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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

DELAWARE	84-1482290
(State or other jurisdiction of	(IRS Employer
incorporation or organization)	Identification No.)
410 17th Street — Suite 1850
Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

 

 

 

 

TETON ENERGY CORPORATION AND SUBSIDARIES

Notes to Consolidated Financial Statements

(Unaudited) 

 

Performance -Vesting Restricted Common Stock
		Outstanding at the beginning of the year			Granted during the period			Earned, vested and issued during the period			Forfeited or cancelled during the period			Outstanding at the end of the period
2007 Grant Year			—			540,000			—			—			540,000
Total			—			540,000			—			—			540,000

 

 

Weighted Average Grant Date Fair Market Values per Share Unit
		Outstanding at the beginning of the year			Granted during the period			Earned, vested and issued during the period			Forfeited or cancelled during the period			Outstanding at the end of the period
2007 Grant Year		$	—		$	5.15		$	—		$	—		$	5.15
Total		$	—		$	5.15		$	—		$	—		$	5.15

Stock Options

A summary of stock option activity for the nine months ended September 30, 2007 is set forth below:

		Number Outstanding			Weighted Average Exercise Price			Weighted Average Remaining Contractual Term			Aggregate Intrinsic Value
												(in thousands)
Outstanding at December 31, 2006			2,088,545		$	3.56
Granted			—			—
Exercised			(565,478	)		3.57
Forfeited/expired			—			—
Outstanding at September 30, 2007			1,523,067		$	3.52			5.61		$	2,512
Exercisable at September 30, 2007			1,516,267		$	3.54			5.64		$	2,498

Note 8 — 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 any required land reclamation in accordance with applicable state and federal laws. Teton determines asset retirement obligations by calculating the present value of estimated cash flows related to future retirement obligations.

The following table provides a reconciliation of the Company’s asset retirement obligations for the three and nine months ended September 30, 2007 and September 30, 2006.

		Three Months Ended September 30,						Nine Months Ended September 30,
		2007			2006			2007			2006
		(in thousands)
Beginning asset retirement obligation		$	239		$	24		$	78		$	4
Additional liabilities incurred			91			16			143			36
Revisions in estimated cash flows			(97	)		—			(8	)		—
Accretion expense			14			—			34			—
Ending asset retirement obligation		$	247		$	40		$	247		$	40

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Note 9 — Subsequent Events

On October 1, 2007 the Company closed on an asset exchange agreement with Delta Petroleum Company. See Note 3 for additional information.

 

Note 10 — Commitments and Contingencies

On February 1, 2007, the Company executed an employment agreement with Dominic J. Bazile II to become the Company’s Executive Vice President and Chief Operating Officer. The employment agreement provides for an initial salary for Mr. Bazile of $225,000 per year. Under the terms of the employment agreement, Mr. Bazile is entitled to 12 months severance pay in the event of a change of position or change in control of the Company or if his employment is terminated without cause. The employment agreement contains an evergreen provision, which automatically extends the term of Mr. Bazile’s employ for a two-year period if the agreement is not terminated by notice to either party during 60 days prior to the end of the initial stated term, which is two years. In addition, Mr. Bazile’s contract employment agreement has an indemnification agreement.

 

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS

With the exception of historical matters, the matters discussed herein are forward-looking statements that involve risks and uncertainties. Forward- looking statements include, but are not limited to, statements concerning the expectation or belief regarding future events, and may include words or phrases such as “will likely result, “are expected to,” “will continue,” ” is anticipated,” “estimate,” “projected,” “intends to” or similar expressions, which are intended to identify “forward looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Our actual results could differ materially from the results discussed in such forward-looking statements. There is absolutely no assurance that we will achieve the results expressed or implied in forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures, our ability to successfully implement our strategy to acquire additional oil and gas properties and our ability to successfully manage and operate our newly acquired oil and gas properties or any properties subsequently acquired by us as well as those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2006, under the subsections “Forward-Looking Statements” and “ITEM 1A. RISK FACTORS,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Management’s Discussion and Analysis

Overview

Teton Energy Corporation (the “Company,” “Teton,” “we,” or “us”) was formed in November 1996 and is incorporated in the state of Delaware. We are an independent energy company engaged primarily in the development, production, and marketing of natural gas and oil in North America. Our strategy is to increase shareholder value by profitably growing reserves and production, primarily through acquiring under-valued properties with reasonable risk-reward potential and by participating in or actively conducting drilling operations in order to exploit our properties. We seek high-quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. Our current operations are located in the Rocky Mountain region of the United States.

Accomplishments and Highlights, Three Months Ended September 30, 2007

Financial and operational highlights for the three months ended September 30, 2007 include the following:

·

Our net loss increased from $797,000 ($0.06 per share) for the three-month period ended September 30, 2006, to $952,000 ($0.06 per share) for the same period in 2007. The increase in net loss of $155,000 is due to decreased oil and gas sales resulting from lower natural gas prices realized, increased interest expense, as well as increased depletion and general and administrative expenses, offset by non-cash gains on derivative instruments.

·

Our oil and gas sales volumes increased from 301,000 mcf equivalent of natural gas (“mcf equivalent”) during the third quarter of 2006 to 407,000 mcf equivalent for the same period in 2007. Average sales price, after deducting marketing, gathering, transportation and fuel costs, decreased from $4.89 per mcf equivalent during the third quarter of 2006 to $2.73 per mcf equivalent for the same period in 2007. As a result, oil and gas sales decreased by $355,000 during the third quarter of 2007 as compared to the third quarter of 2006.

·

We participated in the drilling of 50 gross development wells in the current quarter and connected 25 gross wells to production.

·

On July 25, 2007, we closed on a registered direct offering of 964,060 shares of our common stock and warrants to purchase 337,421 shares of common stock, for gross proceeds of $4.9 million and net proceeds of $4.5 million.

·

For the three months ended September 30, 2007, we incurred capital expenditures of approximately $13.4 million.

Results of Operations for the Three Months Ended September 30, 2007

We had a net loss for the three months ended September 30, 2007, of $952,000, an increase in net loss of $155,000 over the same period in 2006. The increase in net loss was due to decreased oil and gas sales resulting from lower natural gas prices realized, increased interest expense, as well as increased depletion and general and administrative expenses, offset by non-cash gains on derivative instruments, which are further described below.

Our oil and gas sales for the quarter ended September 30, 2007 of $1.1 million represented a decrease of $355,000, or 24% as compared to the same period in 2006. This decrease is primarily due to the 35% increase in production volumes offset by a 44% decrease in the average realized natural gas prices per mcf equivalent. During the three months ended September 30, 2007, oil and gas sales net to our interest totaled 407,000 mcf equivalent, at an average price of $2.73 per mcf equivalent after deducting $202,000 ($0.50 per mcf equivalent) for gathering, fuel, transportation and marketing expenses. During the three months ended September 30, 2006, our oil and gas sales totaled 301,000 mcf equivalent, resulting in $1.5 million in oil and gas sales, at an average price of $4.89 per mcf equivalent after deducting $159,000 ($0.53 per mcf equivalent) for gathering, fuel, transportation and marketing expenses. The higher oil and gas sales volumes are primarily the result of an increased number of wells on production (there were 90 gross wells on production at September 30, 2007 compared to 20 gross wells on production at September 30, 2006).

 

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Lease operating expenses and production taxes ($196,000 and $101,000, respectively) for the three months ended September 30, 2007, totaled $297,000, or 27% of oil and gas sales, equating to $0.73 per mcf equivalent. Lease operating expenses and production taxes ($226,000 and $100,000, respectively) for the three months ended September 30, 2006 totaled $326,000, or 22% of oil and gas sales and equating to $1.08 per mcf equivalent. The decrease in lease operating expenses and production taxes in 2007 of $29,000, or 9%, is primarily due to cost reductions resulting from Piceance Basin roads and pipelines being placed into service, offset by an increase in costs due to the increase in the number of producing wells in 2007 as compared to 2006.

General and administrative expense increased by $432,000 during the quarter ended September 30, 2007 as compared to the same period in 2006. Factors accounting for the increase include an increase in professional fees of $499,000, which is comprised of increased legal fees of $291,000, increased investment banking fees of $98,000 and increased fees of $110,000 associated with accounting services and temporary staff. The increase in professional fees resulted from work relating to financing including regulatory compliance.

 

Offsetting these increases was a $101,000 decrease in share-based compensation expense resulting from third quarter forfeitures of $284,000, offset by an increase of $183,000 in estimated performance payouts under the Company’s 2005 Long Term Incentive Plan (the “LTIP”). Estimated performance payouts increased mainly due to the increased number of participants and scheduled increases in vesting rates under the LTIP.

 

Depreciation, depletion and amortization expense increased by $836,000 to $1,479,000 for the three months ended September 30, 2007, as compared to $643,000 incurred during the same period in 2006, principally due to the higher gas sales volumes and increases in unit-of-production depletion rates in 2007 as compared to 2006.

Exploration expense increased by $84,000 to $123,000 for the three months ended September 30, 2007, as compared to $39,000 incurred during the same period in 2006. The increase is a result of higher expenses incurred for seismic projects and delay rentals on our DJ Basin properties.

Other income (expense) increased $1.5 million in the third quarter of 2007 primarily as a result of $1.9 million of gains on derivative contract liabilities and $528,000 of realized gains applicable to settling natural gas derivative contracts during the quarter. These third quarter gains were offset by a $1.0 million increase in interest expense during the quarter associated with higher levels of debt in 2007. The increase in interest expense includes non-cash charges associated with: the amortization of debt discount of $352,000, amortization of debt issuance costs of $95,000 and the write-off of unamortized debt issuance costs of $209,000 associated with changing our revolving credit facility from BNP Paribas to JPMorgan Chase.

Our $1.9 million gain on derivative contract liabilities was mainly due to the decrease in the market price of our Common Stock from $5.20 on June 29, 2007 to $4.75 on September 28, 2007. The gain attributable to this change in share price was $1.3 million. Other factors contributing to our third quarter gain on derivative contract liabilities were: a gain of $264,000 associated with a 2.5% decrease in the estimated volatility of our share prices, a gain of $236,000 associated with the three month shorter term of the freestanding warrants associated with the liability and a gain of $131,000 associated with a 69 basis point decrease in the estimated risk-free rate used to value these derivatives.

Results of Operations for the Nine Months Ended September 30, 2007

We had a net loss for the nine months ended September 30, 2007, of $10.0 million, which represents an increase of $6.4 million over the same period in 2006. The increase was mainly due to significant non-cash losses on derivative instruments and increased interest expense, and increased general and administrative and depletion expense, which are further described below.

Our oil and gas sales for the nine months ended September 30, 2007 of $3.0 million represented an increase of $606,000, or 25%, as compared to the same period in 2006. During the nine months ended September 30, 2007, oil and gas sales net to our interest totaled 876,000 mcf equivalent, at an average price of $3.44 per mcf equivalent after deducting $489,000 ($0.56 per mcf equivalent) for gathering, fuel, transportation and marketing expenses. During the nine months ended September 30, 2006, our oil and gas sales totaled 477,000 mcf equivalent, resulting in $2.4 million in oil and gas sales, at an average price of $5.05 per mcf equivalent, after deducting $303,000 ($0.64 per mcf equivalent) for gathering, fuel, transportation and marketing expenses. The higher oil and gas sales volumes are primarily the result of an increased number of wells on production (90 gross wells on production at September 30, 2007 compared to 20 gross wells on production at September 30, 2006).

 

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Lease operating expenses and production taxes ($303,000 and $254,000, respectively) for the nine months ended September 30, 2007, totaled $557,000, or 18% of oil and gas sales, equating to $0.64 per mcf equivalent. Lease operating expenses and production taxes ($322,000 and $172,000, respectively) for the nine months ended September 30, 2006 totaled $494,000, or 21% of oil and gas sales equating to $1.04 per mcf equivalent. The increase in lease operating expenses and production taxes in the nine months ended September 30, 2007 of $63,000, or 13%, is primarily due to the increase in the number of producing wells in 2007 as compared to 2006 offset by lower lease operating expense on a per-well basis.

General and administrative expense increased by $1.4 million during the nine months ended September 30, 2007 as compared to the same period in 2006. Factors accounting for the increase include:

 

·

An increase in professional fees of $991,000 was comprised of increased legal fees of $288,000, increased investment banking fees of $256,000 and increased fees of $447,000 associated with accounting services and temporary staff. The increase in fees for accounting services and temporary staff were due, in part, to a one-time credit to accounting fees of $158,000 during the first quarter of 2006 relating to the return of 50,000 shares of our Common Stock from our former Chief Financial Officer. Other increases in professional fees resulted primarily from our growth in operations.

 

·

In addition, non-cash share-based compensation expense associated with our LTIP increased by $495,000 due to a $779,000 increase in the estimated performance payouts offset by a $284,000 decrease in share-based compensation expense associated with forfeitures. Estimated performance payouts increased mainly due to the increased number of participants and scheduled increases in vesting rates under the LTIP.

 

Depreciation, depletion and amortization expense increased by $1.5 million to $2.6 million for the nine months ended September 30, 2007, as compared to $1.1 million incurred during the same period in 2006, principally due to higher gas sales volumes and increased unit-of-production depletion rates.

Exploration expense increased by $483,000 to $737,000 for the nine months ended September 30, 2007, as compared to $254,000 incurred during the same period in 2006. The increase is a result of higher expenses incurred for seismic projects on our DJ Basin properties, primarily through the second quarter of 2007 which totaled $347,000, as well as increased exploration activities and delay rentals associated with our growth in operations.

During the nine months ended September 30, 2007, other income (expense) decreased by $3.5 million mainly as a result of $2.7 million of losses on derivative contract liabilities, additional interest expense of $1.3 million associated with the our new debt offset by $782,000 of realized gains applicable to settling natural gas derivative contracts. The increase in interest expense includes non-cash charges associated with: the amortization of debt discount of $515,000, amortization of debt issuance costs of $126,000 and the write-off of unamortized debt issuance costs of $209,000 associated with changing our revolving credit facility from BNP Paribas to JPMorgan Chase.

Anticipated Fourth Quarter Items

In addition to integrating the oil and gas properties acquired from Delta Petroleum Company (“Delta”) as described in Note 3 to our consolidated financial statements we may pursue additional acquisitions per our business plan. As a result, we may incur due diligence and legal expenses, which will be capitalized only if we successfully complete an acquisition. If an acquisition is not successful, we will include those costs in our general and administrative expenses in the period in which such expenses are incurred.

Liquidity and Capital Resources

As of September 30, 2007, we had cash and cash equivalents of $3.9 million and a working capital deficit of $10.5 million.

Subsequent to the end of the quarter, on October 1, 2007, we received $36.3 million from the sale of part of our working interest, including initial purchase price adjustments, with respect to the sale of a portion of our Piceance assets to Delta as described in Note 3 to our consolidated financial statements.

On May 16, 2007, we closed on $9.0 million of our 8% senior subordinated convertible notes (the “Convertible Notes”) due May 16, 2008. We received $8.3 million from the issuance of these Convertible Notes, net of fees and expenses. In addition to the Convertible Notes, we issued a total of 3,960,000 warrants to purchase our Common Stock at $5.00 per share, including 360,000 warrants issued to the placement agent in conjunction with the Convertible Notes.

On July 25, 2007 we completed a registered direct offering of our Common Stock to a selected group of institutional investors for an aggregate of 964,060 shares of Common Stock which were purchased at a price of $5.05 per share, for gross proceeds of $4.9 million, before fees and expenses. The offering also included 337,421 warrants to purchase 337,421 shares of Common Stock, including 77,126 warrants to purchase 77,126 shares of common stock issued to the placement agents in conjunction with the transaction, with an exercise price of $6.06 per share with a five-year term. Offering costs including underwriter’s fees, legal, accounting and other related expenses totaled $558,000, which includes the 77,126 placement agent warrants valued at $190,000.

 

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On August 9, 2007, we entered into an amended and restated $50.0 million revolving credit facility (the “Amended Credit Facility”) with JP Morgan Chase Bank, N.A. (“JPMorgan Chase”), as administrative agent, replacing BNP Paribas. The Amended Credit Facility matures on August 9, 2011, and is available to be used for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The Amended Credit Facility provides for as much as $50.0 million in borrowing capacity, depending upon a number of factors, such as the projected value of our proven oil and gas assets. The borrowing base for the Amended Credit Facility at any time will be the loan value assigned to the proved reserves attributable to our direct or indirect oil and gas interests. The Amended Credit Facility had an initial borrowing base on August 9, 2007 of $14.0 million. The borrowing base was decreased to $8.0 million on October 1, 2007, as a result of our disposition of 50% of our Piceance Basin assets. At September 30, 2007, the outstanding borrowings under the Credit Facility were $14.0 million. On November 9, 2007, there was a redetermination of the borrowing base to $10,000,000.

We currently estimate the cost associated with our Piceance development program to be approximately $20.0 million for the year ending December 31, 2007, after taking into account the effect of divesting 50% of our interest in the Piceance properties. The $20.0 million represents the drilling costs of 36 wells during 2007 and related infrastructure. Additionally, we estimate that we will spend approximately $6.8 million in the DJ Basin during 2007 for development drilling, facilities and geological and geophysical programs.

We also may continue to receive proceeds from the exercise of outstanding warrants and/or options as we did during the nine months ended September 30, 2007. During the nine months ended September 30, 2007, we received $2.0 million from options that were exercised during the period. As of September 30, 2007, warrants to purchase 5,242,366 shares of Common Stock were outstanding. These warrants have a weighted average exercise price of $4.78 per share and expire between April 2008 and December 2012. As of September 30, 2007, options to purchase 1,523,067 shares of Common Stock were outstanding. These options have a weighted average exercise price of $3.52 per share and expire between January 2008 and May 2015.

We expect that our current cash balances, including the proceeds received in October 2007 from the sale of part of our Piceance Basin assets, will provide us with adequate financial resources to meet our capital needs for the foreseeable future.

Sources and Uses of Funds

Historically, our primary source of liquidity has been cash provided by securities offerings. These offerings are likely to continue to play an important role in financing our business. Cash raised from third parties or generated through operations will be used for additional acquisitions or in connection with drilling programs associated with our current properties.

Cash Flows and Capital Expenditures

Operating activities

During the nine months ended September 30, 2007, we used $1.9 million of cash in operating activities, associated with our net loss of $10.0 million for the period which included the following non-cash items: losses on derivative contract liabilities of $2.7 million, non-cash accrued stock-based compensation of $2.0 million, non-cash depreciation and depletion charges of $2.6 million, non-cash amortization of debt discount of $515,000 and non-cash amortization of debt issuance costs of $335,000. All other non-cash items and changes in assets and liabilities applicable to operating activities netted to a $30,000 use of cash during the period.

During the nine months ended September 30, 2006, we used $4.3 million of cash in operating activities, associated with our net loss of $3.6 million which included the following non-cash items: accrued stock-based compensation of $1.4 million and non-cash depreciation and depletion charges of $1.1 million. During the 2006 period, we used $1.9 million of cash for advances to operators, $911,000 for increases in accounts receivable and $255,000 of cash in respect to discontinued operations. All other non-cash items and changes in assets and liabilities applicable to operating activities netted to a $48,000 use of cash during the period.

Investing activities

We incurred capital costs, including acquisitions, of $28.3 million and $12.6 million for the nine months ended September 30, 2007 and 2006, respectively. During the nine months ended September 30, 2007, we incurred capital costs with respect to our drilling activities of $22.7 million, costs with respect to facilities of $4.3 million, costs with respect to undeveloped leaseholds of $1.0 million, and costs with respect to land of $304,000. During the 2006 period, we incurred capital costs with respect to drilling and completion activities of $9.0 million and $3.6 million with respect to acquisition of undeveloped leaseholds and other miscellaneous capital expenditures. Our development costs increased for the nine months ended September 30, 2007 as compared to the same period in 2006, due to increased drilling and completion activities with respect to our Piceance and DJ Basins’ drilling and development programs.

 

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During the nine months ended September 30, 2006, we received cash of $2.7 million in connection with our Acreage Earning Agreement with Noble with respect to our DJ Basin acreage.

Financing activities

During nine months ended September 30, 2007, holders of 565,478 options exercised their options and purchased an equivalent number of shares of our Common Stock for net proceeds to us of $2.0 million. During the nine months ended September 30, 2006, holders of 760,957 warrants exercised those warrants and purchased shares of Common Stock for net proceeds of $3.5 million and holders of 359,150 stock options exercised their options and purchased an equivalent number of shares our Common Stock for net proceeds to us of $1.3 million.

During the nine months ended September 30, 2007, we raised $8.3 million net of $710,000 in expenses from issuing $9.0 million in Convertible Notes due May 16, 2008. In addition to the Convertible Notes, we issued a total of 3,960,000 warrants to purchase our Common Stock at $5.00 per share, including 360,000 warrants issued to the placement agent as a portion of its fee for placing such Convertible Notes.

During the nine months ended September 30, 2007, we raised $4.5 million net of expenses from a registered direct offering of 964,060 shares of our Common Stock and warrants to purchase 337,421 shares of Common Stock. During the nine months ended September 30, 2006, we raised $10.8 million from a public offering of 2,300,000 shares of our Common Stock.

During the nine months ended September 30, 2007, we drew down $14.0 million on our Credit Facilities and incurred debt issuance costs of $213,000. We incurred $206,000 of debt issuance costs for the same period in 2006.

Commitments

The following outlines our contractual commitments, excluding interest payments, as of September 30, 2007:

		For the Three Months Ended December 31, 2007 and the Years Ended December 31, 2008, 2009, 2010, 2011 and Thereafter
		Remainder of  2007			2008			2009			2010			2011			Thereafter			Total
		(in thousands)
Convertible Notes		$	—		$	9,000		$	—		$	—		$	—		$	—		$	9,000
Credit Facility(a)			—			—			—			—			14,000			—			14,000
Operating lease for office space			31			129			44			—			—			—			204
Total		$	31		$	9,129		$	44		$	—		$	14,000		$	—		$	23,204

 

(a)

Subsequent to September 30, 2007, on October 3, 2007, JPMorgan Chase Bank, N.A., reduced our borrowing base and conforming borrowing base on the Credit Facility to $8.0 million, following our sale of part of our Piceance Basin properties which closed on October 1, 2007. On October 4, 2007, we repaid $6.0 million to JPMorgan Chase, reducing our outstanding balance to $8.0 million. This balance remains outstanding as of November 9, 2007.

 

Critical Accounting Policies and Estimates

The following critical accounting policies should be read in conjunction with our critical accounting policies that we included in our Form 10-K for the year ended December 31, 2006, that we filed with the SEC on March 19, 2007.

Derivative Financial Instruments

We use derivative financial instruments to hedge exposures to oil and gas production cash-flow risks. All derivatives are recognized on the balance sheet and measured at fair value. We review estimated fair values of the derivative contracts as reported by the counterparties to the contract, and we also independently assesses the fair value of derivative contracts and record the changes in the fair value at each reporting period. For derivative contracts that do not qualify as cash flow hedges, changes in the derivative contracts’ fair value are recorded as unrealized gains and losses on derivative contracts in the consolidated statements of operations. We do not have any derivative contracts that qualify as cash flow hedges. We recognize realized gains and losses under other income and expense in our consolidated statements of operations.

We also use various types of financing arrangements to fund our business capital requirements, including convertible debt and other financial instruments indexed to the market price of our Common Stock. These contracts require careful evaluation to determine whether derivative features embedded in host contracts require bifurcation and fair value measurement or, in the case of freestanding derivatives (principally warrants) whether certain conditions for equity classification have been achieved. In instances where derivative financial instruments require liability classification, we are required to initially and subsequently measure such instruments at fair value. Accordingly, we adjust the fair value of these derivative components at each reporting period through a charge to earnings until such time as the instruments are permitted classification in stockholders’ equity.

 

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We estimate fair values of derivative financial instruments using various valuation techniques (and combinations thereof) that are considered to be consistent with the objective of measuring fair values. In selecting the appropriate valuation technique, management considers, among other factors, the nature of the instrument, the market risks that it embodies and the expected means of settlement. For less complex derivative financial instruments, such as free-standing warrants, we use the Black-Scholes-Merton option valuation technique because it embodies all of the requisite assumptions (including trading volatility, estimated terms and risk-free rates) necessary to estimate the fair value of these instruments. For complex derivative financial instruments, such as embedded conversion options, we use a flexible Monte Carlo valuation technique because it embodies all of the requisite assumptions (including credit risk, interest-rate risk and exercise/conversion behaviors) that are necessary to estimate the fair value of these more complex instruments. For forward contracts that require net-cash settlement as the principal means of settlement, we project and discount future cash flows applying probability-weighting to multiple possible outcomes. Estimating fair values of derivative financial instruments requires the use of estimates that change over the term of the instrument. In addition, option-based valuation techniques are highly volatile and sensitive to changes in the market price of our Common Stock, which has a high historical volatility. Since derivative financial instruments are initially and subsequently carried at fair values, our income (loss) will reflect the volatility in these estimate and assumption changes.

Interest Expense

Our interest expense over the term of the Convertible Notes will increase substantially due to the significant original issue discount resulting from the application of Statement of Financial Accounting Standard (“SFAS”) No. 133 “Accounting for derivative financial instruments and Hedging Activities” significant debt issuance costs and the effect of applying the effective interest method. Interest expense applicable to the Convertible Notes through the maturity date of May 16, 2008 is estimated as follows:

 

Estimated Future Interest Expense - Convertible Notes
		Original Issue Discount Amortization			Debt Issuance Cost Amortization			Contractual Interest Expense			Total
											(in thousands)
Fourth quarter 2007		$	1,115		$	215		$	180		$	1,510
First quarter 2008			3,525			678			180			4,383
Second quarter 2008			3,845			740			90			4,675
Estimated total future interest expense		$	8,485		$	1,633		$	450		$	10,568

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices, market price of our Common Stock and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses depending on market dynamics. This forward-looking information provides indicators of how we view and manage (or anticipate managing) our ongoing market risk exposures.

Commodity Price Risk

The price we receive for our oil and natural gas production has a direct influence on our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to fluctuations in response to a variety of factors. The markets for oil and natural gas have experienced periods of high volatility and these markets are likely to experience similar periods of volatility in the future. The prices we receive for our production depend on numerous factors beyond our control. Based on our 2006 production, our income before income taxes for 2006 would have moved up or down approximately $74,000 for every $0.10 change in natural gas prices.

We have entered into natural gas derivative contracts to manage our exposure to natural gas price volatility. Our derivative contracts include costless collars and fixed price SWAPS.

In October 2006 and June 2007, we entered into certain ISDA agreements with BNP Paribas to allow us to hedge our commodity pricing risk relative to our future oil and gas production. These contracts were assigned to JPMorgan on August 9, 2007. In addition, we have a company hedging policy in place, if necessary, to protect a portion of our production against future pricing fluctuations.

 

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Our outstanding hedges as of September 30, 2007 are summarized below:

Commodity		Period			Monthly Volume (MMBtu)			CIG Floor/Ceiling or Fixed Price per MMBtu
Costless Collars Contracts:
Natural Gas			10/2007			30,000		$	6.00/$7.25
Natural Gas			11/2007			30,000		$	6.00/$7.25
Natural Gas			12/2007			30,000		$	6.00/$7.25
Fixed Forward Contract:
Natural Gas			10/2007			30,000		$	5.78
Natural Gas			11/2007			30,000		$	5.78
Natural Gas			12/2007			30,000		$	5.78
Natural Gas			01/2008			30,000		$	5.78
Natural Gas			02/2008			30,000		$	5.78
Natural Gas			03/2008			30,000		$	5.78
Natural Gas			04/2008			30,000		$	5.78
Natural Gas			05/2008			30,000		$	5.78
Natural Gas			06/2007			30,000		$	5.78
Natural Gas			07/2008			30,000		$	5.78
Natural Gas			08/2008			30,000		$	5.78
Natural Gas			09/2008			30,000		$	5.78
Natural Gas			10/2008			30,000		$	5.78

The costless collar hedge prices shown above have the effect of providing a protective floor while allowing us to share in some upward pricing movements. The fixed SWAP hedge prices have the effect of providing a protective floor with no upward pricing benefit. Consequently, while these hedges are designed to decrease our exposure to price decreases, they also have the effect of limiting the benefit of price increases beyond the ceiling or fixed price. For the 2007 and 2008 natural gas contracts listed above, a hypothetical $0.10 change in the Colorado Interstate gas (“CIG’) price below the floor price applied to the notional amounts would cause a gain on hedging activities of $48,000 and a hypothetical $0.10 change in the CIG price above the ceiling price would cause a loss on hedging activities of $9,000. We expect to continue to enter into derivative contracts in order to minimize exposure to commodity price decreases.

On October 18, 2007, we entered into a fixed forward contract with respect to the sale of future period production of crude oil. The contract covers the period November 1, 2007 to December 31, 2008, and covers a total of 25,620 barrels, or 60 bopd. The fixed price per barrel is $80.70 before transportation deductions.

Market Price of Common Stock Risk

Our gain or loss on derivative liabilities is subject to wide fluctuations each reporting period. The amount of gain or loss is largely dependent upon assumptions underlying valuation techniques we apply. In addition, our derivative liability balances are also highly susceptible to changes in the market price of our Common Stock. At September 30, 2007 a one dollar increase in the market price of our Common Stock would result in an approximate $2.9 million increase in loss on derivative liabilities.

Interest Rate Risk

At September 30, 2007, we had $14.0 million outstanding on our Credit Facility. Under the Credit Facility, each loan bears interest at a Eurodollar rate or a base rate, as requested by us, plus an additional margin based on the amount of our total outstanding borrowings relative to the total borrowing base. The Eurodollar rate is based on the London Interbank Offered Rate (“LIBOR”). The base rate is the higher of the Prime Rate or the Federal Funds Rate plus one-half of one percent. Assuming that we were to draw down on the entire $14.0 million available to us under our Credit Facility as of September 30, 2007, a one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate would result in additional interest expense to us of approximately $35,000 per quarter.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as amended (the “Exchange Act”) as of the end of the period covered by this Quarterly Report on Form 10-Q. In designing and evaluating the disclosure controls and procedures, management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of such period, our disclosure controls and procedures are effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended September 30, 2007, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

There have been no material changes from risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006, other than as described below:

If we are unable to obtain additional funding our business operations will be negatively impacted.

We recently received an aggregate of approximately $12.7 million, after expenses and fees, from the sales of certain Convertible Notes, and shares of Common Stock and warrants, which we intend to use for our 2007 capital expenditure program. In addition to raising funds through the issuance of Convertible Notes, Warrants and shares of our Common Stock, we are pursuing property sales in order to fund our capital program. We will require additional funding to meet increasing capital costs associated with our operations. Based on our operating partners’ current capital expenditure plans, we will be unable to fund our planned capital program if we are unable to secure additional funding. In addition, although our amended and restated Credit Facility provides availability of up to $50.0 million, our current borrowing base is only $14.0 million as of September 30, 2007, and there can be no assurance that our borrowing base will be increased or that additional advances will be made under such Credit Facility. We do not know if additional financing will be available when needed, or if it is available, if it will be available on acceptable terms. The lack of available future funding may prevent us from implementing our business strategy.

We may incur non-cash charges to our operations as a result of current and future financing transactions.

Under current accounting rules and requirements, we have incurred $2.7 million of non-cash charges for the nine months ended September 30, 2007, and may incur additional non-cash charges to future operations beyond the stated contractual interest payments required under our current and potential future financing arrangements. While such charges are generally non-cash, they impact our results of operations and earnings per share and have been and are expected to be material.

We have limited operating control over our properties.

A significant portion of our business activities are conducted through joint operating agreements under which we own partial non-operated interests in oil and natural gas properties. Consequently, we do not have control over normal operating procedures, expenditures, or future development of those underlying properties. Therefore, our operating results for that portion of our business activities are beyond our control. The failure of an operator of our wells to perform operations adequately, or an operator’s breach of the applicable agreements, could reduce our production and revenues. In addition, the success and timing of drilling and development activities on properties operated by others, in which we participate, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells, and use of technology. Since we do not have a majority interest in any of our current properties in which we have a non-operated interest, we may not be in a position to remove the operator in the event of poor performance. Further, significant cost overruns of an operation in any one of our current projects may require us to increase our capital expenditure budget and could result in some wells becoming uneconomic.

Our failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business.

We will be subject to Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”) beginning with our annual report on Form 10-K for the period ending December 31, 2007. This will require us to include in our annual reports management’s assessments of the effectiveness of our internal control over financial reporting and a report by our independent auditors that provides the independent auditor’s assessment of the effectiveness of our internal control. Accordingly, we are in the process of documenting and testing our internal control procedures in order to satisfy the requirements of Section 404. We have prepared documentation as to our internal control structure, have added staff to the Chief Financial Officer’s department, including an interim Controller and have developed detailed testing plans that will be implemented during the fourth quarter of 2007. However, during the course of our testing, we may identify deficiencies which we may not be able to remediate in time to meet our deadline for compliance with Section 404, and accordingly, we may not be able to conclude on an ongoing basis that we have effective internal control over financial reporting in accordance with Section 404. In addition, testing and maintaining internal control also will involve significant costs and can divert our management’s attention from other matters that are important to our business. Failure to achieve and maintain an effective internal control environment could harm our operating results, cause us to fail to meet our reporting obligations and could require that we restate our financial statements for prior periods, any of which could cause investors to lose confidence in our reported financial information and cause a decline, which could be material, in the trading price of our Common Stock.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS