Oil and Gas Revenues and Production
Oil and gas revenues were $1.94 million for the three months ended September 30, 2012, as compared to $1.81 million for the three months ended September 30, 2011, an increase of $.13 million, or 7.18%. Our production volume on a BOE basis was 33,618 for the three months ended September 30, 2012, as compared to 33,698 for the three months ended September 30, 2011, a nominal decrease that was effected by increased production attributed to five new wells, but offset by normal production declines on more mature properties. Average oil and gas prices during the three months ended September 30, 2012 increased slightly as compared to the prior year.
A comparison of production and average prices for the three months ended September 30, 2012 and 2011, respectively, follows:
| | | Three Months Ended | |
| | | September 30, | |
| | | 2012 | | | 2011 | |
| Product: | | | | | | |
| Oil (Bbls)-volume | | | 21,151 | | | | 20,145 | |
| Oil (Bbls)- average price (1) | | $ | 83.94 | | | $ | 81.94 | |
| | | | | | | | | |
| Natural Gas (Mcf)-volume | | | 29,061 | | | | 31,579 | |
| NGL’s-(BOE) | | | 7,624 | | | | 8,290 | |
| Natural Gas (Mcf)- average price (2) | | $ | 5.81 | | | $ | 5.10 | |
| Barrels of oil equivalent (BOE) | | | 33,618 | | | | 33,698 | |
| Average daily net production (BOE) | | | 365 | | | | 366 | |
| (1) | Does not include the realized price effects of hedges |
| (2) | Includes proceeds from the sale of NGL’s. |
Oil and gas production expenses, depreciation, depletion and amortization
| | Three Months Ended September 30, | | Three Months Ended September 30, | |
| | 2012 | | 2011 | |
| | | (per BOE) | | | (per BOE) | |
| Average price (1) | | $ | 57.83 | | | $ | 53.76 | |
| | | | | | | | | |
| Production costs | | | 11.83 | | | | 10.23 | |
| Production taxes | | | 5.91 | | | | 5.68 | |
| Depletion and amortization | | | 31.80 | | | | 31.25 | |
| | | | | | | | | |
| Total operating costs | | | 49.54 | | | | 47.16 | |
| | | | | | | | | |
| Gross margin | | $ | 8.29 | | | $ | 6.60 | |
| | | | | | | | | |
| Gross margin percentage | | | 14.3 | % | | | 12.2 | % |
| (1) | Does not include the realized price effects of hedges |
Commodity Price Derivative Activities
Changes in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivative instruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted exclusively of swaps. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.
Commodity price derivative net realized gain was $0.04 million during the three months ended September 30, 2012, compared to a realized gain of $0.73 million for the three months ended September 30, 2011, for a decrease in realized gain of $0.69 million, or 95% decrease. We also recorded an unrealized loss on commodity price derivatives of $0.13 million for the three months ended September 30, 2012 compared to no gain or loss during the three months ended September 30, 2011, for a decrease of $0.13 million
Production costs
Production costs were $0.40 million for the three months ended September 30, 2012, as compared to $0.34 million during the three months ended September 30, 2011, a change of $0.06 million, or 18%. Production costs increased due to a larger number of producing wells in the three months ended September 30, 2012 compared to the three months ended September 30, 2011.
Production taxes
Production taxes were $0.20 million for the three months ended September 30, 2012, as compared to $0.19 million during the three months ended September 30, 2011, a change of $0.01 million, or 5%. Production taxes increased due to an increase in oil and gas revenues.
General and administrative expenses
General and administrative expenses were $1.52 million for the three months ended September 30, 2012, as compared to $1.98 million for the three months ended September 30, 2011, a decrease of $0.46 million, or 23%. Our general and administrative expenses for the three months ended September 30, 2012 included approximately $0.54 million in non-cash compensation expense. General and administrative expenses for the three months ended September 30, 2011 included approximately $0.92 million in non-cash compensation expense. Excluding non-cash components, cash general and administrative expenses were $0.94 million for the three months ended September 30, 2012 compared to $1.06 million for the three months ended September 30, 2011. Cash general and administrative expenses during the three months ended September 30, 2012 decreased primarily as a result of a decrease in professional fees and third party fees, but were also affected by general decreases in other general and administrative expense areas.
Depreciation, depletion and amortization
Depreciation, depletion and amortization was $1.07 million for the three months ended September 30, 2012, as compared to $1.05 million during the three months ended September 30, 2011, an increase of $0.02 million, or 2%. Depreciation, depletion, and amortization increased due to additional evaluated properties added during the three months ended September 30, 2012 as compared to the three months ended September 30, 2011.
Interest expense
Interest expense was $2.15 million during the three months ended September 30, 2012, compared to $2.14 million during the three months ended September 30, 2011, an increase of $0.01 million, or 0.4%. During the three months ended September 30, 2012, interest included non-cash charges of $1.29 million, compared to $1.50 million in the comparable period of 2011. Excluding non-cash components, cash interest was $0.86 million for the three months ended September 30, 2012 compared to $0.64 in the comparable period of 2011.
Nine Months Ended September 30, 2012 compared to the Nine Months Ended September 30, 2011.
The Company reported a net loss for the nine months ended September 30, 2012 of approximately $12.78 million compared to a net loss of approximately $11.53 million for the nine months ended September 30, 2011.
| | | Nine months ended September 30, | |
| | | 2012 | | | 2011 | |
| Revenues and other income: | | | | | | |
| Oil sales | | $ | 4,685,713 | | | $ | 5,534,325 | |
| Gas sales | | | 397,298 | | | | 446,386 | |
| Realized gain on commodity hedges | | | 49,729 | | | | | |
| Unrealized gain on commodity price derivatives | | | 445,609 | | | | | |
| Other | | | 132,367 | | | | 110,282 | |
| Total revenues and other income | | | 5,710,711 | | | | 6,716,037 | |
| Expenses: | | | | | | | | |
| Production costs | | | 1,033,635 | | | | 1,114,220 | |
| Production taxes | | | 561,278 | | | | 630,718 | |
| General and administrative | | | 5,099,932 | | | | 8,837,802 | |
| Depreciation, depletion and amortization | | | 2,897,156 | | | | 3,194,301 | |
| Impairment of evaluated properties | | | 3,274,718 | | | | - | |
| Total expenses | | | 12,866,719 | | | | 13,777,041 | |
| | | | | | | | | |
| Loss from continuing operations | | | (7,156,009 | ) | | | (7,061,004 | ) |
| Interest expense | | | (6,320,919 | ) | | | (6,123,496 | ) |
| Other | | | (372 | ) | | | 63,115 | |
| Conversion note derivative gain | | | 700,000 | | | | 1,587,699 | |
| Net loss | | $ | (12,777,299 | ) | | $ | (11,533,686 | ) |
Oil and Gas Revenues and Production
Oil and gas revenues were $5.08 million for the nine months ended September 30, 2012, as compared to $5.98 million for the nine months ended September 30, 2011, a decrease of $0.90 million, or 15%. Our production volume on a BOE basis was 80,005 for the nine months ended September 30, 2012, as compared to 101,251 for the nine months ended September 30, 2011 a decrease of 21,246 BOE, or 21%. This decrease is primarily attributable to normal decline curves related to mature properties, but partially offset by production attributable to wells drilled during the nine months ended September 30, 2012. Production declines were also partially offset by slightly higher average prices for both oil and gas.
Production and average prices for the nine months ended September 30, 2012 are presented in the following table:
| | Nine Months Ended | |
| | | September 30, | |
| | | 2012 | | | 2011 | |
| Product: | | | | |
| Oil (Bbls)-volume | | | 52,658 | | | | 63,114 | |
| Oil (Bbls)-average price (1) | | $ | 88.98 | | | $ | 87.69 | |
| | | | | | | | | |
| Natural gas (Mcf)-volume | | | 63,746 | | | | 88,229 | |
| NGL’s-(BOE) | | | 16,723 | | | | 23,433 | |
| Natural gas (Mcf)-average price (2) | | $ | 6.23 | | | $ | 5.06 | |
| Barrels of oil equivalent (BOE) | | | 80,005 | | | | 101,251 | |
| Average daily net production (BOE) | | | 291 | | | �� | 370 | |
| (1) | Does not include the realized price effects of hedges |
| (2) | Includes proceeds from the sale of NGL’s. |
Oil and gas production expenses, depreciation, depletion and amortization
| | Nine Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2012 | | | 2011 | |
| | | (per BOE) | | | (per BOE) | |
| Average price (1) | | $ | 63.53 | | | $ | 59.07 | |
| | | | | | | | | |
| Production costs | | | 12.92 | | | | 11.00 | |
| Production taxes | | | 7.02 | | | | 6.23 | |
| Depletion and amortization | | | 36.21 | | | | 31.55 | |
| | | | | | | | | |
| Total operating costs | | | 56.15 | | | | 48.78 | |
| | | | | | | | | |
| Gross margin | | $ | 7.38 | | | $ | 10.29 | |
| | | | | | | | | |
| Gross margin percentage | | | 12 | % | | | 17 | % |
| (1) | Does not include the realized price effects of hedges |
Commodity Price Derivative Activities
Changes in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivative instruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted exclusively of swaps. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.
Commodity price derivative net realized gain was $0.05 million during the nine months ended September 30, 2012, as compared to a realized gain of $0.40 million for the nine months ended September 30, 2011, for a decrease in realized gain of $0.35 million, or 88%. We also recorded an unrealized gain on commodity price derivatives of $0.45 million for the nine months ended September 30, 2012 compared to a gain of $0.22 million during the nine months ended September 30, 2011, for an increase of $0.23 million, or 105%.
Production costs
Production costs were $1.03 million during the nine months ended September 30, 2012, as compared to $1.11 million for the nine months ended September 30, 2012, a decrease of $0.08 million, or 7%. Production costs decreased due to lower work over expenses during the nine months ended September 30, 2012.
Production taxes
Production taxes were $0.56 million during the nine months ended September 30, 2012, as compared to $0.63 million during the nine months ended September 30, 2011, a decrease of $0.07 million, or 11%. Production taxes decreased due to the decrease in revenues during the nine months ended September 30, 2012.
General and administrative expenses
General and administrative expenses were $5.10 million for the nine months ended September 30, 2012 compared to $8.84 million for the nine months ended September 30, 2011, a decrease of $3.74 million, or 42%. General and administrative expenses for the nine months ended September 30, 2012 included approximately $1.07 million in non-cash compensation expense and $0.71 million for non-cash payment for consulting fees. General and administrative expenses for the nine months ended September 30, 2011 included approximately $5.50 million in non-cash compensation expense. Excluding non-cash components, cash general and administrative expenses were $3.32 million for the nine months ended September 30, 2012 compared to $3.34 million for the nine months ended September 30, 2011. Cash general and administrative expenses during the nine months ended September 30, 2012 decreased primarily as a result of a decrease in payroll, legal and accounting fees and third party fees related to transactions, as well as being offset by general increases in other general and administrative expense areas.
Depreciation, depletion and amortization
Depreciation, depletion, and amortization were $2.90 million during the nine months ended September 30, 2012, as compared to $3.19 million during the nine months ended September 30, 2011, a decrease of $.29 million, or 9%. Depreciation, depletion, and amortization decreased due lower unit volumes of oil and gas sales and a declining cost center.
Expressed in dollars per BOE, depreciation, depletion, and amortization was $36.21 per BOE during the nine months ended September 30, 2012, as compared to $31.55 during the nine months ended September 30, 2011.
Impairment of evaluated properties
Impairment of evaluated properties was $3.27 million during the nine months ended September 30, 2012, as compared to no impairment during the nine months ended September 30, 2011. Impairment of evaluated properties increased due to capitalized costs exceeding the ceiling value as of the quarter ended March 31, 2012.
Interest Expense
Interest expense was $6.32 million during the nine months ended September 30, 2012, compared to $6.12 million during the nine months ended September 30, 2011, an increase of $0.20 million, or 3%. During the nine months ended September 30, 2012, interest included non-cash charges of $3.8 million, compared to $3.70 million for the nine months ended September 30, 2011. Cash interest accruing on debt in 2012 decreased primarily as a result of lower average term loan balances.
Liquidity and Capital Resources
Cash used in operating activities during the nine months ending ended September 30, 2012 was $2.75 million; this use of cash, coupled with the cash used in investing activities, exceeded cash provided by financing activities by $2.0 million, and resulted in a corresponding decrease in cash. This net use of cash also substantially contributed to a $2.20 million decrease in working capital as of September 30, 2012 as compared to working capital as of December 31, 2011.
In the immediate term, the Company expects that additional capital will be required to fund its remaining capital budget for 2012, partially to fund some of its ongoing overhead, and to provide additional capital to generally improve its working capital position. In March 2012, the Company secured commitments to fund up to $5.0 million of additional convertible debentures, all of which had been funded as of September 30, 2012. (See Note 7—Loan Agreements.)
Pursuant to our credit agreements with Hexagon, LLC (“Hexagon”), a substantial portion of our monthly net revenues from our producing properties is required to be used for debt and interest payments. In addition, our debt instruments contain provisions that, absent consent of the lenders, may restrict our ability to raise additional capital. Also, the Hexagon debt is currently due on December 31, 2013 and will need to be extended or retired prior to that date.
The Company will continue to pursue alternatives to address its working capital position and capital structure and to provide funding for the balance of its planned 2012 expenditures.
On November 5, 2012, the Company liquidated all of its price derivatives for proceeds of $0.60 million.
2012 Capital Budget
Our anticipated 2012 capital expenditure budget is currently expected to total $7-$9 million, of which approximately $4.7 million has been expended through September 30, 2012. The remaining 2012 budget is allocated primarily to the drilling and completion of oil and gas wells in the DJ Basin in Wyoming, Nebraska and Colorado targeting the conventional Muddy ‘J’ sand targets, and to the conventional development of certain Niobrara and Codell properties.
Our 2012 drilling program has remained flexible in order to accommodate both the timing of the securing of adequate capital and to identify suitable well locations. We anticipate funding the remainder of the 2012 capital program through a combination of the issuance of additional equity or debt securities, use of existing working capital and operating cash flows, and from cash provided by potential joint venture participants and/or asset sales.
Other factors that could cause us to further increase our level of activity and adjust our capital expenditure budget include a reduction in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, a further improvement in commodity prices or well performance that exceeds our forecasts, any of which could positively impact our operating cash flow. Factors that could cause us to reduce level of activity and adjust our capital budget include, but are not limited to, increases in service and materials costs, reductions in commodity prices or under-performance of wells relative to our forecasts, any of which could negatively impact our operating cash flow.
In order to fund the remainder of the 2012 budget, the Company will need to secure additional financing. We may also choose to sell certain non-strategic assets in order to supplement the funding of our 2012 capital budget.
We cannot give assurances that our working capital on hand, our cash flow from operations or any available capital or borrowings, equity offerings or other financings, or sales of non-strategic assets will be sufficient to fund our anticipated capital expenditures. If our existing and potential sources of investment capital are not sufficient to undertake our planned 2012 capital expenditures, we may be required to reduce our 2012 drilling capital budget, curtail our expenditures and/or restructure our operations.
Capital Resources
Currently, the majority of our cash flows from operations are applied to the payment of principal and interest of our loans and to capital expenditures. Due to the continuing operating losses and the large amounts of capital expenditures during 2011 and continuing through 2012, our liquidity and working capital have deteriorated. While we believe that we have sufficient liquidity and capital resources to maintain our staff and continue our current production operations, we require additional capital to resolve our current working capital deficit and will also require substantial additional capital in order to fully test, develop and evaluate our 141,000 gross (126,000 net) undeveloped acres. We expect to obtain this capital through a variety of sources, including, but not limited to, future debt and equity financings and potentially from future joint venture partners. In the absence of near term major debt or equity financing or other similar transaction, we may be required to sell certain assets in order to meet obligations as they arise. We can provide no assurance that we will be able to secure a major financing, nor can we predict the terms of any future potential financing transactions.
Information about our financial position is presented in the following table:
| | | September 30, 2012 | | | December 31, 2011 | |
| Financial Position Summary | | | | | | |
| Cash and cash equivalents | | $ | 698,276 | | | $ | 2,707,722 | |
| Working capital | | $ | (907,863 | ) | | $ | 1,294,706 | |
| Balance outstanding on term loans and convertible debentures payable | | $ | 33,692,339 | | | $ | 29,680,636 | |
| Shareholders’ equity | | $ | 39,311,760 | | | $ | 49,668,225 | |
During the nine months ended September 30, 2012, our working capital decreased to $(0.91 million) from $1.29 million at December 31, 2011. The lower working capital and cash position is primarily the result of a combination of cash used in operating and investing activities, but partially offset by cash provided by financing activities.
A summary of cash flow results during the nine months ended September 30, 2012 follows:
| | | Nine Months Ended September 30, | |
| | | 2012 | |
| Cash provided by (used in): | | | |
| Operating activities | | $ | (2,747,079 | ) |
| Investing activities | | | (3,274,068 | ) |
| Financing activities | | | 4,011,701 | |
| | | | | |
| Net change in cash | | $ | (2,009,446 | ) |
During the nine months ended September 30, 2012, net cash used in operating activities was $2.75 million. The primary changes in operating cash during the nine months ended September 30, 2012 were $12.78 million of net loss, adjusted for non-cash charges of $4.51 million of depreciation, depletion, amortization and accretion expenses, $1.77 million of stock-based compensation, $3.27 million of impairment of evaluated properties, $2.23 million of amortization of deferred financing costs and issuance of stock for convertible debentures interest, and non-cash change in fair value of convertible debentures conversion option of $0.70 million, and offset by a non-cash charge for the change in commodity price derivatives of $0.45 million.
During the nine months ended September 30, 2012, net cash used in investing activities was $3.27 million. The primary changes in investing cash during the nine months ended September 30, 2012 were $0.44 million related to our acquisitions of unproved acreage and drilling capital expenditures of $4.28 million, offset by the proceeds from the sale of undeveloped properties of $1.44 million.
During the nine months ended September 30, 2012, net cash provided by financing activities was $4.01 million. The changes in financing cash during the nine months ended September 30, 2012 were from net proceeds from the issuance of new convertible debentures of $5.00 million, offset by the net repayments of debt of $0.98 million.
Term Loans
The Company entered into three separate loan agreements with Hexagon during 2010. All three loans bear annual interest of 15% and mature on December 31, 2013.
Effective January 29, 2010, the Company entered into a $4.5 million loan agreement, with an original maturity date of December 1, 2010. Effective March 25, 2010, the Company entered into a $6.00 million loan agreement, with an original maturity date of December 1, 2010. Effective April 14, 2010, the Company entered into a $15 million loan agreement, with an original maturity date of December 1, 2010. All three loan agreements have similar terms, including customary representations and warranties and indemnification, and require the Company to repay the loans with the proceeds of the monthly net revenues from the production of the acquired properties. The loans contain cross collateralization and cross default provisions and are collateralized by mortgages against a portion of the Company’s developed and undeveloped leasehold acreage as well as all related equipment purchased in the Wilke Field, Albin Field, and State Line Field acquisitions.
We entered into a loan modification agreement on May 28, 2010, which extended the maturity date of the loans to December 1, 2011. In consideration for extending the maturity of the loans, Hexagon received 250,000 warrants with an exercise price of $6.00 per share. The loan modification agreement also required the Company to issue 250,000 five year warrants to purchase common stock at $6.00 per share to Hexagon if the Company did not repay the loans in full by January 1, 2011. Since the loans were not paid in full by January 1, 2011, the Company issued 250,000 additional warrants with an exercise price of $6.00 per share to Hexagon which was valued at approximately $1.60 million. This amount was recorded as a deferred financing cost and is being amortized over the remaining term of the loan.
In December 2010, Hexagon extended the maturity to September 1, 2011. During the last six months of 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2.00 million as payment on the loans. In November 2011, Hexagon extended the maturity to January 1, 2013. In November 2011, Hexagon also temporarily advanced the Company an additional amount of $0.31 million, which was repaid in full in February 2012. In March 2012, Hexagon extended the maturity of the loans to June 30, 2013, and in connection therewith, the Company agreed to make minimum monthly loan payments of $0.33 million, effective immediately. In July 2012, Hexagon extended the maturity date to September 30, 2013. In November 2012, Hexagon extended the maturity date to December 31, 2013.
As of September 30, 2012, the total debt outstanding under these facilities is $20.29 million, of which $0.87 million is current portion of long term debt.
The Company is subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements. As of September 30, 2012, the Company was in compliance with all covenants under the facilities. If any of the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default and accelerate all principal and interest outstanding.
Convertible Debentures Payable
In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of three year 8% Senior Secured Convertible Debentures (the "Debentures") with a group of accredited investors. Initially, the Debentures were convertible at any time at the holders' option into shares of our common stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. Interest on the Debentures is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or at the Company's option in shares of common stock, valued at 95% of the volume weighted average price of the common stock for the 10 trading days prior to an interest payment date. The Company can redeem some or all of the Debentures at any time. The redemption price is 115% of principal plus accrued interest. If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price will include a make-whole premium equal to the remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable in common stock. T.R. Winston & Company LLC acted as placement agent for the private placement and received $0.40 million of Debentures equal to 5% of the gross proceeds from the sale. The Company is amortizing the $0.40 million over the life of the loan as deferred financing costs. The Company amortized $0.13 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.18 million of deferred financing costs to be amortized through February 2014.
In December, 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share.
This amendment was an inducement consideration to the Debenture holders for their agreement to release a mortgage on certain properties so the properties could be sold. The sale of these properties was effective December 31, 2011, and a final closing occurred during the three months ended March 31, 2012.
On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to increase the amount of its Debentures by up to an additional $5.0 million (the “Supplemental Debentures”). Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of Supplemental Debentures are to be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other general corporate purposes. Any new producing properties that are developed from the proceeds of Supplemental Debentures are to be pledged as collateral under a mortgage to secure future payment of the Debentures and Supplemental Debentures. All terms of the Supplemental Debentures are substantively identical to the Debentures. The Agreements also provided for the payment of additional consideration to the purchasers of Supplemental Debentures in the form of a proportionately reduced, 5% carried working interest in any properties developed with the proceeds of the Supplemental Debenture offering.
Through July 2012, we received $3.04 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development of six new wells, resulting in a total investment of $3.69 million. Five of these wells resulted in commercial production, and one well was plugged and abandoned.
In August 2012, the Company and certain holders of the Supplemental Debentures agreed to renegotiate the terms of the Supplemental Debenture offering. These negotiations concluded with the issuance of an additional $1.96 million of Supplemental Debentures. The August 2012 modifications to the Supplemental Debenture agreements increased the carried working interest from 5% to 10% and also provided for a one-year, proportionately reduced net profits interest of 15% in the properties developed with the proceeds of the Supplemental Debenture offering, as well as the next four properties to be drilled and developed by the Company.
The Company has estimated the total value of consideration paid to Supplemental Debenture holders in the form of the modified net profits interest and carried working interest to be approximately $1.16 million, and recorded this amount as a debt discount to be amortized over the remaining life of the Debentures.
We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect to September 30, 2012, the Supplemental Debentures. This valuation resulted in an estimated derivative liability as of September 30, 2012 and December 31, 2011 of $1.3 million and $1.3 million, respectively. The portion of the derivative liability that is associated with the Supplemental Debentures, in the approximate amount of $0.70 million, has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.
During the nine and three months ended September 30, 2012, the Company amortized $1.65 million and $0.71 million, respectively of debt discounts.
On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures. The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs. The Company amortized $0.01 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.22 million of deferred financing costs to be amortized through February 2014.
As of September 30, 2012 and December 31, 2011, the convertible debt is recorded as follows:
| | As of | | As of | |
| | | September 30,
2012 | | | December 31, 2011 | |
| Convertible debentures | | $ | 13,400,000 | | | $ | 8,400,000 | |
| Debt discount | | | (3,804,947 | ) | | | (3,470,932 | ) |
| Total convertible debentures, net | | $ | 9,595,053 | | | $ | 4,929,068 | |
Annual debt maturities as of September 30, 2012 are as follows:
| Year 1 | | $ | 873,142 | |
| Year 2 | | | 32,819,197 | |
| Thereafter | | | - | |
| Total | | $ | 33,692,339 | |
Interest Expense
For the nine months ended September 30, 2012 and 2011, the Company incurred interest expense of approximately $6.32 million and $6.12 million, respectively, of which approximately $3.8 million and $3.70 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures payable interest paid in stock.
For the nine months ended September 30, 2012 and 2011, the Company incurred interest expense of approximately $6.32 million and $6.12 million, respectively, of which approximately $3.86 million and $3.70 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures payable interest paid in stock.
Obligations and Commitments
We have the following contractual obligations and commitments as of September 30, 2012 (in thousands):
| | | Payments due by period | |
Contractual obligations | | Total | | | Within 1 year | | | 2-3 years | | | 4-5 years | | | More than 5 years | |
| Secured debt | | $ | 20,292,339 | | | $ | 873,142 | | | $ | 19,419,197 | | | $ | — | | | $ | — | |
| Interest on secured debt | | | 4,016,115 | | | | 3,026,858 | | | | 989,257 | | | | — | | | | — | |
| Convertible debentures | | | 13,400,000 | | | | — | | | | 13,400,000 | | | | — | | | | — | |
| Interest on convertible debentures | | | 1,608,000 | | | | 1,072,000 | | | | 536,000 | | | | — | | | | — | |
| Operating leases | | | 54,000 | | | | 54,000 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Total contractual cash obligations (1) | | $ | 39,370,454 | | | $ | 5,026,000 | | | $ | 34,344,454 | | | $ | — | | | $ | — | |
(1) We could be liable for liquidated damages under registration rights agreements covering approximately 3.2 million shares of our common stock if we fail to maintain the effectiveness of a prior registration statement as required in the agreements. In such case, we would be required to pay monthly liquidated damages of up to $0.23 million. The maximum aggregate liquidated damages are capped at $1.37 million.
Under the terms of the Supplemental Debenture agreements, the Company has a commitment to drill four additional wells. Such agreements do not specify the location, timing, target zones, or other conditions related to these wells. However, the Company anticipates that the capital commitment required to satisfy this provision will be approximately $3.3 million.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Plan of Operations
Our plan of operations for through the remainder of 2012 is to identify and develop oil and natural gas prospects from our existing inventory of undeveloped acreage. In this regard, we have gradually added structure and staffing to our company as we become the operator of an increasing number of acquired properties. By acting as the operator, we have greater control over operating, drilling and developmental decisions, and would expect to generally better control our overall finding costs as we increase our exploration and development activities.
We anticipate the investment of substantial capital during the next few years to evaluate, assess and develop our existing inventory 141,000 gross, 126,000 net acres of developed and undeveloped oil and gas leases.
The acquisition and development of properties and prospects and the pursuit of fresh opportunities require that we maintain access to adequate levels of capital. We will strive for an optimal balance between our property portfolio and our capital structuring that will allow for growth designed to build shareholder value and profitability. The decisions around the balancing of capital needs and property holdings will be a challenge to us as well as all companies in the entire energy industry during this time of continued disruption in the financial markets and an increasingly complex global economic picture. As a function of balancing properties and capital, we may decide to monetize certain properties to reduce debt or to allow us to acquire interests in new prospects or producing properties that may be better suited to the current economic and energy industry environment.
The business of oil and natural gas acquisition, exploration and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. Therefore, a principal part of our plan of operations is to raise the additional capital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties. As explained above in the “Liquidity and Capital Resources” section, based on our present working capital and current rate of cash flow from operations, we will need to raise additional capital to partially fund our overhead, and fund our exploration and development budget through, at least, December 31, 2012. We will seek additional capital through the sale of our securities and we will endeavor to obtain additional capital through debt and project financing. However, as described further below, under the terms of our $21.0 million credit facilities, we are prohibited from incurring any additional debt from third parties without prior consent from our lender. Our ability to obtain additional capital through new debt instruments and project financing may be subject to the repayment of our $21.0 million credit facility.
We intend to use the services of independent consultants and contractors to perform various professional services, including land, legal, environmental, investor relations and tax services. We believe that by limiting our management and employee costs, we may be able to better control total costs and retain flexibility in terms of project management.
Marketing and Pricing
We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.
Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of oil and natural gas. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:
| ● | changes in global supply and demand for oil and natural gas; |
| ● | the actions of the Organization of Petroleum Exporting Countries, or OPEC; |
| ● | the price and quantity of imports of foreign oil and natural gas; |
| ● | acts of war or terrorism; |
| ● | political conditions and events, including embargoes, affecting oil-producing activity; |
| ● | the level of global oil and natural gas exploration and production activity; |
| ● | the level of global oil and natural gas inventories; |
| ● | weather conditions; |
| ● | technological advances affecting energy consumption; and |
| ● | the price and availability of alternative fuels. |
From time to time, we will enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:
| ● | our production and/or sales of natural gas are less than expected; |
| ● | payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or |
| ● | the counter party to the hedging contract defaults on its contract obligations. |
In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States, or GAAP, requires our management to make 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 and the reported amounts of revenues and expenses during the reporting period. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures.
Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial condition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.
Use of Estimates
The financial statements included herein were prepared from the records of Recovery in accordance with GAAP, and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods. The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe that our estimates are reasonable. Our most significant financial estimates are associated with our estimated proved oil and gas reserves as well as valuation of common stock used in various issuances of common stock, options and warrants and estimated fair value of the asset held for sale.
Oil and Natural Gas Reserves
We follow the full cost method of accounting. All of our oil and gas properties are located within the United States, and therefore all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the SEC rules, we prepared our oil and gas reserve estimates as of September 30, 2012, using the average, first-day-of-the-month price during the 12-month period ending September 30, 2012.
Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.
We believe estimated reserve quantities and the related estimates of future net cash flows are the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are 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 periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discount rate. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change. We evaluate and estimate our oil and natural gas reserves as of December 31 of each year and quarterly throughout the year. For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.
Oil and Natural Gas Properties—Full Cost Method of Accounting
We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.
Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure.
Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations.
Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%. Royalties paid, net of any tax credits received, are netted against oil and natural gas sales.
In applying the full cost method, we perform a ceiling test on properties that restricts the capitalized costs, less accumulated depletion, from exceeding an amount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleum engineers. The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the end of the applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financing costs, future site restoration costs and income taxes. Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.
As of September 30, 2012, the Company has one well in progress that has been drilled, completed and is pending further evaluation as to its potential to ultimately produce commercial quantities of hydrocarbons. This well is currently carried at a cost of $3.82 million. The Company believes that this well should be ultimately capable of commercial production, but will need to invest additional capital to obtain this status. However, should this well be ultimately plugged and abandoned, all capitalized costs would be transferred to the full cost pool. Given the current status of the ceiling tests as of September 30, 2012, the current carrying costs would exceed the ceiling by the amount of $1.44 million, which would flow through the income statement as an expense if the well were assumed to be non-productive as of September 30, 2012.
Likewise, operations that are being conducted on this well are extending the primary terms of leases that comprise approximately 6,919 net acres and that are currently being carried at a cost of approximately $4.1 million. Absent a successful completion of this well, the lease terms of some or all of these acres may expire, and the carrying costs of these leases would also be subject to the ceiling test.
Revenue Recognition
The Company derives revenue primarily from the sale of produced natural gas and crude oil. The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses and are included in oil and gas production expense in the accompanying consolidated statements of operations. Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses its knowledge of its properties, their historical performance, NYMEX and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates.
Share Based Compensation
The Company accounts for share-based compensation by estimating the fair value of share-based payment awards made to employees and directors, including restricted stock grants, on the date of grant. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods.
Derivative Instruments
Periodically, the Company entered into swaps to reduce the effect of price changes on a portion of our future oil production. We reflect the fair market value of our derivative instruments on our balance sheet. Our estimates of fair value are determined by obtaining independent market quotes as well as utilizing a valuation model that is based upon underlying forward curve data and risk free interest rates. Changes in commodity prices will result in substantially similar changes in the fair value of our commodity derivative agreements. We do not apply hedge accounting to any of our derivative contracts, therefore we recognize mark-to-market gains and losses in earnings currently.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Market risk represents the risk of loss that may impact our financial position, results of operations, or cash flows due to adverse changes in financial market prices, including interest rate risk, foreign currency exchange rate risk, commodity price risk, and other relevant market or price risks.
Commodities Price Risk. Our financial condition, results of operations and capital resources are dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our development activities.
In order to protect the Company from uncertainty associated with oil and natural gas prices we entered into the following:
On December 21, 2011, we entered into a Commodity Fixed Price Swap contract that covers approximately 40% of our forecasted 2012 oil production. This contract covers 100 bopd throughout 2012, or a total of 36,600 barrels, and establishes a fixed sales price per barrel of $96.25. At the end of each month in 2012, the fixed price is compared to a floating price equal to the average of settlement prices of the Nymex Prompt month WTI crude oil contract. If the fixed price is less than the floating price, then the Company will make an immediate payment to the swap counterparty equal to the difference in the fixed and floating prices multiplied by the monthly oil volume (3,000 barrels in a 30 day month). Alternatively, if the fixed price is more than the floating price, then we will receive a payment from the swap counterparty equal to the difference between the fixed and floating prices multiplied by the monthly volume.
On March 21, 2012, we entered into a similar Commodity Fixed Price Swap contract that covers 100 bopd throughout the first six months of 2013, or a total of 18,100 barrels, and establishes a fixed sales price per barrel of $106.25.
On September 7, 2012, we entered into a similar Commodity Fixed Price Swap contract that covers 100 bopd throughout 2013, or a total of 36,500 barrels, and establishes a fixed sales price per barrel of $96.90.
As of September 30, 2012, we marked these swaps to market, based upon the estimated forward floating price of each contract as compared to the current market price for crude oil, and recorded an unrealized commodity derivative receivable asset related to these Swap contracts of approximately $0.37 million.
On November 5, 2012, the Company liquidated all of its price derivatives for proceeds of $0.60 million.
We may, from time to time, enter into other similar agreements in order to hedge oil prices from future substantial price swings.
Interest Rate Risk. We have minimal interest rate risk as all of our debt currently provides for fixed interest rates. However, we may enter into future transactions that could result in higher interest rates, or in floating or adjustable interest rates that could expose the Company to additional interest rate risks.
Foreign Currency Risk. We do not currently have any substantial exposure to foreign currency risk.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2012, the end of the period covered by this report. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2012, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, systems that are more efficient, consolidating activities, and migrating processes.
In our Annual Report on Form 10K/A for the year ended December 31, 2011, we noted that the following material weaknesses in our internal control over financial reporting existed as of December 31, 2011:
| ● | Insufficient independent internal review and approval of critical accounting schedules used in the preparation of financial statements. |
| ● | The financial statement close process did not permit timely preparation of necessary financial information and there is inadequate documentation of internal controls for some assertions in certain significant accounts. |
| ● | Lack of effective controls over general ledger processing, spreadsheets and data back-up. |
These material weaknesses continued to exist during the three months ending March 31, 2012, June 30, 2012, and September 30, 2012.
We have implemented the following new internal controls during the three months ending September 30, 2012:
| ● | Additional controls were implemented during 2012 within the areas of internal controls over financial reporting including (but not limited to) the implementation of a new accounting system, timely management contract review and tracking, journal entry review and posting procedures, the timely and consistent reconciliation of balance sheet accounts to mitigate the risk of financial reporting inaccuracies, revenue recognition procedures, and month-over-month financial analyses to allow for trend analysis and the timely capture of coding errors. Additional controls were implemented over daily financial network and application data backups to an off-site server to ensure the safety and redundancy of shareholder data and the ability to retrieve shareholder data as needed. |
| ● | Management believes the implementation and timely testing of these controls will assist with the accuracy of the financial schedules and statements. All financial statement assertion gaps have been addressed by the implementation of these new controls. |
Management conducted an evaluation of the effectiveness of our internal control over financial reporting as of September 30, 2012, based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was not effective as of September 30, 2012 and that the material weaknesses documented in the Annual Report on Form 10K/A for the year ending December 31, 2011 continue to exist but that significant effort has been made to remediate these issues and that management expects the material weaknesses will be fully remediated by December 31, 2012.
Other than as noted above, there were no other changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Limitations in Control Systems
Our controls and procedures are designed at a reasonable assurance level. In designing and evaluating our controls and procedures, management recognizes that, because of inherent limitations, any system of controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance of achieving the desired objectives of the control system. In addition, the design of a control system must reflect the fact that there are resource constraints, and management must apply its judgment in evaluating the benefits of possible controls relative to their costs. Further, no evaluation of controls and procedures can provide absolute assurance that all errors, control issues, and instances of fraud will be prevented or detected. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls and procedures is also based in part on certain assumptions regarding the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
Currently we are not aware of any material litigation pending or threatened by or against the Company.
Item 1A. Risk Factors.
There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2011 Annual Report on Form 10-K/A filed with the Securities and Exchange Commission, which we incorporate by reference herein, except that we have the following new risk factor which was included in our Quarterly Report on form 10-Q for the quarters ended March 31, 2012 and June 30, 2012:
If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, wells in progress are deemed unsuccessful, or major tracts of undeveloped leases expire, or other similar adverse events occur, we may be required to write-down the carrying value of our evaluated properties.
We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling wells, completing productive wells, or plugging and abandoning non-productive wells, costs related to expired leases, or leases underlying producing and non-producing wells, and overhead charges directly related to acquisition and exploration activities. Under the full cost method of accounting, capitalized oil and natural gas property that comprise the full cost pool, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves. This ceiling test is performed at least quarterly. Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize impairment expense. Effective with our report on Form 10-Q for the quarter ended March 31, 2012, we recognized impairment expenses in the amount of approximately $3.3 million related to impairment of the carrying value of the evaluated properties that comprised the full cost pool. Future write-downs could occur for numerous reasons, including, but not limited to reductions in oil and gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserve estimates, or from the addition of non-productive capitalized costs to the full cost pool that do not result in corresponding increase in oil and gas reserves. Impairments of unevaluated leases and plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full cost pool, without any corresponding increase in reserve values; as such, these situations could result in future additional impairment expenses.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to increase the amount of its Debentures by up to an additional $5.0 million (the “Supplemental Debentures”). Under the terms of the Supplemental Debenture Agreements, proceeds derived from the issuance of Supplemental Debentures are to be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other working capital purposes. Any new producing properties that are developed from the proceeds of Supplemental Debentures are to be pledged as collateral to secure future payment of the Debentures. All terms of the Supplemental Debentures are substantively identical to the Debentures.
As of September 30, 2012, we received $5.0 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development of six new wells, resulting in a total investment of $3.69 million. The remaining $1.31 million was used for general corporate purposes. Five of the wells drilled with the proceeds of the Supplemental Debentures resulted in commercial production, and one well was plugged and abandoned. Under the terms of the Supplemental Debenture agreements, as amended, the Company also has an obligation to drill four additional wells that will be subject to the terms of such agreements.
The $5.0 million of convertible debentures that have been issued are currently convertible into 1,176,471 shares of common stock, at the rate of $4.25 per common share, subject to adjustment under certain circumstances. Under the terms of the March 19, 2012 agreements as amended, we have no obligation to register any of the convertible debentures that are or may be issued, or any of the underlying common stock that may be issued upon conversion of any such convertible debentures.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
Not Applicable
Item 5. Other Information.
None.
Exhibit Number | | Exhibit Description |
| 31.1 | | Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002 |
| 31.2 | | Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002 |
| 32.1 | | Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes Oxley Act of 2002 |
| 32.2 | | Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes Oxley Act of 2002 |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant caused this amended report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | Recovery Energy, Inc. | |
| | | |
| Date: November 9, 2012 | By: | /s/ Roger A. Parker | |
| | | Roger A. Parker | |
| | | Chief Executive Officer | |
| Date: November 9, 2012 | By: | /s/ A. Bradley Gabbard | |
| | | A. Bradley Gabbard | |
| | | Chief Financial Officer | |
| Date: November 9, 2012 | By: | /s/ Eric Ulwelling | |
| | | Eric Ulwelling | |
| | | Principal Accounting Officer | |
