve quantities, December 31, 2005
|
|
1,329
|
|
|
5,480
|
|
|
Purchase of minerals-in-place
|
|
507
|
|
|
—
|
|
|
Production
|
|
(184
|
)
|
|
(577
|
)
|
|
Revision of quantity estimates
|
|
125
|
|
|
(685
|
)
|
|
|
|
|
|
|
|
|
|
Proved reserve quantities, December 31, 2006
|
|
1,777
|
|
|
4,218
|
|
|
Purchase of minerals-in-place
|
|
9,080
|
|
|
27,977
|
|
|
Extensions and discoveries
|
|
7
|
|
|
965
|
|
|
Production
|
|
(391
|
)
|
|
(1,648
|
)
|
|
Revisions of quantity estimates
|
|
271
|
|
|
(1,702
|
)
|
|
|
|
|
|
|
|
|
|
Proved reserve quantities, December 31, 2007
|
|
10,744
|
|
|
29,810
|
|
|
Purchase of minerals-in-place
|
|
672
|
|
|
9,726
|
|
|
Sales of minerals-in-place
|
|
(988
|
)
|
|
(4,946
|
)
|
|
Extensions and discoveries
|
|
501
|
|
|
1,155
|
|
|
Production
|
|
(743
|
)
|
|
(2,962
|
)
|
|
Revisions of quantity estimates
|
|
(1,393
|
)
|
|
2,013
|
|
|
|
|
|
|
|
|
|
|
Proved reserve quantities, December 31, 2008
|
|
8,793
|
|
|
34,796
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserve quantities:
|
|
|
|
|
|
|
|
December 31, 2006
|
|
1,591
|
|
|
3,197
|
|
|
December 31, 2007
|
|
8,921
|
|
|
26,427
|
|
|
December 31, 2008
|
|
7,522
|
|
|
25,025
|
|
3. Discounted Future Net Cash Flows
In accordance with SFAS No. 69, estimates of standardized measure of discounted future cash flows were determined by applying period-end prices (adjusted for location and quality
differentials) to the estimated future production of year-end proved reserves. Future cash inflows were reduced by the estimated future production and development costs based on period-end costs to determine pre-tax cash inflows in the associated
proved oil and gas properties. Estimated future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion, depletion carryforwards, net operating loss carryforwards, and
investment tax credit carryforwards. Future net cash inflows were discounted using a 10% annual discount rate to arrive at the standardized measure.
The standardized measure of discounted future net cash flow amounts contained in the following tabulation does not purport to represent the fair market value of oil and gas properties. No value has been given to
unproved properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. Future realization of oil and gas prices over the
remaining reserve lives may vary significantly from current prices. In addition, the method of valuation utilized, based on year-end prices and costs and the use of a 10% discount rate is not necessarily appropriate for determining fair value.
F-27
Presented below is the standardized measure of discounted future net cash flows as of December 31,
2008, 2007 and 2006.
Standardized Measure of Estimated Future Net Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
(in thousands)
|
|
Future cash inflows
|
|
$
|
547,966
|
|
$
|
1,171,932
|
|
$
|
125,999
|
|
Future production costs
|
|
|
228,369
|
|
|
418,750
|
|
|
56,009
|
|
Future development costs
|
|
|
35,020
|
|
|
49,036
|
|
|
5,748
|
|
Future income taxes
|
|
|
56,860
|
|
|
191,598
|
|
|
137
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
227,717
|
|
|
512,548
|
|
|
64,105
|
|
10% annual discount for estimated timing of cash flows
|
|
|
107,098
|
|
|
233,902
|
|
|
23,787
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
120,619
|
|
$
|
278,646
|
|
$
|
40,318
|
|
|
|
|
|
|
|
|
|
|
|
The principal sources of changes in the standardized measure of discounted future net cash flows
for 2008, 2007 and 2006 are as follows:
Changes in Standardized Measure
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
(in thousands, except product prices)
|
|
|
Standardized measure, beginning of period
|
|
$
|
278,646
|
|
|
$
|
40,318
|
|
|
$
|
49,020
|
|
|
Changes in prices, net of production cost
|
|
|
(206,127
|
)
|
|
|
26,229
|
|
|
|
(9,079
|
)
|
|
Extensions, discoveries and enhanced production
|
|
|
6,571
|
|
|
|
3,183
|
|
|
|
—
|
|
|
Revision of quantity estimates
|
|
|
(4,221
|
)
|
|
|
815
|
|
|
|
200
|
|
|
Development costs incurred, previously estimated
|
|
|
876
|
|
|
|
1,366
|
|
|
|
76
|
|
|
Change in estimated future development costs
|
|
|
9,676
|
|
|
|
105
|
|
|
|
(1,387
|
)
|
|
Purchases of minerals-in-place
|
|
|
17,401
|
|
|
|
325,882
|
|
|
|
9,833
|
|
|
Sales of minerals-in-place
|
|
|
(39,923
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Sale of oil and gas produced, net of production costs
|
|
|
(61,283
|
)
|
|
|
(20,462
|
)
|
|
|
(10,083
|
)
|
|
Accretion of discount
|
|
|
43,861
|
|
|
|
4,171
|
|
|
|
4,827
|
|
|
Change in estimated future income taxes
|
|
|
73,348
|
|
|
|
(103,258
|
)
|
|
|
(87
|
)
|
|
Changes in timing of estimated cash flows and other
|
|
|
1,794
|
|
|
|
297
|
|
|
|
(3,002
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
120,619
|
|
|
$
|
278,646
|
|
|
$
|
40,318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current prices at year-end, used in standardized measure:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per barrel)
|
|
$
|
41.47
|
|
|
$
|
89.88
|
|
|
$
|
59.06
|
|
|
Gas (per Mcf)
|
|
$
|
5.29
|
|
|
$
|
6.87
|
|
|
$
|
4.96
|
|
Equity in Partnership Reserves
1. Costs incurred related to oil and gas activities
The following two unaudited tables set forth the Company’s share of costs incurred in the affiliated partnerships during the years ended December 31, 2008 and 2007. During 2006, the Company did not hold an
interest in either one of the affiliated partnerships that it accounted for using the equity method at December 31, 2008.
F-28
Costs incurred in acquisition, development and exploration:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(in thousands)
|
|
Acquisition cost
|
|
$
|
949
|
|
$
|
1,553
|
|
Development cost
|
|
$
|
633
|
|
$
|
434
|
|
Exploration cost
|
|
$
|
—
|
|
$
|
—
|
Capitalized cost of oil and gas properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(in thousands)
|
|
|
Proved properties
|
|
$
|
3,543
|
|
|
$
|
1,973
|
|
|
Unproved properties
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,543
|
|
|
|
1,973
|
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(662
|
)
|
|
|
(274
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized cost
|
|
$
|
2,881
|
|
|
$
|
1,699
|
|
|
|
|
|
|
|
|
|
|
|
2. Estimated Quantities of Proved Oil and Gas Reserves and Discounted Future Net Cash Flows
The reserve information presented above does not include the Company’s share of reserves held by two limited partnerships which
are accounted for under the equity method of accounting. The following table presents the Company’s estimated share of the oil and gas reserves held by the limited partnerships as of December 31, 2008.
|
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
Gas (Mcf)
|
|
|
|
(in thousands)
|
|
Oil and gas volumes:
|
|
|
|
|
|
|
Proved developed
|
|
58
|
|
|
12,227
|
|
Proved undeveloped
|
|
61
|
|
|
4,510
|
|
|
|
|
|
|
|
|
Total
|
|
119
|
|
|
16,737
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
|
|
$
|
17,871
|
|
|
|
|
|
|
|
F-29
Signatures
Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the Registrant caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
|
|
|
|
|
GEORESOURCES, INC. (the “Registrant”)
|
|
|
|
|
|
Dated: March 25, 2009
|
|
|
|
/s/ Frank A. Lodzinski
|
|
|
|
|
|
Frank A. Lodzinski, Chief Executive Officer
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
(Power of
Attorney)
Each person whose signature below constitutes and appoints FRANK A. LODZINSKI and HOWARD E. EHLER his true and
lawful attorneys-in-fact and agents, each acting along, with full power of stead, in any and all capacities, to sign any or all amendments to this annual report on Form 10-K for the year ended December 31, 2008, and to file the same, with all
exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, 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 each acting alone, or his substitute or substitutes, may lawfully do or cause to be done by virtue thereof.
|
|
|
|
|
|
|
|
|
|
|
Signatures
|
|
Title
|
|
Date
|
|
|
|
|
|
|
|
|
/s/ Frank A. Lodzinski
|
|
President, Chief Executive Officer
|
|
March 25, 2009
|
|
|
|
Frank A. Lodzinski
|
|
(principal executive officer) and Director
|
|
|
|
|
|
|
|
|
|
|
/s/ Howard E. Ehler
|
|
Principal Financial Officer and
|
|
March 25, 2009
|
|
|
|
Howard E. Ehler
|
|
Principal Accounting Officer
|
|
|
|
|
|
|
|
|
|
|
/s/ Collis P. Chandler, III
|
|
Director
|
|
March 25, 2009
|
|
|
|
Collis P. Chandler, III
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Christopher W. Hunt
|
|
Director
|
|
March 25, 2009
|
|
|
|
Christopher W. Hunt
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Jay F. Joliat
|
|
Director
|
|
March 25, 2009
|
|
|
|
Jay F. Joliat
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Scott R. Stevens
|
|
Director
|
|
March 25, 2009
|
|
|
|
Scott R. Stevens
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Nicholas L. Voller
|
|
Director
|
|
March 25, 2009
|
|
|
|
Nicholas L. Voller
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Michael A. Vlasic
|
|
Director
|
|
March 25, 2009
|
|
|
|
Michael A. Vlasic
|
|
|
|
|
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