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.
Year ended December 31, 2011 compared to year ended December 31, 2010
The following table compares operating data for the fiscal year ended December 31, 2011 to December 31, 2010:
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
Revenues and other income:
|
|
|
|
|
|
|
Oil sales
|
|
|
7,148,110
|
|
|
|
9,504,737
|
|
Gas sales
|
|
|
547,190
|
|
|
|
68,075
|
|
Realized gains on commodity hedges
|
|
|
625,043
|
|
|
|
570,233
|
|
Other
|
|
|
41,751
|
|
|
|
(385,353
|
)
|
Total revenues
|
|
|
8,362,094
|
|
|
|
9,757,692
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Production Costs
|
|
|
1,514,784
|
|
|
|
862,042
|
|
Production Taxes
|
|
|
838,714
|
|
|
|
1,056,244
|
|
General and administrative
|
|
|
10,544,347
|
|
|
|
15,530,248
|
|
Impairment of oil and natural gas properties
|
|
|
2,821,176
|
|
|
|
-
|
|
Depreciation depletion and amortization
|
|
|
4,347,117
|
|
|
|
5,036,648
|
|
Bad debt expense
|
|
|
-
|
|
|
|
400,000
|
|
Total expenses
|
|
|
20,066,138
|
|
|
|
22,885,182
|
|
Income (loss) from continuing operations
|
|
|
(11,704,044
|
)
|
|
|
(13,127,490
|
)
|
Interest expense
|
|
|
(8,218,225
|
)
|
|
|
(6,640,209
|
)
|
Other
|
|
|
71,253
|
|
|
|
28,666
|
|
Debt Inducement Expense
|
|
|
(2,800,000
|
)
|
|
|
-
|
|
Conversion Note Derivative Gain
|
|
|
3,821,792
|
|
|
|
-
|
|
Net income
|
|
|
(18,829,224
|
)
|
|
|
(19,739,033
|
)
|
Total revenues in 2011 declined from $9.8 million in 2010 to $8.4 million in 2011 due primarily to a decrease in net oil production due to natural production declines. This reduction in oil sales was partially offset by an increase in net gas production, but also affected by changes in the average unit prices received by the Company for the sale of its oil and gas products. The following table shows the comparison of production volume and average prices:
|
|
Year Ended December 31,
|
|
|
|
2011
|
|
|
2010
|
|
Oil Sales (net bbls)
|
|
|
81,443
|
|
|
|
133,709
|
|
Gas Sales (net mcf)
|
|
|
115,583
|
|
|
|
14,914
|
|
|
|
|
|
|
|
|
|
|
Average Oil Price
|
|
$
|
87.77
|
|
|
$
|
71.08
|
|
Average Gas Price
|
|
$
|
4.73
|
|
|
$
|
4.56
|
|
|
|
|
|
|
|
|
|
|
Average Price per BOE
|
|
|
76.41
|
|
|
|
74.47
|
|
Production Costs
|
|
|
15.19
|
|
|
|
6.33
|
|
Production Taxes
|
|
|
8.18
|
|
|
|
7.76
|
|
Depreciation and Amortization
|
|
|
42.25
|
|
|
|
36.98
|
|
Total Operating Costs
|
|
|
65.62
|
|
|
|
51.07
|
|
Gross Margin
|
|
|
10.79
|
|
|
|
23.40
|
|
Gross Margin %
|
|
|
14.12
|
%
|
|
|
31.42
|
%
|
Oil volumes declined 39%, gas volume increased by 675%, and prices for both oil and gas increased. The gas volume increase can be attributed to the production of one gas well that produced during the entirety of 2011, but only for part of 2010. The decline in oil volume is due almost entirely to natural production declines.
Other revenues in 2010 included an unrealized loss on commodity hedges of $399,000. Unrealized losses on commodity hedges in 2011 were nominal.
Production taxes in 2011 decreased by 22% in 2011 as a result in the overall decrease in oil and gas sales. Production costs increased by 77%. This increase is due primarily to an increase in the number of workovers, property improvements and other onsite work that was performed on our producing properties during the year.
Depletion expense declined in 2011 by 16% as a result of lower unit volumes of oil and gas sales, and a declining cost center, even though the cost per BOE increased by 14%.
An impairment expense of $2.8 million was recorded in 2011 as a result of capitalized costs exceeding the standardized measure of reserve values.
General and administrative expenses declined 32% in 2011 as compared to 2010. 2011 general and administrative expenses included non-cash stock compensation expense of $6.7 million compared to $13.1 million in 2010. Excluding these non-cash components, cash general and administrative expenses were $3.9 million in 2011 compared to $2.23 million in 2010. Cash general and administrative expenses in 2011 increased primarily as a result of an increase in payroll, and legal and third party fees related to transactions, as well as general increases in other general and administrative expense areas.
Interest expense increased by $1.6 million in 2011 as compared to 2010. 2011 interest includes non-cash loan costs amortization of $5.0 million, and cash interest expense of $3.2 million, compared to cash interest expense in 2010 of $2.7 million. Cash interest increased in 2011 primarily as a result of an increase in the average level of debt.
In 2011, we recorded inducement expense of $2.8 million related to an amendment of our convertible debentures that reduced the conversion price from $9.40 to $4.25 per share. The inducement related to a request to the holders of the convertible debentures to release certain collateral so that it could be sold. We also recorded derivative gains of $3.8 million related to the reduction of liability attributed to the conversion feature recorded as of the original transaction date in the first quarter of 2011, versus the liability related to this conversion feature as of the end of the year.
Year ended December 31, 2010 compared to year ended December 31, 2009
In general our revenues and expenses were significantly higher in 2010 when compared to inception through December 31, 2009 as during 2009 we were a development stage company with minimal activities. In January 2010, we acquired our first producing oil and gas assets and incurred interest expense with the associated debt utilized to acquire the property. Therefore, results are generally not comparable for the year ended December 31, 2010 to the period of inception through December 31, 2009. We have presented the results for each period below.
Revenue and other income:
For the twelve month period ended December 31, 2010, we had $9,504,737 in oil sales and $68,075 in natural gas sales, respectively.
Average daily net production for the twelve month period ended December 31, 2010 was 373 BOEPD.
Miscellaneous Income and Operating Fees
We earned net operating fees of $13,487 during the twelve months ended December 31, 2010. We realized a mark-to-market gain of $28,666 during the twelve months ended December 31, 2010 on a put agreement associated with 85,000 shares of stock placed in conjunction with our reverse merger in September 2009.
Price Risk Management Activities
We recorded a net loss on our derivative contracts that do not qualify for cash flow hedge accounting of $(398,840) for the year ended December 31, 2010. This amount represents an unrealized non-cash loss which represents a change in the fair value of our mark-to-market derivative instruments at December 31, 2010 as detailed in “Note 5 – Financial Instruments and Derivatives” and “Note 6 – Fair Value of Financial Instruments”. We realized a gain on our derivative contracts that do not qualify for cash flow hedge accounting $570,233 for the year ended December 31, 2010. This amount represents a realized cash gain from the settlement of our forward sale contracts for the quarter ended December 31, 2010 as detailed in “Note 5 – Financial Instruments and Derivatives” and “Note 6 – Fair Value of Financial Instruments”.
Oil and Gas Production Expenses, Depreciation, Depletion and Amortization
|
|
Years ended December 31,
|
|
|
|
2010
|
|
|
2009 (1)
|
|
Net production
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
133,709
|
|
|
|
-
|
|
Gas (Mcf)
|
|
|
14,914
|
|
|
|
-
|
|
MBOE
|
|
|
136,195
|
|
|
|
-
|
|
Average net daily production
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
366
|
|
|
|
-
|
|
Gas (Mcf)
|
|
|
41
|
|
|
|
-
|
|
BOE
|
|
|
373
|
|
|
|
-
|
|
Average realized sales price, excluding the effects of hedging
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
71.08
|
|
|
$
|
-
|
|
Gas (per Mcf)
|
|
$
|
4.56
|
|
|
$
|
-
|
|
Per BOE
|
|
$
|
70.29
|
|
|
$
|
-
|
|
Average realized sales price, including the effects of hedging
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
75.27
|
|
|
$
|
-
|
|
Gas (per Mcf)
|
|
$
|
4.56
|
|
|
$
|
-
|
|
Per BOE
|
|
$
|
74.47
|
|
|
$
|
-
|
|
Production costs per BOE
|
|
|
|
|
|
|
|
|
Lease operating expense (2)
|
|
$
|
6.33
|
|
|
$
|
-
|
|
DD&A
|
|
$
|
36.98
|
|
|
$
|
-
|
|
Production taxes
|
|
$
|
7.76
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
Total operating costs
|
|
$
|
51.07
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
Gross margin percentage
|
|
|
31
|
%
|
|
$
|
-
|
%
|
(1)
|
Prior to January 2010, the Company did not own any oil and gas properties.
|
(2)
|
Approximately $2.35/BOE of lease operating expense relates to surface, subsurface, road repairs and work-over activities.
|
General and Administrative Expenses
General and administrative expenses were $15,530,248 for the year ended December 31, 2010. Our general and administrative expenses twelve months ended December 31, 2010 included $1,464,990 in professional fees (financial advisors, attorneys, accountants, and reserve engineers) of which $372,393 were noncash, and $9,958,300 in non-cash compensation expense. We also incurred a non-cash expense of $54,500 in rental expense for our office lease for the year ending December 31, 2010 and a non-cash warrant modification expense of $2,953,450 for the year ended December 31, 2010. Total non-cash general and administrative expenditures for the year ended December 31, 2010 was approximately $13,300,000. This compares to approximately $1,057,306 in general and administrative expenditures from inception through December 31, 2009 which included non-cash expenditures of $690,000.
Depreciation Expense
Depreciation and amortization expense were $5,036,648 for the twelve months ended December 31, 2010.
Interest Expense
Total interest expense was $6,640,209 for the year ended December 31, 2010. The interest expense was comprised of $3,989,649 in non-cash amortization of expenses for the year ended December 31, 2010 related to warrants issued and overriding royalty interests assigned to our lender in conjunction with the closing of the three credit agreements and the extension of the credit agreements. We incurred $2,655,131 in cash interest expense for the year ended December 31, 2010. Neither we nor our predecessor business incurred interest expense from inception through December 31, 2009.
We incurred a net loss to common shareholders of $19,739,033 for the year ended December 31, 2010.
Financial Condition and Liquidity
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.
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.
On March 19, 2012, we entered into agreements with our existing convertible debenture holders to issue up to an additional $5.0 million in convertible debentures. All terms of the new convertible debentures are substantively identical to the existing convertible debentures. This financing was completed by September 30, 2012.
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
|
|
Cash used in operating activities during the year ended December 31, 2011 was $.6 million, and cash used in investing activities exceeded cash provided by financing activities by approximately $2.2 million. This net cash use contributed to a substantial decrease in our net working capital as of December 31, 2011. Expenditures subsequent to December 31, 2011 have continued to exceed cash receipts, causing a further reduction of the Company’s working capital position.
During the year ended December 31, 2011, our working capital decreased to $1.3 million compared to $4.4 million at December 31, 2010. This lower level of working capital is primarily of the result of cash used in operations, and cash investing activities that exceeded cash provided by financing activities.
During the year ended December 31, 2011, net cash used in operating activities was $570,000. The primary changes in operating cash during the year ended December 31, 2010 were $18.8 million of net loss, adjusted for non-cash charges of $ 4.3 million of depreciation, depletion and amortization expenses and accretion expense, $6.5 million of stock-based compensation and stock paid for services, $4.4 million of amortization of deferred financing costs, $2.8 million of impairment expense, $2.8 million of debt inducement expense, and offset by $3.3 million in non-cash gains on derivatives.
During the year ended December 31, 2011, net cash used by investing activities was $13.3 million. The primary changes in investing cash during the year ended December 31, 2011 was $9.4 million in expenditures related to our acquisitions which consisted primarily of the undeveloped acreage, and $7.0 million in drilling capital expenditures, offset by $3.0 million in proceeds received from the sale of certain undeveloped acreage.
During the year ended December 31, 2011, net cash provided by financing activities was $11.0 million. The primary changes in financing cash during the year ended December 31, 2011 were $8.0 million related to the issuance of convertible debt, $2.1 million derived from the issuance of common stock, and $.9 million in other changes in debt.
Pursuant to our credit agreements with Hexagon, a substantial portion of our monthly net revenues derived 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.
In December 2011, we sold certain undeveloped acreage for total proceeds of $4.5 million. During 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues of approximately $2,000,000 in the aggregate as payment on the Hexagon debt. In November 2011, Hexagon extended the maturity date of their notes to January 1, 2013, and also advanced an additional $309,000 to us. We repaid the $309,000 advance in February 2012. In March 2012, Hexagon extended the maturity date of their Notes to June 30, 2013, and in connection therewith we agreed to make minimum monthly note payments of $325,000, effective immediately. We will continue to pursue alternatives to shore up our working capital position and to provide funding for our planned 2012 expenditures.
Our primary term debt of $19.5 million is currently due on December 31, 2013. We will need to replace or refinance this debt prior to its due date. While we believe we have sufficient liquidity and other sources of capital available to us that will allow us to conduct our current operations for the next 12 months, we will need to find additional sources of capital to fund our 2013 drilling budget and, if necessary, to replace our existing debt facility. We will seek to obtain this additional capital 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. We may also choose to sell certain non-strategic assets in order to supplement the funding of our 2013 capital budget.
Currently, we have no agreements or understandings with any third parties at this time for additional working capital. Further, under the terms of our credit agreements, we are prohibited from incurring any additional debt from third parties without prior consent from our lender. Our ability to obtain additional working capital through bank lines of credit and project financing would likely be subject to the repayment of the approximately $19.5 million debt related to our primary credit facility. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price will be materially adversely affected.
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 properties acquired using the loan proceeds. 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 of the loans 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 reflected as the 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 8% Senior Secured Convertible Debentures due February 2, 2014 (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 years ended December 31, 2011 and 2010, the Company incurred interest expense of approximately $8.2 million and $6.6 million, respectively, of which approximately $5.0 million and $3.9 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.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
2013 Capital Budget
Our 2013 Capital Budget is currently projected to be approximately $15 million, but is subject to securing sufficient capital to support planned drilling and development expenses. We anticipate that approximately 50% of this budget will be allocated toward the development of two of our unconventional prospects located in the Wattenburg field of the DJ Basin that will target horizontal drilling and development of the Niobrara shale and Codell formations. The remainder of our 2013 budget is anticipated to be directed principally toward the conventional development of certain lower risk offset wells to existing production. We also anticipate the allocation of approximately 10% of our 2013 capital budget toward higher risk exploration activities, including the procurement of seismic and the drilling of one conventional exploratory well.
Our 2013 capital expenditure budget was subject to various factors, including market conditions, availability of capital, oilfield services and equipment availability, commodity prices and drilling results. Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget as the cash flow from the wells could provide additional capital which we may use to increase our capital budget. We do not anticipate any significant expansion of our current acreage position.
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.
Capital Resources
Our 2013 capital program is subject to securing sufficient capital, principally via the issuance of additional equity and debt both to fund our capital program and to refinance the Hexagon loans which are due on December 31, 2013. We may also secure additional capital by pursuing sales of certain assets that are considered non-strategic. We may also seek to finance certain projects via joint venture agreements or other arrangements with strategic or industry partners.
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 address our upcoming debt maturities, and will also require substantial additional capital in order to fully test, develop and evaluate our 125,000 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. Unless we are successful in competing a substantial debt and/or equity financing or other similar transaction in the near term, 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.
We cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings, equity offerings or other financings, or sales of non-strategic assets will be sufficient to fund our anticipated 2013 capital expenditures.
Plan of Operations
Our plan of operations is to identify and develop oil and natural gas prospects from our existing inventory of undeveloped acreage. We anticipate the investment of substantial capital during the next few years to evaluate, assess and develop this inventory. Currently, our inventory of developed and undeveloped leases includes approximately 21,800 net acres that are held by production, approximately 11,600 net acres that expire in 2013, and approximately 25,000 net acres, 59,000 net acres and 7,600 net acres that expire in the years 2014, 2015 and thereafter, respectively. Approximately 64% of our remaining inventory of undeveloped leases provide for extension of lease terms from two to five years, at the option of the Company, via payment of varying, but typically nominal, extension amounts.
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 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.
Likewise, operations that are being conducted on this well are extending the primary terms of leases that comprise approximately 6,919 net acres 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 transferred to the full cost pool.
The acquisition and development of properties and prospects and the pursuit of new 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 under “Financial Condition and Liquidity”, 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, 2013. 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, under the terms of our $19.5 million in 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 $19.5 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 undeveloped 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.
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 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.
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 transferred to the full cost pool.
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.
The following table sets forth the names, ages and positions of the persons who are our directors and named executive officers as of the date of this prospectus:
|
|
|
|
|
|
|
|
|
|
W. Phillip Marcum
|
|
68
|
|
Chief Executive Officer, Chairman
|
A. Bradley Gabbard
|
|
58
|
|
President, Chief Financial Officer, Director
|
Bruce B. White
|
|
60
|
|
Director
|
Timothy N. Poster
|
|
43
|
|
Director
|
D. Kirk Edwards
|
|
52
|
|
Director
|
Directors hold office for a period of one year from their election at the annual meeting of stockholders and until a particular director’s successor is duly elected and qualified. Officers are elected by, and serve at the discretion of, our board of directors. None of the above individuals has any family relationship with any others. It is expected that our board of directors will elect officers annually following each annual meeting of stockholders.
W. Phillip Marcum: Chief Executive Officer and Chairman of the Board of Directors. Mr. Marcum joined our board of directors in September, 2011. He has been a director of Houston Texas-based Key Energy Services (NYSE: KEG) since 1996. Mr. Marcum was the non-executive chairman of the board of WellTech, Inc., an energy production services company, from 1994 until March 1996, when WellTech was merged into Key Energy Services. From January 1991 until April 2007, when he retired, he was chairman of the board, president and chief executive officer of Metretek Technologies, Inc. (now known as PowerSource International, Inc., and formerly known as Marcum Natural Gas Services, Inc.). He has been a principal in MG Advisors, LLC since April 2007. Mr. Marcum also serves as chairman of the board of ADA-ES, a Denver, Colorado based company (“ADA”), and chairman of the board of Applied Natural Gas Fuels, Inc. (formerly PNG Ventures, Inc.), a Westlake Village, California based company. He holds a bachelor's degree in business administration from Texas Tech University. When determining Mr. Marcum’s qualifications to serve as a director of the Company, the Company considered his leadership experience, as chairman of the board, president and CEO of PowerSecure International, Inc., director of Key Energy Services, non-executive chairman of WellTech and chairman of the boards of ADA and Applied Natural Gas Fuels, and his industry experience, which includes extensive experience in oil and gas development stage and public companies at the entities and in the capacities described above.
A. Bradley Gabbard: President, Chief Financial Officer and Director. Mr. Gabbard became our chief financial officer in July 2011. He has 35 years’ experience in the management and operations of energy and oil and gas companies. Prior to coming to Recovery Energy, he served as an officer of Applied Natural Gas Fuels, Inc., serving from September 2009 to May 2010 as vice-president—special projects, and from May 2010 through June 2011 as chief financial officer. From April 2007 through September 2009, Mr. Gabbard provided management and financial consulting services to companies involved in the oil and gas and energy related businesses. From 1991 to April 2007, Mr. Gabbard co-founded and served as chief financial officer, executive vice president and a director of PowerSecure International, Inc. (f/k/a Metretek Technologies, Inc.), a developer of energy and smart grid solutions for electric utilities, and their commercial, institutional, and industrial customers. Mr. Gabbard also serves as a director on the board of ADA. Mr. Gabbard received a bachelor of accountancy degree from the University of Oklahoma in 1977, and is a CPA. When determining Mr. Gabbard’s qualifications to serve as a director of the Company, the Company considered his experience as a senior officer of, and consultant to, several energy companies and his background in financial accounting.
Bruce B. White: Director. Mr. White joined our board in April 2012. He is currently a senior vice president of High Sierra Water Services, LLC and has served in that capacity since the purchase of Conquest Water Services, LLC by High Sierra in June 2011. Mr. White co-founded Conquest Water Services in 1993 and served as a co-managing partner to build that company into a DJ Basin service company. Mr. White has more than 25 years of experience operating in the DJ basin, including exploration, drilling, development and other well operations, many of which were conducted through Conquest Oil Company, founded by White in 1984 which he continues to serve as president. White served as the Chairman of the University of Northern Colorado Foundation in 2003. White was also a founding member of the Denver Julesburg Petroleum Association, the predecessor to the Colorado Oil and Gas Association (COGA), and served as its president during 1987 and 1988. A veteran of the Vietnam War, Mr. White served in the Navy for six years; he attended Grossmont College in El Cajon, California but does not hold a degree from there. When determining Mr. White’s qualifications to serve as a director of the Company, the Company considered his leadership experience as founder of Conquest Oil Company and Conquest Water Services and Senior Vice President of High Sierra Water Services, as well as his industry experience, including extensive experience in oil and gas development and services industries at the entities and in the capacities described above.
D. Kirk Edwards: Director. Mr. Edwards became president of Las Colinas Energy Partners, LP and four affiliated entities in March, 2012, where he manages a diverse oil and gas royalty base, surface lands, and non-operated working interests in more than 9,000 wells located throughout the U.S. and the Gulf Coast of Mexico. He has served as president for the following oil and gas companies for more than five years: MacLondon Royalty Company (and four affiliates), Alexis Energy GP, LP, and Noelle Land & Minerals LLC. Mr. Edwards worked in various disciplines as a petroleum engineer including Field, Reservoir, and drilling engineer for Texaco, Inc. from 1981-1986. In 1987, he founded Odessa Exploration, Inc., an independent oil and gas company, which he sold to Key Energy Services, Inc. in 1993. He served as a director, executive vice president and in other capacities of Key Energy Services until 2001. Mr. Edwards is a past president of the Permian Basin Petroleum Association, and is a past director and former chairman of the board of the Federal Reserve Bank of Dallas’ El Paso Branch. Mr. Edwards received a Bachelor of Science degree in Chemical Engineering from the University of Texas at Austin in 1981, and is a registered Professional Engineer in the State of Texas. When determining Mr. Edwards’s qualifications to serve as a director of the Company, the Company considered his experience running numerous oil and gas companies and his extensive business knowledge working with other companies in the energy industry.
Compensation of Directors
The table below sets forth the compensation earned by our non-employee directors during the 2012 fiscal year. There were no non-equity incentive plan compensation, stock options, change in pension value or any non-qualifying deferred compensation earnings during the 2012 fiscal year. All amounts are in dollars.
Name
|
|
Fees Earned or
Paid in Cash
Compensation
|
|
|
Stock Awards
|
|
|
All Other
Compensation
|
|
|
Total
|
|
Timothy N. Poster
|
|
$
|
40,000.00
|
|
|
$
|
40,000.00
|
|
|
$
|
0.00
|
|
|
$
|
80,000.00
|
|
W. Phillip Marcum (1)
|
|
$
|
42,500.00
|
|
|
$
|
150,000.00
|
|
|
$
|
0.00
|
|
|
$
|
192,500.00
|
|
D. Kirk Edwards
|
|
$
|
24,835.16
|
|
|
$
|
150,000.00
|
|
|
$
|
0.00
|
|
|
$
|
174,835.16
|
|
Bruce B. White
|
|
$
|
27,472.52
|
|
|
$
|
150,000.00
|
|
|
$
|
0.00
|
|
|
$
|
177,472.52
|
|
Conway J. Schatz (2)
|
|
$
|
5,000.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
5,000.00
|
|
(1) Mr. Marcum ceased being a non-employee director when he was appointed chief executive officer on November 15, 2012.
(2) Mr. Schatz resigned as a director to pursue other professional and career obligations on January 31, 2012.
We currently pay each of our non-employee directors annual cash compensation of $40,000 ($10,000 per quarter), and annual equity compensation in common shares equal to $40,000 (payable on each anniversary of their initial appointment) at the then current fair market value of our shares. We pay additional cash compensation of $10,000 per year (payable quarterly) to the chairman of our audit and compensation committees. Mr. Poster currently serves as chair of our compensation committee, and Mr. Marcum served as chair of our audit committee until he was appointed an executive officer of the Company on November 15, 2012.
In May 2010 we granted Mr. Poster 125,000 shares of our common stock, 50% of which vested on January 1, 2011 and the other 50% of which will vest on January 1, 2012. In April 2012 we granted Mr. Marcum and Mr. White 50,000 shares of our common stock for their service as directors. The shares vest in equal amounts on the first, second and third anniversaries of the date of their initial appointment to the board (September 9, 2011 for Mr. Marcum and April 24, 2012 for Mr. White). We also made an additional grant of 13,115 to Mr. Poster in April 2012 in accordance with his independent director agreement. In May 2012, when Mr. Edwards joined the board, we granted him 50,000 shares subject to vesting on the first, second and third anniversaries of the date of his initial appointment to the board (May 18, 2012).
We have entered into independent director agreements with our non-employee directors. These agreements provide that the shares granted to a director fully vest upon a change of control or termination of the director's services as a director by Recovery Energy other than for cause. The agreements permit a director to engage in other business activities in the energy industry, some of which may be in conflict with the best interests of Recovery Energy, and also states that if a director becomes aware of a business opportunity, he has no affirmative duty to present or make such opportunity available to us.
Executive Compensation for Fiscal Year 2012
The compensation earned by our executive officers for fiscal 2012 consisted of base salary and long-term incentive compensation consisting of awards of stock grants.
Summary Compensation Table
The table below sets forth compensation paid to our executive officers for the 2012 and 2011 fiscal years.
Name and
Principal Position
|
|
Year
|
|
Salary
|
|
|
Bonus
|
|
|
Stock Awards
|
|
|
Other Compensation
|
|
|
Total
|
|
Roger A. Parker
|
|
2012
|
|
$
|
217,700
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
141,903
|
(1)
|
|
$
|
359,603
|
|
(chief executive officer May 1, 2010 – November 15, 2012)(3)
|
|
2011
|
|
$
|
240,000
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
110,000
|
(2)
|
|
$
|
350,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A. Bradley Gabbard
|
|
2012
|
|
$
|
182,146
|
|
|
$
|
-
|
|
|
$
|
97,689
|
(4)
|
|
$
|
5,275
|
(5)
|
|
$
|
285,110
|
|
(chief financial officer since July 12, 2011; president since November 15, 2012)
|
|
2011
|
|
$
|
84,000
|
|
|
$
|
-
|
|
|
$
|
166,000
|
(6)
|
|
$
|
-
|
|
|
$
|
250,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jeffrey A. Beunier
|
|
2012
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
70,459
|
(7)
|
|
$
|
-
|
|
(president and chief financial officer from May 1, 2010 to April 11, 2011)(8)
|
|
2011
|
|
$
|
225,000
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
12,000
|
(5)
|
|
$
|
237,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
W. Phillip Marcum
(chief executive officer since November 15, 2012)(9)
|
|
2012
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
(1)
|
Reflects (a) $21,400 in vacation pay paid upon termination, (b) $21,400 in severance payments, (c) $16,603 in reimbursement of health insurance premiums, and (d) $82,500 of expense reimbursement pursuant to Mr. Parker's employment agreement.
|
(2)
|
Reflects payment of $90,000 of expense reimbursement pursuant to Mr. Parker's employment agreement and $20,000 in reimbursement of health insurance premiums.
|
(3)
|
Mr. Parker retired as an executive officer of the Company on November 15, 2012.
|
(4)
|
Mr. Gabbard was granted 26,042 shares of our common stock on November 23, 2012 at a cost basis of $1.78 per share and 29,167 shares of our common stock on November 30, 2012 at a cost basis of $1.76 per share.
|
(5)
|
Reflects reimbursement of health insurance premiums.
|
(6)
|
Mr. Gabbard was granted 100,000 shares of our common stock in 2011 as compensation. We recognized $166,000 of compensation expense in 2011 for these shares.
|
(7)
|
Mr. Beunier resigned as an executive officer of the Company to pursue other professional and career obligations on April 11, 2011.
|
(8)
|
Reflects $65,625 in severance payments and $4,834 in continuing health insurance benefits.
|
(9)
|
As of December 31, 2012, Mr. Marcum had not received any stock or cash compensation as an officer of the Company.
|
Outstanding Equity Awards at Fiscal Year-End
|
|
Stock Awards
|
|
Name
|
|
Number of shares or units of stock that have
not vested
(#)
|
|
|
Market value of shares
of units of stock that have not
vested
($)
|
|
|
Equity incentive plan awards: Number of unearned shares, units or other rights
that have not vested
(#)
|
|
|
Equity incentive plan awards: Market or payout value of unearned shares, units or other rights
that have not vested
($)
|
|
Roger A. Parker
|
|
|
1,350,000 |
|
|
|
2,686,500 |
|
|
|
0 |
|
|
|
0 |
|
A. Bradley Gabbard
|
|
|
107,292 |
|
|
|
213,511 |
|
|
|
0 |
|
|
|
0 |
|
There were no outstanding option awards at December 31, 2012.
The Board of Directors and Committees Thereof
Our board of directors conducts its business through meetings and through its committees. Our board of directors held 10 meetings in 2012, which all directors attended. Our policy regarding directors’ attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances.
Affirmative Determinations Regarding Director Independence and Other Matters
Our board of directors follows the standards of independence established under the Nasdaq rules in determining if directors are independent and has determined that three of our current directors, Timothy N. Poster, D. Kirk Edwards and Bruce B. White are “independent directors” under those rules. W. Phillip Marcum was an “independent director” prior to his appointment in November 2012 as our chief executive officer. No independent director receives, or has received, any fees or compensation from us other than compensation received in his or her capacity as a director. There were no transactions, relationships or arrangements not otherwise disclosed that were considered by the board of directors in determining that any of the directors are independent.
Committees of the Board of Directors
Pursuant to our amended and restated bylaws, our board of directors is permitted to establish committees from time to time as it deems appropriate. To facilitate independent director review and to make the most effective use of our directors’ time and capabilities, our board of directors has established an audit committee and a compensation committee. The membership and function of these committees are described below.
Compensation Committee
Our compensation committee currently consists of Mr. Edwards, Mr. Poster and Mr. White. Mr. Poster is chair of the compensation committee. The compensation committee did not meet during 2012, but acted by written consent. The compensation committee reviews, approves and modifies our executive compensation programs, plans and awards provided to our directors, executive officers and key associates. The compensation committee also reviews and approves short-term and long-term incentive plans and other stock or stock-based incentive plans. In addition, the committee reviews our compensation and benefit philosophy, plans and programs on an as-needed basis. In reviewing our compensation and benefits policies, the compensation committee may consider the recruitment, development, promotion, retention, compensation of executive and senior officers of Recovery Energy, trends in management compensation and any other factors that it deems appropriate. The compensation committee may engage consultants in determining or recommending the amount of compensation paid to our directors and executive officer. The compensation committee is governed by a written charter that will be reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.recoveryenergyco.com under “Investor Relations.”
Compensation Committee Interlocks and Insider Participation
None of the members of the compensation committee is or has been an officer or employee of the Company. None of our executive officers currently serves or has served on the compensation committee (or other board committee performing equivalent functions or, in the absence of any such committee, the entire board of directors) or as a director of another entity, one of whose executive officer serves or served as one of our directors or on our compensation committee.
Audit Committee
Our audit committee currently consists of Mr. Edwards, Mr. Poster and Mr. White. Prior to Mr. Marcum’s appointment in November 2012 as our chief executive officer, he served as chair of our audit committee and met the Securities and Exchange Commission's definition of an audit committee financial expert. The Company is currently conducting a search for a new independent director to replace Mr. Marcum as audit committee financial expert. The audit committee is governed by a written charter that will be reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.recoveryenergyco.com under “Investor Relations.”
Communications with the Board of Directors
Stockholders may communicate with our board of directors or any of the directors by sending written communications addressed to the board of directors or any of the directors, Recovery Energy, Inc., 1900 Grant Street, Suite #720, Denver, CO 80203, Attention: Corporate Secretary. All communications are compiled by the corporate secretary and forwarded to the board or the individual director(s) accordingly.
Nomination of Directors
Our board of directors has not established a nominating committee because the board believes that it is unnecessary in light of the board’s small size. In the event that vacancies on our board of directors arise, the board considers potential candidates for director, which may come to the attention of the board through current directors, professional executive search firms, stockholders or other persons. Our board does not set specific, minimum qualifications that nominees must meet in order to be recommended as directors, but rather believes that each nominee should be evaluated based on his or her individual merits, taking into account the needs of Recovery and the composition of our board. We do not have any formal policy regarding diversity in identifying nominees for a directorship, but rather consider it among the various factors relevant to any particular nominee. In the event we decide to fill a vacancy that exists or we decide to increase the size of the board, we identify, interview and examine appropriate candidates. We identify potential candidates principally through suggestions from our board and senior management. Our chief executive officer and board members may also seek candidates through informal discussions with third parties. We also consider candidates recommended or suggested by stockholders.
The board will consider candidates recommended by stockholders if the names and qualifications of such candidates are submitted in writing in accordance with the notice provisions for stockholder proposals set forth under the caption “General Information — Next Annual Meeting of Stockholders” in this prospectus to our corporate secretary, Recovery Energy, Inc., 1900 Grant Street, Suite #720, Denver, CO 80203, Attention: Corporate Secretary. The board considers properly submitted stockholder nominations for candidates for the board of directors in the same manner as it evaluates other nominees. Following verification of the stockholder status of persons proposing candidates, recommendations are aggregated and considered by the board and the materials provided by a stockholder to the corporate secretary for consideration of a nominee for director are forwarded to the board. All candidates are evaluated at meetings of the board. In evaluating such nominations, the board seeks to achieve the appropriate balance of industry and business knowledge and experience in light of the function and needs of the board of directors. The board considers candidates with excellent decision-making ability, business experience, personal integrity and reputation. Our management recommended our incumbent directors for election at our 2012 annual meeting. We did not receive any other director nominations.
Code of Conduct
Our board of directors has adopted a code of conduct that applies to all of our officers and employees, including our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. Our code of conduct codifies the business and ethical principles that govern all aspects of our business. A copy of our code of conduct is available on our website at www.recoveryenergyco.com under “Investor Relations” and “Corporate Governance.” We undertake to provide a copy of our code of conduct to any person, at no charge, upon a written request. All written requests should be directed to: Recovery Energy, Inc., 1900 Grant Street, Suite #720, Denver, CO 80203, Attention: Corporate Secretary.
Board Leadership Structure
The board’s current leadership structure does not separate the positions of chairman and principal executive officer. The board has determined our leadership structure based on factors such as the experience of the applicable individuals, the current business and financial environment faced by Recovery, particularly in view of its financial condition and industry conditions generally and other relevant factors. After considering these factors, we determined that not separating the positions of chairman of the board and principal executive officer is the appropriate leadership structure at this time. The board, through the chairman and the chief executive officer, is currently responsible for the strategic direction of the company. The chief executive officer is currently responsible for the day to day operation and performance of the company. The board feels that this provides an appropriate balance of strategic direction, operational focus, flexibility and oversight.
The Board’s Role in Risk Oversight
It is management’s responsibility to manage risk and bring to the board's attention any material risks to the company. The board has oversight responsibility for Recovery's risk policies and processes relating to the financial statements and financial reporting processes and the guidelines, policies and processes for mitigating those risks.
Employment Agreements and Other Compensation Arrangements
Until his resignation in November 2012, we had an employment agreement with Mr. Parker. Under his employment agreement Mr. Parker received an annual base salary of $240,000 and was eligible for an annual cash bonus based on performance goals that included targets related to earnings before interest taxes, depreciation and amortization, hydrocarbon production level, and hydrocarbon reserve amounts, with a targeted bonus of no less than $100,000 (with board approval). Mr. Parker also received a monthly, non-accountable expense reimbursement of $7,500 for expenses related to company business. Mr. Parker received grants totaling 1,375,000 shares of our common stock, 100,000 of which vested on January 1, 2011. Pursuant to the terms of the severance agreement we entered into with Mr. Parker on November 15, 2012, the remainder of Mr. Parker’s outstanding restricted stock will vest in two equal installations, one on May 15, 2013 and one on November 15, 2013.
In 2012, Mr. Gabbard received an annual salary of $187,250, and was granted 104,167 shares of our common stock, 26,042 shares of which vested immediately and 78,125 shares of which vest annually over three years beginning on November 23, 2013.
The compensation committee is currently negotiating compensation arrangements with Mr. Marcum and Mr. Gabbard. Although final agreements have not been completed, the general terms of these arrangements are expected to be as follows:
Each of Mr. Marcum and Mr. Gabbard will receive an annual salary of $220,000. Each executive will be eligible for a performance bonus in an amount up to 50% of annual base compensation payable on an annual basis and subject to determination by the compensation committee of the Board, based on the achievement by the Company of performance goals established by the compensation committee for the preceding fiscal year, which may include targets related to the Company’s earnings before interest, taxes, depreciation and amortization, hydrocarbon production level, and hydrocarbon reserve amounts. Each executive will also receive an incentive grant of 300,000 stock options with a fair market value vesting price, with vesting occurring 33.33% on each of the next three anniversaries of the grant date. Such stock options will vest 100% upon a termination of employment by the Company without cause, by the executive for good reason, upon a change of control of the Company or upon the death or disability of the executive. Upon a termination due to death or disability, a termination initiated by the executive for any reason except for good reason, or a termination initiated by the Company with cause, the Company’s obligation to pay any compensation or benefits ceases on the separation date. If the separation is initiated by the executive for good reason or by the Company for any reason other than cause, the Company will continue to pay the executive’s monthly salary as then in effect for a period equal to twelve (12) months commencing on the separation date.
Compensation Discussion and Analysis
Overview
The following Compensation Discussion and Analysis describes the material elements of compensation for the named executive officers identified in the Summary Compensation Table above. As more fully described below, the compensation committee reviews and recommends to the full board of directors the total direct compensation programs for our named executive officers. Our chief executive officer also reviews the base salary, annual bonus and long-term compensation levels for the other named executive officers.
Compensation Philosophy and Objectives
Our compensation philosophy has been to encourage growth in our oil and natural gas reserves and production, encourage growth in cash flow, and enhance stockholder value through the creation and maintenance of compensation opportunities that attract and retain highly qualified executive officers. To achieve these goals, the compensation committee believes that the compensation of executive officers should reflect the growth and entrepreneurial environment that has characterized our industry in the past, while ensuring fairness among the executive management team by recognizing the contributions each individual executive makes to our success.
Based on these objectives, the compensation committee has recommended an executive compensation program that includes the following components:
|
●
|
a base salary at a level that is competitive with the base salaries being paid by other oil and natural gas exploration and production enterprises that have some characteristics similar to Recovery and could compete with Recovery for executive officer level employees;
|
|
●
|
annual incentive compensation to reward achievement of Recovery's objectives, individual responsibility and productivity, high quality work, reserve growth, performance and profitability and that is competitive with that provided by other oil and natural gas exploration and production enterprises that have some characteristics similar to Recovery; and
|
|
|
|
|
●
|
long-term incentive compensation in the form of stock-based awards that is competitive with that provided by other oil and natural gas exploration and production enterprises that have some characteristics similar to Recovery.
|
As described below, the compensation committee periodically reviews data about the compensation of executives in the oil and gas industry. Based on these reviews, we believe that the elements of our executive compensation program have been comparable to those offered by our industry competitors.
Elements of Recovery’s Compensation Program
The three principal components of Recovery’s compensation program for its executive officers, base salary, annual incentive compensation and long-term incentive compensation in the form of stock-based awards, are discussed below.
Base Salary. Base salaries (paid in cash) for our executive officers have been established based on the scope of their responsibilities, taking into account competitive market compensation paid by the peer companies for similar positions. We have reviewed our executives’ base salaries in comparison to salaries for executives in similar positions and with similar responsibilities at companies that have certain characteristics similar to Recovery. Base salaries are reviewed annually, and typically are adjusted from time to time to realign salaries with market levels after taking into account individual responsibilities, performance, experience and other criteria.
The compensation committee reviews with the chief executive officer his recommendations for base salaries for the named executive officers, other than himself, each year. New base salary amounts have historically been based on an evaluation of individual performance and expected future contributions to ensure competitive compensation against the external market, including the companies in our industry with which we compete. The compensation committee has targeted base salaries for executive officers, including the chief executive officer, to be competitive with the base salaries being paid by other oil and natural gas exploration and production enterprises that have some characteristics similar to Recovery. We believe this is critical to our ability to attract and retain top level talent.
Long Term Incentive Compensation. We believe the use of stock-based awards creates an ownership culture that encourages the long-term performance of our executive officers. Each of our named executive officers received a stock grant upon becoming an employee of Recovery. These grants vest over time.
Other Benefits. All employees may participate in our 401(k) retirement savings plan, or 401(k) plan. Each employee may make before tax contributions in accordance with the Internal Revenue Service limits. We provide this 401(k) plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. We make a matching contribution in an amount equal to 100% of the employee’s elective deferral contribution below 3% of the employee’s compensation and 50% of the employee’s elective deferral that exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’s compensation.
All fulltime employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, dental and vision care coverage, disability insurance and life insurance.
Indemnification of Directors and Officers
Pursuant to our certificate of incorporation we provide indemnification of our directors and officers to the fullest extent permitted under Nevada law. We believe that this indemnification is necessary to attract and retain qualified directors and officers.
Narrative Disclosure of Compensation Policies and Practices as they Relate to Risk Management
In accordance with the requirements of Regulation S-K, Item 402(e), to the extent that risks may arise from our compensating policies and practices that are reasonably likely to have a material adverse effect on Recovery, we are required to discuss these policies and practices for compensating our employees (including employees that are not named executive officers) as they relate to our risk management practices and the possibility of incentivizing risk-taking. We have determined that the compensation policies and practices established with respect to our employees are not reasonably likely to have a material adverse effect on Recovery and, therefore, no such disclosure is necessary. The compensation committee and the board for directors are aware of the need to routinely assess our compensation policies and practices and will make a determination as to the necessity of this particular disclosure on an annual basis.
During fiscal year 2010 through the date of this prospectus, we have engaged in the following transactions with related parties:
Edward Mike Davis. We have acquired most of our oil and gas properties from Edward Mike Davis, L.L.C. and Spottie, Inc., both owned by Edward Mike Davis. We paid for these acquisitions in a combination of cash and stock. As a result of these transactions, the Davis entities received an aggregate of 3,291,667 shares of our common stock. As of December 31, 2012, Davis had sold substantially all of his Recovery stock. The Davis entities were not a related party prior to these transactions. The specific transactions with the Davis entities are:
●
|
The Wilke Field acquisition agreement entered into in December 2009 did not close. The agreement provided for a purchase price of $2,200,000 and 387,500 shares of common stock. 362,500 shares were given as a non-refundable deposit.
|
●
|
The Wilke Field acquired in January 2010, for $4,500,000 in cash effective as of January 1, 2010. Included in the acquisition were seven producing wells and a 50% working interest in two development prospects located in Nebraska and Colorado.
|
●
|
The Albin Field acquired in March 2010, for $6,000,000 cash and 137,500 shares of our common stock which we valued at approximately $412,500. Included in the acquisition were four producing wells.
|
●
|
The State Line Field acquired in April 2010, for $15,000,000 cash and 625,000 shares of our common stock which we valued at approximately $1,875,000. Included in the acquisition were six producing wells and interests in 1240 acres.
|
●
|
Approximately 60,000 acres located in Banner and Kimball Counties, Nebraska and Laramie and Goshen Counties, Wyoming acquired in May, 2010 for $20,000,000 cash and 500,000 shares of our common stock which we valued at $1,500,000.
|
●
|
Approximately 33,800 net acres located in Laramie County and Goshen County, Wyoming, and Banner County, Kimball County, and Scotts Bluff County, Nebraska, and rights below the base of the Greenhorn on approximately 23,000 net acres in Laramie County and Goshen County, Wyoming, and Banner County and Kimball County, Nebraska, acquired in December, 2010. These properties were undeveloped with no proved reserves or production. The purchase price was $8,000,000 in cash which was due to the sellers on or before December 20, 2010. We issued 1,666,667 shares of our common stock as security against the cash payment, which were to be returned to us upon the cash payment. We did not make the cash payment and the Davis entities kept the 1,666,667 shares of common stock.
|
●
|
In November 2010, we completed a well located on a 640 acre oil and gas lease in Arapahoe County, Colorado known as Comanche Creek. We acquired 50% interests in this prospect and the Omega prospect in January 2010 from the Davis entities as part of the Wilke acquisition. We acquired an additional 12.5% working interest in the Comanche Creek prospect in June 2010 from Davis in exchange for a 1% overriding royalty interest on our existing 50% working interest, resulting in us owning a 62.5% working interest. The remaining 37.5% working interest is split between Davis and Timothy N. Poster, a member of our board of directors, with Davis holding 12.5% and Mr. Poster holding 25% of the working interest. The operations of the well are covered by a joint operating agreement and will require both Davis and Mr. Poster to pay their proportionate share of operating costs as well as an overhead/operating fee to us.
|
Hexagon, LLC. We financed several of our acquisitions with loans from Hexagon, LLC. Hexagon has the right to designate one member of our board of directors pursuant to a stockholders agreement. Conway Schatz, who resigned from our board in January 2012, was designated by Hexagon. Hexagon has not designated a replacement for Mr. Schatz. Hexagon was not a related party prior to these loans. The specific transactions with Hexagon are:
●
|
$4,500,000 loan in January 2010, to finance the purchase of the Wilke Field properties. The loan bears annual interest of 15%, will mature on June 30, 2013 and is secured by mortgages on the Wilke Field properties. Hexagon received 62,500 shares of our common stock in connection with the financing which we valued at approximately $2,250,000.
|
·
|
$6,000,000 loan in March 2010, to finance the cash portion of the purchase price for the Albin Field properties. The loan bears annual interest of 15%, will mature on June 30, 2013 and is secured by mortgages on the Albin Field properties. In connection with the financing Hexagon received 46,875 shares of our common stock which we valued at approximately $562,500 and a one-half percent overriding royalty in the leases and wells acquired which we valued at $175,322.
|
·
|
$15,000,000 loan in April 2010, to finance the cash portion of the purchase price for the Laramie County, Wyoming purchases. The loan bears annual interest of 15%, will mature on June 30, 2013 and is secured by a mortgage on the acquired property. In connection with the financing Hexagon received 203,125 shares of our common stock which we valued at approximately $2,437,500, a warrant to purchase 125,000 shares of our common stock exercisable at $10.00 per share which we valued at approximately $184,589 and a one percent overriding royalty in the leases and wells acquired which we valued at $184,589.
|
·
|
In connection with the May 2010, acquisition of 60,000 acres from the Davis entities, we issued Hexagon Investments a five year warrant to purchase 62,500 shares of our common stock at $6.00 per share which we valued at approximately $369,153 as compensation for amendments to our credit agreements and agreed that if the loans were not repaid in full on or before January 1, 2011 we would issue Hexagon Investments a second five year warrant to purchase 62,500 shares of our common stock at $6.00 per share The loans remain outstanding, on January 1, 2011 and the warrant was issued to Hexagon which we valued at approximately $1,049,095.
|
·
|
In November 2010, we entered into a Put Option Agreement with Grandhaven Energy, LLC whereby Grandhaven Energy has the right to require us to purchase for up to $2,400,000 25% of certain overriding royalty interests in undeveloped oil and gas leasehold in Laramie County it and several other purchasers acquired from the Davis entities. The put option was exercisable until March 31, 2011 and expired unexercised. Grandhaven Energy is an affiliate of Hexagon.
|
·
|
In December 2010, the maturity date of the Hexagon loans was extended to September 1, 2012, and in November 2011 the maturity date of the Hexagon loans was extended to January 1, 2013. We did not pay any consideration for the extension.
|
·
|
In November 2011 Hexagon loaned us $309,000 which was repaid in February 2012.
|
·
|
In March 2012 the maturity date of the Hexagon loans was extended to June 30, 2013 and in connection therewith we agreed to make minimum monthly note payments of $325,000.
|
Convertible Debentures. The Steven B. Dunn and Laura Dunn Revocable Trust and Wallington Investment Holdings, Ltd., each of whom owns more than 5% of our outstanding common stock, hold $2,000,000 and $4,110,000 respectively, aggregate principal amount of our outstanding Debentures.
T.R. Winston
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.
In December 2011, we issued 1,500,000 unregistered shares of our common stock to TRW Exploration, LLC to purchase oil and gas interests in 15,644 gross, 2,400 net acres in the Chugwater prospect located in Laramie County, Wyoming, including two horizontal wells drilled in that prospect and mutual releases in connection with termination of a joint venture with TRW Exploration. Our board of directors approved the transaction which closed in December, 2011. TRW Exploration was majority owned by several of our shareholders, at least one of whom owned more than 5% of our outstanding common stock at the time the shares were issued.
Under the December 2010 joint venture agreement, TRW Exploration paid us $2,000,000 for the purchase of an interest in the 2,400 net acres and also agreed to pay $7,100,000 of the drilling and completion costs of two horizontal wells to be drilled on the acreage in order to earn a 60% working interest in each well. These two wells were drilled and completed in 2011 and are currently being evaluated as to their potential to sustain commercial production. In addition to the $2,000,000 initial payment, TRW paid $7,100,000 of the drilling and completion costs of the two wells. Upon termination of the joint venture, TRW sold back its interest in the wells along with all of its rights to the undeveloped acreage in consideration for the issuance by the Company of 1,500,000 shares of unregistered common stock that we valued at $4,875,000 and the mutual releases.
Conflict of Interest Policy
We have a corporate conflict of interest policy that prohibits conflicts of interests unless approved by the board of directors. Our board of directors has established a course of conduct whereby it considers in each case whether the proposed transaction is on terms as favorable or more to the Company than would be available from a non-related party. Our board also looks at whether the transaction is fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Each of the related party transactions was presented to our board of directors for consideration and each of these transactions was unanimously approved by our board of directors after reviewing the criteria set forth in the preceding two sentences. Each of our purchases from Davis was individually negotiated, and none of the transactions was contingent upon or otherwise related to any other transaction.
The following table sets forth certain information with respect to beneficial ownership of our common stock as of January 18, 2013 by each of our executive officers and directors and each person known to be the beneficial owner of 5% or more of the outstanding common stock. This table is based upon the total number of shares outstanding as of January 18, 2013 of 18,361,220. Unless otherwise indicated, the persons and entities named in the table have sole voting and sole investment power with respect to the shares set forth opposite the stockholder’s name, subject to community property laws, where applicable. Beneficial ownership is determined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended. In computing the number of shares beneficially owned by a person or a group and the percentage ownership of that person or group, shares of our common stock subject to options or warrants currently exercisable or exercisable within 60 days after the date hereof are deemed outstanding, but are not deemed outstanding for the purpose of computing the percentage ownership of any other person. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Recovery Energy, 1900 Grant Street, Suite #720, Denver, CO 80203.
Name and Address of Beneficial Owner
|
|
Beneficially
Owned
|
|
|
Percent of
Class Beneficially
Owned
|
|
Directors and Executive Officers
|
|
|
|
|
|
|
|
|
|
|
|
|
|
W. Phillip Marcum, Chief Executive Officer and Chairman of Board of Directors
|
|
|
128,096
|
(1)
|
|
|
0.70
|
%
|
|
|
|
|
|
|
|
|
|
A. Bradley Gabbard, President and Chief Financial Officer
|
|
|
100,375
|
(2)
|
|
|
0.55
|
%
|
|
|
|
|
|
|
|
|
|
Timothy N. Poster, Director
|
|
|
164,440
|
|
|
|
0.90
|
%
|
|
|
|
|
|
|
|
|
|
Bruce White, Director
|
|
|
100,000
|
(3)
|
|
|
0.55
|
%
|
|
|
|
|
|
|
|
|
|
D. Kirk Edwards, Director
|
|
|
132,627
|
(3)
|
|
|
0.72
|
%
|
|
|
|
|
|
|
|
|
|
Officers and directors as a group (six persons)
|
|
|
629,705
|
(4)
|
|
|
3.43
|
%
|
|
|
|
|
|
|
|
|
|
Roger A. Parker
|
|
|
25,000
|
(5)
|
|
|
0.14
|
%
|
|
|
|
|
|
|
|
|
|
Hexagon Investments, LLC
|
|
|
2,675,000
|
(6)
|
|
|
13.82
|
%
|
|
|
|
|
|
|
|
|
|
Labyrinth Enterprises LLC
|
|
|
2,675,000
|
(6)
|
|
|
13.82
|
%
|
|
|
|
|
|
|
|
|
|
Reiman Foundation
|
|
|
2,675,000
|
(6)
|
|
|
13.82
|
%
|
|
|
|
|
|
|
|
|
|
Scott J. Reiman
|
|
|
2,675,000
|
(6)
|
|
|
13.82
|
%
|
|
|
|
|
|
|
|
|
|
Steven B. Dunn and Laura Dunn Revocable Trust
|
|
|
1,293,546
|
(7)
|
|
|
6.78
|
%
|
|
|
|
|
|
|
|
|
|
J. Steven Emerson
|
|
|
1,261,657
|
(8)
|
|
|
6.87
|
%
|
|
|
|
|
|
|
|
|
|
Wallington Investment Holdings, Ltd
|
|
|
1,733,432
|
(9)
|
|
|
8.44
|
%
|
(1)
|
|
Does not include 33,333 shares of restricted stock subject to vesting, which will not vest within 60 days after the date hereof.
|
(2)
|
|
Does not include 107,292 shares of restricted stock subject to vesting, which will not vest within 60 days after the date hereof.
|
(3)
|
|
Does not include 50,000 shares of restricted stock subject to vesting, which will not vest within 60 days after the date hereof.
|
(4)
|
|
Does not include 278,125 shares of restricted stock subject to vesting, which will not vest within 60 days after the date hereof.
|
(5)
|
|
Does not include 1,350,000 shares of restricted stock subject to vesting, which will not vest within 60 days after the date hereof.
|
(6)
|
|
Includes (i) 1,250,000 shares owned by Hexagon, LLC, (ii) 1,000,000 shares underlying warrants held by Hexagon, (iii) 129,008 shares owned by Labyrinth Enterprises LLC, which is controlled by Scott J. Reiman, (iv) 245,992 shares owned by Reiman Foundation, which is controlled by Scott J. Reiman and (v) 50,000 shares owned by Scott J. Reiman. Mr. Reiman is President of Hexagon Investments. Based on a Schedule 13D filed on December 13, 2012.
|
(7)
|
|
Includes (i) 1,119,628 shares owned by Steven B. Dunn and Laura Dunn Revocable Trust (including 258,350 restricted shares), (ii) 86,959 shares owned by Beau 8, LLC, and (iii) 86,959 shares owned by Winston 8, LLC. Does not 713,242 shares issuable upon conversion of convertible securities, because such shares are not issuable within 60 days after the date hereof. Steven B. Dunn and Laura Dunn, mailing address is 16689 Schoenborn Street, North Hills, CA 91343, are trustees of the Trust and also share voting and dispositive power with respect to the shares owned by the LLCs. Based on information received from a representative of Steven B. Dunn and Laura Dunn.
|
(8)
|
|
Includes (i) 710,000 shares owned by J. Steven Emerson Roth IRA, (ii) 236,657 shares owned by J. Steven Emerson IRA R/O II, (iii) 105,000 shares owned by Emerson Partners, (iv) 150,000 shares owned by J. Steven Emerson and (v) 60,000 shares owned by Emerson Family Foundation. J. Steven Emerson controls each of these entities. Based on information received from a representative of J. Steven Emerson.
|
(9)
|
|
Does not include 2,185,880 shares issuable upon conversion of convertible securities, because such shares are not issuable within 60 days after the date hereof. Based on information received from a representative of Wallington Investment Holdings, Ltd.
|
DISCLOSURE OF COMMISSION POSITION ON INDEMNIFICATION FOR SECURITIES ACT LIABILITY
Indemnification
Our director and officer are indemnified as provided by the Nevada Revised Statutes and our Bylaws. We have agreed to indemnify each of our directors and certain officers against certain liabilities, including liabilities under the Securities Act. Insofar as indemnification for liabilities arising under the Securities Act may be permitted to our directors, officers and controlling persons pursuant to the provisions described above, or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than our payment of expenses incurred or paid by our director, officer or controlling person in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
At present, there is no pending litigation or proceeding involving any of our directors, officers, employees or agents where indemnification will be required or permitted. We are not aware of any threatened litigation or proceeding that might result in a claim for such indemnification.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling Recovery Energy, we have been informed that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. No dealer, sales person or any other person has been authorized in connection with this offering to give any information or to make any representations other than those contained in this prospectus and, if given or made, such information or representations must not be relied upon as having been authorized by us. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any of the securities offered hereby in any jurisdiction in which such offer or solicitation is not authorized or in which the person making such offer or solicitation is not qualified to do so or to any person to whom it is unlawful to make such an offer or solicitation. Neither the delivery of this prospectus nor any sale made hereunder shall, under any circumstances, create an implication that there has been no change in the circumstances of Recovery Energy or the facts herein set forth since the date hereof.
Davis Graham & Stubbs LLP will pass upon the validity of the common stock on our behalf.
We have filed with the SEC a registration statement on Form S-1 with respect to the common stock offered by this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all the information set forth in the registration statement or the exhibits and schedules that are part of the registration statement. Statements made in this prospectus regarding the contents of any contract or other documents are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. In addition, we are required to file periodic and current reports and other information with the SEC by reason of the registration of our senior notes under the Securities Act. For further information pertaining to us and to the common stock offered by this prospectus, reference is made to the registration statement and those periodic and current reports, including the exhibits and schedules thereto, copies of which may be inspected without charge at the Public Reference Room of the SEC at 100 F Street N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for information regarding the operation of the Public Reference Room. In addition, the SEC maintains a web site that contains reports, proxy and information statements and other information that is filed electronically with the SEC. The web site can be accessed at www.sec.gov.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Recovery Energy, Inc.
We have audited the accompanying consolidated balance sheets of Recovery Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the years ended December 31, 2011 and 2010 and for the period from March 6, 2009 (inception) through December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Recovery Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for the years ended December 31, 2011 and 2010, and for the period from March 6, 2009 (inception) through December 31, 2009, in conformity with U.S. generally accepted accounting principles.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Recovery Energy, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our report dated March 29, 2012 expressed an opinion that Recovery Energy, Inc. had not maintained effective internal control over financial reporting as of December 31, 2011.
Hein & Associates LLP
Denver, Colorado
March 29, 2012
RECOVERY ENERGY, INC.
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
ASSETS
|
|
Current assets:
|
|
|
|
|
|
|
Cash
|
|
$ |
2,707,722 |
|
|
$ |
5,528,744 |
|
Restricted cash
|
|
|
932,165 |
|
|
|
1,150,541 |
|
Accounts receivable
|
|
|
2,227,466 |
|
|
|
857,554 |
|
Prepaid assets
|
|
|
75,376 |
|
|
|
27,772 |
|
Total current assets
|
|
|
5,942,729 |
|
|
|
7,564,611 |
|
|
|
|
|
|
|
|
|
|
Oil and gas properties (full cost method), at cost:
|
|
|
|
|
|
|
|
|
Unevaluated properties
|
|
|
45,697,481 |
|
|
|
33,605,594 |
|
Evaluated properties
|
|
|
32,113,143 |
|
|
|
26,307,975 |
|
Wells in progress
|
|
|
6,425,509 |
|
|
|
1,219,397 |
|
Total oil and gas properties, at cost
|
|
|
84,236,133 |
|
|
|
61,132,966 |
|
|
|
|
|
|
|
|
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(12,099,098 |
) |
|
|
(5,003,499 |
) |
Net oil and gas properties, at cost
|
|
|
72,137,035 |
|
|
|
56,129,467 |
|
|
|
|
|
|
|
|
|
|
Other assets:
|
|
|
|
|
|
|
|
|
Office equipment, net
|
|
|
106,286 |
|
|
|
51,129 |
|
Prepaid advisory fees
|
|
|
574,160 |
|
|
|
979,449 |
|
Deferred financing costs
|
|
|
2,341,595 |
|
|
|
3,211,566 |
|
Restricted cash and deposits
|
|
|
186,055 |
|
|
|
185,707 |
|
Total other assets
|
|
|
3,208,096 |
|
|
|
4,427,851 |
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$ |
81,287,860 |
|
|
$ |
68,121,929 |
|
The accompanying notes are an integral part of these financial statements.
RECOVERY ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
2,050,768 |
|
|
$ |
968,295 |
|
Commodity price derivative liability
|
|
|
75,609 |
|
|
|
398,840 |
|
Related party payable
|
|
|
16,475 |
|
|
|
11,638 |
|
Accrued expenses
|
|
|
1,354,204 |
|
|
|
1,540,592 |
|
Short-term note
|
|
|
1,150,967 |
|
|
|
208,881 |
|
Total current liabilities
|
|
|
4,648,023 |
|
|
|
3,128,246 |
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
|
612,874 |
|
|
|
507,280 |
|
Term-note payable
|
|
|
20,129,670 |
|
|
|
20,229,801 |
|
Convertible notes payable, net of discount
|
|
|
4,929,068 |
|
|
|
- |
|
Convertible notes conversion derivative liability
|
|
|
1,300,000 |
|
|
|
- |
|
Total long-term liabilities
|
|
|
26,971,612 |
|
|
|
20,737,081 |
|
Total liabilities
|
|
|
31,619,635 |
|
|
|
23,865,327 |
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies – Note 8
|
|
|
- |
|
|
|
- |
|
Preferred stock, 10,000,000 authorized, none issued and outstanding as of December 31, 2011 and 2010.
|
|
|
- |
|
|
|
- |
|
Common stock subject to redemption rights, $0.0001 par value; 0 and 10,625 shares issued and outstanding as of December 31, 2011 and December 31, 2010, respectively
|
|
|
- |
|
|
|
86,257 |
|
Common Stock, $0.0001 par value: 100,000,000 shares authorized; 17,436,825 and 14,453,592 shares issued and outstanding (excluding 0 and 10,625 shares subject to redemption) as of December 31, 2011 and December 31, 2010, respectively
|
|
|
1,744 |
|
|
|
1,445 |
|
Additional paid-in capital
|
|
|
118,146,119 |
|
|
|
93,819,314 |
|
Accumulated deficit
|
|
|
(68,479,638 |
) |
|
|
(49,650,414 |
) |
Total shareholders' equity
|
|
|
49,668,225 |
|
|
|
44,170,345 |
|
Total liabilities and shareholders' equity
|
|
$ |
81,287,860 |
|
|
$ |
68,121,929 |
|
The accompanying notes are an integral part of these financial statements.
RECOVERY ENERGY, INC.
|
|
Year Ended
December 31, 2011
|
|
|
Year Ended
December 31, 2010
|
|
|
March 6, 2009
(Inception) through December 31, 2009
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$ |
7,148,110 |
|
|
$ |
9,504,737 |
|
|
$ |
- |
|
Gas sales
|
|
|
547,190 |
|
|
|
68,075 |
|
|
|
- |
|
Operating fees
|
|
|
117,360 |
|
|
|
13,487 |
|
|
|
- |
|
Realized gain on price hedges
|
|
|
625,043 |
|
|
|
570,233 |
|
|
|
- |
|
Unrealizedlosses price hedges
|
|
|
(75,609 |
) |
|
|
(398,840 |
) |
|
|
- |
|
Total revenues
|
|
|
8,362,094 |
|
|
|
9,757,692 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
1,514,784 |
|
|
|
862,042 |
|
|
|
- |
|
Production taxes
|
|
|
838,714 |
|
|
|
1,056,244 |
|
|
|
- |
|
General and administrative (includes non-cash consideration of $6,656,152, $13,097,346, and $684,778 for the periods ended December 31, 2011, 2010 and 2009)
|
|
|
10,544,347 |
|
|
|
15,530,248 |
|
|
|
1,057,306 |
|
Depreciation, depletion,accretion, and amortization
|
|
|
4,347,117 |
|
|
|
5,036,648 |
|
|
|
- |
|
Impairment of equipment
|
|
|
- |
|
|
|
- |
|
|
|
2,750,000 |
|
Impairment of evaluated properties
|
|
|
2,821,176 |
|
|
|
- |
|
|
|
- |
|
Bad debt expense
|
|
|
- |
|
|
|
400,000 |
|
|
|
- |
|
Fair value of common stock and warrants issued in aborted property acquisitions
|
|
|
- |
|
|
|
- |
|
|
|
8,404,106 |
|
Restructuring and related consulting costs
|
|
|
- |
|
|
|
- |
|
|
|
17,700,000 |
|
Total costs and expenses
|
|
|
20,066,138 |
|
|
|
22,885,182 |
|
|
|
29,911,412 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from operations
|
|
|
(11,704,044 |
) |
|
|
(13,127,490 |
) |
|
|
(29,911,412 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income
|
|
|
71,253 |
|
|
|
- |
|
|
|
- |
|
Convertible notes conversion derivative gain
|
|
|
3,821,792 |
|
|
|
- |
|
|
|
- |
|
Interest expense (includes non-cash interest expense of $ 4,993,997, $3,989,649, and $0 for the periods ended December 31, 2011, 2010 and 2009)
|
|
|
(8,218,225 |
) |
|
|
(6,640,209 |
) |
|
|
31 |
|
Unrealized gain on lock-up
|
|
|
- |
|
|
|
28,666 |
|
|
|
- |
|
Debt inducement expense
|
|
|
(2,800,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$ |
(18,829,224 |
) |
|
$ |
(19,739,033 |
) |
|
$ |
(29,911,381 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$ |
(1.21 |
) |
|
$ |
(2.15 |
) |
|
$ |
(12.19 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
|
15,543,758 |
|
|
|
9,167,803 |
|
|
|
2,453,921 |
|
The accompanying notes are an integral part of these financial statements.
RECOVERY ENERGY, INC.
For the year ended December 31, 2011, December 31, 2010 and from March 6, 2009 (Inception) through December 31, 2009
|
|
Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subject to Redemption |
|
|
Common Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
Additional Paid-In Capital
|
|
|
Accumulated Deficit
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 6, 2009 (Inception)
|
|
$ |
- |
|
|
|
- |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued in reverse merger
|
|
|
- |
|
|
|
- |
|
|
|
524,750 |
|
|
|
52 |
|
|
|
(33,957 |
) |
|
|
- |
|
|
|
(33,905 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued in exchange of debt
|
|
|
- |
|
|
|
- |
|
|
|
525,000 |
|
|
|
53 |
|
|
|
3,249,790 |
|
|
|
- |
|
|
|
3,249,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued in lock-up agreement
|
|
|
21,250 |
|
|
|
172,516 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued in restructuring
|
|
|
- |
|
|
|
- |
|
|
|
1,250,000 |
|
|
|
125 |
|
|
|
17,499,500 |
|
|
|
- |
|
|
|
17,499,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued in attempted acquisition
|
|
|
- |
|
|
|
- |
|
|
|
425,000 |
|
|
|
43 |
|
|
|
5,824,830 |
|
|
|
- |
|
|
|
5,824,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued for cash
|
|
|
- |
|
|
|
- |
|
|
|
31,250 |
|
|
|
3 |
|
|
|
499,988 |
|
|
|
- |
|
|
|
499,991 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock and performance options issued to employees and directors
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
684,778 |
|
|
|
- |
|
|
|
684,778 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants issued for financing commitment
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,329,106 |
|
|
|
- |
|
|
|
3,329,106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock reacquired in attempted acquisition
|
|
|
- |
|
|
|
- |
|
|
|
(62,500 |
) |
|
|
(6 |
) |
|
|
(749,975 |
) |
|
|
- |
|
|
|
(749,981 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1:4 Reverse stock split
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
808 |
|
|
|
- |
|
|
|
808 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(29,911,381 |
) |
|
|
(29,911,381 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
21,250 |
|
|
|
172,516 |
|
|
|
2,693,500 |
|
|
|
269 |
|
|
|
30,304,868 |
|
|
|
(29,911,381 |
) |
|
|
393,756 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued for property acquisitions
|
|
|
- |
|
|
|
- |
|
|
|
2,929,167 |
|
|
|
293 |
|
|
|
15,786,328 |
|
|
|
- |
|
|
|
15,786,621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued in connection with financing property acquisitions
|
|
|
- |
|
|
|
- |
|
|
|
1,250,000 |
|
|
|
125 |
|
|
|
5,249,500 |
|
|
|
- |
|
|
|
5,249,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued for cash
|
|
|
- |
|
|
|
- |
|
|
|
3,978,789 |
|
|
|
398 |
|
|
|
14,924,142 |
|
|
|
- |
|
|
|
14,924,540 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued for services
|
|
|
- |
|
|
|
- |
|
|
|
502,216 |
|
|
|
50 |
|
|
|
2,256,038 |
|
|
|
- |
|
|
|
2,256,088 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock issued to employees and directors
|
|
|
- |
|
|
|
- |
|
|
|
2,235,797 |
|
|
|
223 |
|
|
|
8,375,327 |
|
|
|
- |
|
|
|
8,375,550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants exercised for cash
|
|
|
- |
|
|
|
- |
|
|
|
853,500 |
|
|
|
85 |
|
|
|
5,120,658 |
|
|
|
- |
|
|
|
5,120,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants issued for cash, services and fees |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
11,712,671 |
|
|
|
- |
|
|
|
11,712,671 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock no longer subject to redemption
|
|
|
(10,625 |
) |
|
|
(86,258 |
) |
|
|
10,625 |
|
|
|
1 |
|
|
|
86,258 |
|
|
|
- |
|
|
|
86,258 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1:4 Reverse stock split
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,525 |
|
|
|
- |
|
|
|
3,525 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(19,739,033 |
) |
|
|
(19,739,033 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
|
10,625 |
|
|
|
86,258 |
|
|
|
14,453,593 |
|
|
|
1,444 |
|
|
|
93,819,315 |
|
|
|
(49,650,414 |
) |
|
|
44,170,344 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1:4 Reverse stock split
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
387 |
|
|
|
- |
|
|
|
387 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued for property acquisitions
|
|
|
- |
|
|
|
- |
|
|
|
2,269,543 |
|
|
|
228 |
|
|
|
10,895,665 |
|
|
|
- |
|
|
|
10,895,893 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock no longer subject to redemption (1)
|
|
|
(10,625 |
) |
|
|
(86,258 |
) |
|
|
10,625 |
|
|
|
1 |
|
|
|
86,254 |
|
|
|
- |
|
|
|
86,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued in connection with interest payment of the financing
|
|
|
- |
|
|
|
- |
|
|
|
78,982 |
|
|
|
8 |
|
|
|
559,863 |
|
|
|
- |
|
|
|
559,872 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued for services
|
|
|
- |
|
|
|
- |
|
|
|
10,000 |
|
|
|
1 |
|
|
|
81,996 |
|
|
|
- |
|
|
|
81,997 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock issued to employees and directors
|
|
|
- |
|
|
|
- |
|
|
|
238,750 |
|
|
|
24 |
|
|
|
6,161,041 |
|
|
|
- |
|
|
|
6,161,065 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants issued for cash
|
|
|
- |
|
|
|
- |
|
|
|
375,333 |
|
|
|
38 |
|
|
|
2,129,801 |
|
|
|
- |
|
|
|
2,129,804 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants issued for debt extension
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,611,797 |
|
|
|
|
|
|
|
1,611,832 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt conversion expense
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,800,000 |
|
|
|
- |
|
|
|
2,800,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(18,829,224 |
) |
|
|
(18,829,224 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2011
|
|
|
- |
|
|
|
- |
|
|
|
17,436,825 |
|
|
$ |
1,744 |
|
|
$ |
118,146,119 |
|
|
$ |
(68,479,638 |
) |
|
$ |
49,668,225 |
|
The accompanying notes are an integral part of these financial statements.
RECOVERY ENERGY, INC.
|
|
Year Ended
December 31, 2011
|
|
|
Year Ended
December 31, 2010
|
|
|
March 6, 2009
(Inception) through
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$ |
(18,829,224 |
) |
|
$ |
(19,739,033 |
) |
|
$ |
(29,911,381 |
) |
Adjustments to reconcile net loss to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of equipment
|
|
|
- |
|
|
|
- |
|
|
|
2,750,000 |
|
Impairment of evaluated properties
|
|
|
2,821,176 |
|
|
|
- |
|
|
|
- |
|
Debt inducement and warrant modification expense
|
|
|
2,800,000 |
|
|
|
2,953,450 |
|
|
|
- |
|
Common stock issued for convertible note interest
|
|
|
559,873 |
|
|
|
- |
|
|
|
- |
|
Bad debt expense
|
|
|
- |
|
|
|
400,000 |
|
|
|
- |
|
Common stock for services and compensation
|
|
|
6,566,152 |
|
|
|
8,701,263 |
|
|
|
884,778 |
|
Fair value of warrants issued
|
|
|
- |
|
|
|
- |
|
|
|
3,329,106 |
|
Non-cash restructuring costs
|
|
|
- |
|
|
|
- |
|
|
|
17,500,000 |
|
Loss on aborted property acquisitions
|
|
|
- |
|
|
|
- |
|
|
|
5,075,000 |
|
Changes in the fair value of commodity price derivatives
|
|
|
(549,434 |
) |
|
|
398,840 |
|
|
|
- |
|
Compensation expense recognized for assignment of overrides
|
|
|
- |
|
|
|
1,578,080 |
|
|
|
- |
|
Amortization of deferred financing costs
|
|
|
4,446,911 |
|
|
|
3,989,649 |
|
|
|
- |
|
Change in fair value of convertible notes conversion derivative
|
|
|
(3,821,792 |
) |
|
|
- |
|
|
|
|
|
Depreciation, depletion, and amortization and accretion of asset retirement obligation
|
|
|
4,347,117 |
|
|
|
5,036,648 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
73,940 |
|
|
|
(757,554 |
) |
|
|
(100,000 |
) |
Restricted cash
|
|
|
218,376 |
|
|
|
(1,129,665 |
) |
|
|
(20,876 |
) |
Other assets
|
|
|
39,451 |
|
|
|
(34,066 |
) |
|
|
15,627 |
|
Accounts payable and other accrued expenses
|
|
|
757,207 |
|
|
|
2,361,082 |
|
|
|
96,507 |
|
Net cash provided by (used in) operating activities
|
|
|
(570,247 |
) |
|
|
3,758,694 |
|
|
|
(381,239 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions of evaluated properties and equipment (net of purchase price adjustment)
|
|
|
- |
|
|
|
(25,580,793 |
) |
|
|
- |
|
Acquisition of unevaluated properties
|
|
|
(9,433,073 |
) |
|
|
(18,560,412 |
) |
|
|
- |
|
Drilling capital expenditures
|
|
|
(7,017,523 |
) |
|
|
(4,637,111 |
) |
|
|
- |
|
Sale of unevaluated property interests
|
|
|
3,000,000 |
|
|
|
2,000,000 |
|
|
|
1,500,000 |
|
Sale of drilling rigs
|
|
|
- |
|
|
|
100,000 |
|
|
|
- |
|
Additions of office equipment
|
|
|
(83,727 |
) |
|
|
(55,767 |
) |
|
|
(750,470 |
) |
Proceeds from hedge settlement
|
|
|
226,203 |
|
|
|
- |
|
|
|
- |
|
Investment in operating bonds
|
|
|
(348 |
) |
|
|
(75,675 |
) |
|
|
(109,891 |
) |
Net cash provided by (used in) investing activities
|
|
|
(13,308,468 |
) |
|
|
(46,809,758 |
) |
|
|
639,639 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of common stock, units and exercise of warrants
|
|
|
2,129,870 |
|
|
|
28,132,727 |
|
|
|
500,000 |
|
Proceeds from debt
|
|
|
9,411,597 |
|
|
|
28,500,000 |
|
|
|
- |
|
Common stock reacquired in attempted Church acquisition
|
|
|
- |
|
|
|
- |
|
|
|
(750,000 |
) |
Common stock issuable
|
|
|
- |
|
|
|
(100,000 |
) |
|
|
100,000 |
|
Payment of debt
|
|
|
(483,774 |
) |
|
|
(8,061,319 |
) |
|
|
- |
|
Net cash provided by (used in) financing activities
|
|
|
11,057,693 |
|
|
|
48,471,408 |
|
|
|
(150,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
(2,821,023 |
) |
|
|
5,420,344 |
|
|
|
108,400 |
|
Cash and cash equivalents, beginning of period
|
|
|
5,528,744 |
|
|
|
108,400 |
|
|
|
- |
|
Cash and cash equivalents, end of period
|
|
$ |
2,707,722 |
|
|
$ |
5,528,744 |
|
|
$ |
108,400 |
|
Supplemental disclosure of non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$ |
3,201,312 |
|
|
$ |
2,655,131 |
|
|
$ |
- |
|
Cash paid for income taxes
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of rigs for note payable
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
3,250,000 |
|
Sale of property for receivable
|
|
$ |
1,443,852 |
|
|
$ |
- |
|
|
$ |
- |
|
Debt issuance cost
|
|
$ |
400,000 |
|
|
$ |
- |
|
|
$ |
- |
|
Purchase of properties for common stock
|
|
$ |
10,895,893 |
|
|
$ |
15,787,500 |
|
|
$ |
8,025,000 |
|
Stock and warrants issued for deferred financing costs
|
|
$ |
1,611,832 |
|
|
$ |
6,867,735 |
|
|
$ |
- |
|
Stock and warrants issued for prepaid financial advisory fees
|
|
$ |
- |
|
|
$ |
1,234,510 |
|
|
$ |
- |
|
Stock and warrants issued for prepaid financial office rent
|
|
$ |
81,997 |
|
|
$ |
- |
|
|
$ |
- |
|
Default on note in property acquisition
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(2,200,000 |
) |
Property additions for asset retirement obligation
|
|
$ |
61,469 |
|
|
$ |
479,238 |
|
|
$ |
- |
|
Stock issued for payment on long-term debt
|
|
$ |
559,872 |
|
|
$ |
- |
|
|
$ |
- |
|
The accompanying notes are an integral part of these financial statements.
RECOVERY ENERGY, INC.
NOTE 1 – ORGANIZATION
On September 21, 2009, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC (“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to Recovery Energy, Inc. (“Recovery”, “Recovery Energy”, “we”, “our”, and the “Company”). The Agreement was accounted for as a reverse acquisition with Coronado being treated as the acquirer for accounting purposes. Accordingly, the financial statements of Coronado have been adopted as the historical financial statements of Recovery.
The Company is an independent oil and gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 130,000 net acres. Recovery drills for, operates and produces oil and natural gas wells through the Company’s land holdings located in Wyoming, Colorado, and Nebraska.
All common stock share information is retroactively adjusted for the effect of a 4:1 reverse stock split that was effective October 19, 2011.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States ("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.
Certain amounts in the December 31, 2010 consolidated financial statements have been reclassified to conform to the December 31, 2011 consolidated financial statement presentation. Such reclassifications had no effect on net income.
Use of Estimates in the Preparation of Financial Statements
The preparation of the financial statements in accordance 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. On an ongoing basis, management evaluates its estimates based on historical experience and on various other factors that the Company believes to be reasonable under the circumstances. Actual results could differ from those estimates.
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. Significant financial estimates are also required for the analysis of impairment of oil and gas properties.
Principle of Consolidation
The accompanying consolidated financial statements include Recovery Energy, Inc. and its wholly−owned subsidiaries Recovery Oil and Gas, LLC, and Recovery Energy Services, LLC. All intercompany accounts and transactions have been eliminated in consolidation. Both subsidiaries were inactive and were dissolved in the 4th quarter of 2011.
Liquidity
Cash used in operating activities during the year ended December 31, 2011 was $.6 million and cash used in investing activities exceeded cash provided by financing activities by approximately $2.2 million. This net cash use contributed to a substantial decrease in our net working capital as of December 31, 2011. Expenditures subsequent to December 31, 2011 have continued to exceed cash receipts, causing a further reduction of the Company’s working capital position.
In the immediate term, the Company expects that additional capital will be required to fund its capital budget for 2012, partially to fund some of its ongoing overhead, and to provide additional capital to generally improve its working capital position. We anticipate that these capital requirements will be funded by a combination of capital raising activities, including the selling of additional debt and/or equity securities and the selling of certain assets. If we are not successful in obtaining sufficient cash sources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring portions of our 2012 capital budget.
Pursuant to our credit agreements with Hexagon, a substantial portion of our monthly net revenues derived 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.
Since inception, the Company raised approximately $72 million in cash generally through private placements of debt and equity securities. In December 2011, the Company sold certain undeveloped acreage for total proceeds of $4.5 million. During 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues of approximately $2,000,000 in the aggregate as payment on the Hexagon debt. In November 2011, Hexagon extended the maturity date of their notes to January 1, 2013, and also advanced an additional $309,000 to the Company. The Company repaid the $309,000 advance in February 2012. In March 2012, Hexagon extended the maturity date of their notes to June 30, 2013, and in connection therewith, the Company agreed to make minimum note payments of $325,000, effective immediately. The Company will continue to pursue alternatives to shore up its working capital position and to provide funding for its planned 2012 expenditures.
Cash and Cash Equivalents
Cash and cash equivalents include cash in banks and highly liquid debt securities which have original maturities of 90 days or less at the purchase date.
Restricted Cash
Restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities and amounts restricted pursuant to our loan agreements.
Accounts Receivable
The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables for years ended December 31, 2011or December 31, 2010. Receivables which derive from sales of certain oil and gas production are collateral for our Loan Agreements (see Note 7).
During the year ended December 31, 2010, the Company wrote off a note receivable for $400,000 as a bad debt expense (see Note 13). During the year ended December 31, 2011 and period ended December 31, 2009, no receivable amounts were written off to bad debt expense.
Assets Held For Sale
Assets held for sale are recorded at the lower of cost or estimated net realizable value. As of December 31, 2011 and 2010, the Company did not have any assets held for sale.
Concentration of Credit Risk
The Company's cash, cash equivalents and short-term investments are invested at major financial institutions primarily within the United States. At December 31, 2011 and December 2010, the Company’s cash and cash equivalents were maintained in accounts that are insured up to the limit determined by the federal governmental agency. The Company may at times have balances in excess of the federally insured limits.
The Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.
Significant Customers
During the year ended December 31, 2011 and December 31, 2010, approximately 76% and 64%, respectively, of the Company's revenue sold to one customer, Shell Trading (US). However, the Company does not believe that the loss of a single purchaser, including Shell Trading (US), would materially affect the Company's business because there are numerous other purchasers in the area in which the Company sells its production.
Oil and Gas Producing Activities
The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration, development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.
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. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves, and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that are not otherwise included in capitalized costs.
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 sum of i.) the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves, plus ii.) the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. As of December 31, 2011, the Company recognized an impairment of $2,821,176. During the year ended December 31, 2010 and period ended December 31, 2009, no impairment charges were recognized.
The present value of estimated future net revenues was computed by applying a twelve month average of the first day of the month price of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.
Unproved Properties
The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties or the amount of the impairment is added to costs subject to depletion calculations. During the year ended December 31, 2011, the Company impaired $3,861,875 of unproved property value. During the years ending December 31, 2010 and December 31, 2009, no impairment was recorded.
Wells in Progress
Wells in progress represent wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to exploration and development costs and become subject to both depletion and the ceiling test calculations in future periods. At December 31, 2011, the Company had two wells in progress, both of which have been drilled and completed and are pending evaluation as to their potential to produce commercial quantities of oil and gas reserves.
Deferred Financing Costs
As of December 31, 2011 and December 31, 2010, the Company recorded unamortized deferred financing costs of approximately $2.3 million and $3.2 million, respectively, related to the closing of its loans and credit agreements (see Note 7). Deferred financing costs include origination (warrants issued and overriding royalty interests assigned to our lender), legal and engineering fees incurred in connection with the Company's credit facility, which are being amortized over the term of the credit facility. The Company recorded amortization expense of approximately $5.0 million and $4.0 million, respectively, in the years ended December 31, 2011 and December 31, 2010.
Prepaid Advisory Fees
The Company accounts for prepaid advisory services with the total consideration amortized over the underlying service agreement period. As of December 31, 2011 and 2010 prepaid financial advisory fees were approximately $574,000 and $979,000, respectively. The prepaid fees were paid with non-cash consideration (shares of our common stock and warrants exercisable for shares of our common stock issued to our financial advisors) initially issued in 2010 in the amount of $1,234,000. This amount is being amortized over the term of the underlying agreement. The Company amortized $405,000 and $247,000, respectively of prepaid fees during the years ended December 31, 2011 and December 31, 2010.
The following schedule details the future expense of the prepaid advisory fees.
2012
|
|
$ |
405,289 |
|
2013
|
|
|
168,871 |
|
Total
|
|
$ |
574,160 |
|
Property and Equipment
Property and equipment (other than the full cost pool) are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from one to 7 years. The Company recorded $34,000 and $5,000 of depreciation for the years ended December 31, 2011 and December 31, 2010, respectively.
Impairment of Long-lived Assets
The Company accounts for long-lived assets (other than the full cost pool), which include property and equipment, prepaid advisory fees, and identifiable intangible assets with finite useful lives (subject to amortization, depletion, and depreciation), whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.
For the period ended December 31, 2009, the Company recorded impairment expense of $2,750,000 related to the two medium depth drilling rigs. As of December 31, 2011 and 2010, no impairment has been recorded for long lived assets other than the impairment of its capitalized oil and gas property costs during 2011 as discussed above.
Fair Value of Financial Instruments
As of December 31, 2011 and 2010, the carrying value of cash and cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits approximates fair value due to the short-term nature of such items. The carrying value of other long-term liabilities approximates fair value as the related interest rates approximate rates currently available to Recovery Energy, certain other assets and liabilities are measured at fair value as discussed in Note 6.
Commodity Derivative Instrument
The Company utilizes swaps to reduce the effect of price changes on a portion of our future oil production. On a monthly basis, a swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price. The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivative contracts to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions (see Note 5).
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts are currently with one counterparty. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement (see Note 5).
Revenue Recognition
The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable.
Asset Retirement Obligation
The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value.
For purposes of depletion calculations, the Company also includes estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations.
Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated to operating expense using a systematic and rational method. As of December 31, 2011 and 2010, the Company recorded a net asset of $592,150 and $540,707 and a related liability of $612,874 and $507,280 (see Note 6).
The information below reconciles the value of the asset retirement obligation for the periods presented:
|
|
For the years ended December 31,
|
|
|
|
2011
|
|
|
2010
|
|
Balance, beginning of period
|
|
$ |
507,280 |
|
|
|
- |
|
Liabilities incurred
|
|
|
61,469 |
|
|
|
478,208 |
|
Accretion expense
|
|
|
44,125 |
|
|
|
28,042 |
|
Change in estimate
|
|
|
- |
|
|
|
1,030 |
|
Balance, end of period
|
|
$ |
612,874 |
|
|
$ |
507,280 |
|
Share Based Compensation
The Company measures the fair value of share-based compensation expense awards made to employees and directors, including stock options, restricted stock and employee stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. 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. The measurement of share-based compensation expense is based on several criteria, including but not limited to the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining share-based compensation expense and the actual factors, which become known over time, Recovery may change the input factors used in determining future share-based compensation expense.
Recovery accounts for option grants to non-employees whereby the fair value of such options is determined using the Black-Scholes option pricing model at the earlier of the date at which the non-employee’s performance is complete or a performance commitment is reached (Note 12).
Warrant Modification Expense
The Company accounts for the modification of warrants as an exchange of the old award for a new award. The incremental value is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a period expense or amortized over the performance or vesting date. We estimate the incremental value of each warrant using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree of subjective judgment is the estimated volatility of our stock price (Note 12).
Loss per Common Share
Basic earnings (loss) per share is based on the weighted average number of common shares outstanding during the period presented. In addition to common shares outstanding, diluted loss per share is computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares. Potentially dilutive securities, such as stock grants and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive. For the years ended December 31, 2011 and December 31, 2010, outstanding warrants and derivatives of 5,638,900 and 5,764,233, respectively, have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. Accordingly, basic shares equal diluted shares for all periods presented. On October 16, 2011, the Company affected a 4:1 reverse stock split.
Income Taxes
For tax reporting, the Company continues to file its tax returns on an April 30 year end, which is the legal tax year end of its predecessor.
The Company uses the asset liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities, and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization.
We recognize tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards. As of December 31, 2011, the Company has determined that no liability is required to be recognized.
Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. However, we did not accrue interest or penalties at December 31, 2011 and December 31, 2010, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest on underpayments of tax and we believe that we are below the minimum statutory threshold for imposition of penalties. We do not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months. The earliest years remaining subject to examination are April 30, 2010 and 2009.
Recently Issued Accounting Pronouncements
The Company did not adopt any new authoritative guidance for the year ended December 31, 2011 that had a material impact on its financial statements.
NOTE 3 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS AND DIVESTITURES
DJ Basin Properties Acquisitions – Accounted for as a Business Combination
During the fourth quarter of 2009, the Company pursued a number of acquisition opportunities. The Company entered into two purchase and sale agreements with Edward Mike Davis, LLC and affiliates (“Davis”) for the purchase of multiple oil and gas properties. The Company was not successful in fulfilling the requirements under the purchase and sale agreements and forfeited 1,450,000 shares of our common stock with an estimated fair value of $5,075,000.
In January 2010, the Company acquired the Wilke Field from Davis for $4,500,000. The Company simultaneously entered into a credit agreement with Hexagon to finance 100% of the purchase of the Wilke Field properties. Hexagon received 1,000,000 shares of the Company's common stock in connection with the financing. The Company recorded $2.25 million in deferred financing costs related to the shares issued in conjunction with the loan (see Note 7).
In March 2010, the Company acquired the Albin Field properties from Davis for $6,000,000 and 550,000 shares of common stock with an estimated fair value of $412,500. The Company simultaneously entered into a loan agreement with Hexagon to finance 100% of the cash portion of the purchase price. The Company recorded approximately $737,822 in deferred financing costs related to 750,000 shares of the Company’s common stock and a one-half percent overriding royalty in the leases and wells in connection with the financing from Hexagon (see Note 7).
In April 2010, the Company acquired the State Line Field properties from Davis for $15,000,000 and 2,500,000 shares of common stock with an approximate fair value of $1,875,000. The Company simultaneously entered into a loan agreement with Hexagon to finance 100% of the cash portion of the purchase price. The Company recorded approximately $2,780,775 in deferred financing costs related to 3,250,000 shares of the Company’s common stock, 2,000,000 warrants to acquire the Company’s common stock at $2.50 per share and a one percent overriding royalty interest in connection with the financing from Hexagon (see Note 7).
All three of the acquisitions above were recorded at their fair values as of the acquisition date. The following table summarizes the fair values of assets acquired and liabilities assumed for each acquisition as of the related acquisition date:
|
|
Wilke Field
|
|
|
Albin Field
|
|
|
State Line Field
|
|
Consideration given:
|
|
|
|
|
|
|
|
|
|
Cash payment funded by debt
|
|
$ |
4,500,000 |
|
|
$ |
6,000,000 |
|
|
$ |
15,000,000 |
|
Stock
|
|
|
- |
|
|
|
412,500 |
|
|
|
1,875,000 |
|
Total consideration attributable to allocation
|
|
$ |
4,500,000 |
|
|
$ |
6,412,500 |
|
|
$ |
16,875,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of purchase price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$ |
4,418,267 |
|
|
$ |
4,675,099 |
|
|
$ |
15,529,268 |
|
Unproved oil and gas properties
|
|
|
83,200 |
|
|
|
1,791,619 |
|
|
|
1,070,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fair value of oil and gas properties acquired
|
|
|
4,501,467 |
|
|
|
6,466,718 |
|
|
|
16,600,243 |
|
Oil and gas revenue receivable
|
|
|
195,594 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
4,697,061 |
|
|
|
6,466,718 |
|
|
|
16,600,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
- |
|
|
|
- |
|
|
|
(52,147 |
) |
Asset retirement obligation
|
|
|
(197,061 |
) |
|
|
(54,218 |
) |
|
|
(149,151 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities acquired
|
|
|
(197,061 |
) |
|
|
(54,218 |
) |
|
|
(201,298 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets acquired
|
|
$ |
4,500,000 |
|
|
$ |
6,412,500 |
|
|
$ |
16,398,945 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Value attributable to ORRI paid to lender
|
|
$ |
- |
|
|
$ |
(175,322 |
) |
|
$ |
(158,685 |
) |
Value attributable to ORRI awarded to management
|
|
$ |
(125,220 |
) |
|
$ |
(701,290 |
) |
|
$ |
(317,370 |
) |
The following unaudited supplemental pro forma information presents the results of operations for the years ended December 31, 2010 and 2009, as if the Wilke, Albin, and State Line acquisitions had occurred as of the earliest period presented, January 1, 2009. These unaudited pro forma results of operations are based on the historical financial statements and related notes of the Company, and the related historical audited statements of revenue and direct expenses for the Wilke, Albin and State Line acquisitions included in the related filings on Form 8-K. These pro forma results of operations contain adjustments to depreciation, depletion and amortization for the effects of purchase price allocation, and to interest expense and amortization of deferred financing costs related to financing the acquisitions. The pro forma results are presented for informational purposes only and are not necessarily indicative of what actually would have occurred if the acquisitions had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
Operating revenues
|
|
$ |
12,941,108 |
|
|
$ |
6,070,500 |
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
$ |
(10,599,304 |
) |
|
$ |
(29,001,745 |
) |
|
|
|
|
|
|
|
|
|
Net loss
|
|
$ |
(19,063,015 |
) |
|
$ |
(33,489,536 |
) |
|
|
|
|
|
|
|
|
|
Pro forma loss per common share:
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$ |
(2.08 |
) |
|
$ |
(12.92 |
) |
Also in May 2010, the Company acquired additional undeveloped leasehold acreage and certain overriding royalty interests on existing Company owned acreage and wells in the DJ Basin from Davis for 2,000,000 shares of common stock valued at $1,500,000 and a cash payment of $20 million.
In August 2010, the Company farmed into approximately 240 net acres in exchange for carrying Davis, the lease owner, for a 26% working interest in one well, which has been drilled. The Company also farmed into approximately 533 net acres in the state of Nebraska in exchange for carrying Davis, the lease owner, for a 33% working interest in one well which has been drilled.
In November 2010, the Company purchased certain oil and gas interests of approximately 33,800 net acres located in Laramie County and Goshen County, Wyoming, and Banner County, Kimball County, and Scotts Bluff County, Nebraska from Davis. Additionally, the Company acquired rights below the base of the Greenhorn on approximately 23,000 net acres in Laramie County and Goshen County, Wyoming, and Banner County and Kimball County, Nebraska. The Company issued 6,666,667 shares of our common stock to acquire the property with an estimated fair value of approximately $12,000,000.
In December 2010, the Company entered into an acquisition and development agreement with TRW Exploration, LLC (a related party, see note 9) whereby TRW paid $2,000,000 for the purchases of an interest in approximately 2,000 net undeveloped acres and also agreed to carry the Company’s 40% interest in two horizontal wells to be drilled on lands defined by the agreement. TRW subsequently funded the drilling and completion costs of two horizontal wells on the lands covered by the leases, at a total cost of approximately $7 million. This agreement was terminated in December, 2011 and TRW sold back its interest in the wells along with all of its rights to the undeveloped acreage, in consideration for the issuance by the Company of 1,500,000 shares of unregistered common stock valued at $4,875,000. Additional amounts were incurred in drilling the wells and were paid by the Company. The Company allocated $2 million of this purchase price to the undeveloped leases, and the remainder to the purchase of the two wells.
The two wells are in progress and currently being evaluated as to their potential to establish commercial production of oil and gas. These wells are carried as wells in progress as of December 31, 2011 at a total cost of $6.4 million.
In February 2011, the Company purchased undeveloped oil and gas leases from various private individuals for $1,253,780 in cash and $653,449 in stock in the Grover Field and surrounding area in Weld County, Colorado, and Goshen County, Wyoming.
In March 2011, the Company purchased undeveloped oil and gas interests located in Laramie County, Wyoming. The purchase price was $6,469,552 cash and shares of common stock valued at $5,798,546 in stock. The Company also closed on two acquisitions of undeveloped oil and gas leases from various private individuals for a combined $551,519 in cash in Goshen County, Wyoming.
DJ Basin Properties Divestitures
Effective December 31, 2011 the Company sold 2,838 net acres of undeveloped leases for consideration of approximately $4.5 million. A gain of $1.8 million related to the sale of this acreage was applied as a credit to the carrying costs of evaluated oil and gas properties.
Depreciation, depletion and amortization (“DD&A”) expenses related to the proved properties were approximately $4,274,215 and $5,036,000 for the years ended December 31, 2011 and December 31, 2010, respectively. During the year ended December 31, 2011, the company impaired the carrying costs of its evaluated oil and gas properties by $2.8 million as a result of an excess of carrying costs above the applicable ceiling threshold. Prior to January 1, 2010, the Company did not own any oil and gas properties therefore we did not incur DD&A expense in 2009.
The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized as of December 31, 2011:
|
As of
December 31, 2011
|
|
Leasehold acquisitions
|
|
|
2010
|
|
$ |
33,605,594 |
|
2011
|
|
|
12,091,887 |
|
Unevaluated properties
|
|
|
45,697,481 |
|
|
|
|
|
|
Wells in progress exploration 2011
|
|
|
6,425,509 |
|
Total
|
|
$ |
52,122,990 |
|
The Company plans to evaluate exploration costs (wells-in progress) in 2012 and will likely develop, sell or reclassify to evaluated properties its inventory of unevaluated leasehold over the next three years. Included in its inventory of unevaluated leases are certain undeveloped leases with an approximate carrying value of $11 million that are being held and extended by the conducting of continuous operations on the two wells in progress. If commercial production is not eventually established in one or both of the two wells in progress, some or all of these leases may expire, and require such cases to be reclassified to evaluated property and subject to the Company’s full cost lid calculation.
NOTE 4 – WELLS IN PROGRESS
The following table reflects the net changes in capitalized additions to wells in progress during 2010 and 2009:
|
|
For the Year Ended December 31,
|
|
|
|
2011
|
|
|
2010
|
|
Beginning balance
|
|
$ |
1,219,254 |
|
|
|
- |
|
Additions to capital wells in progress costs
|
|
|
8,904,532 |
|
|
|
1,219,254 |
|
Reclassifications to proved properties
|
|
|
(3,698,563 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
$ |
6,425,509 |
|
|
$ |
1,219,254 |
|
All wells in progress have been capitalized for less than one year.
NOTE 5 - FINANCIAL INSTRUMENTS AND DERIVATIVES
Periodically, the Company enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. During the year ended December 31, 2011, the Company terminated and settled certain future commodity swaps resulting in a realized gain of approximately $625,000.
As of December 31, 2011, the Company maintained an active commodity swap for 100 barrels per day through December 31, 2012, at a price of $96.25 per barrel.
The amount of gain (loss) recognized in income related to our derivative financial instruments was as follows:
|
|
For the Year Ended December 31, |
|
|
|
2011
|
|
|
2010
|
|
|
2009(1)
|
|
Realized gain on oil price hedges
|
|
$ |
625,043 |
|
|
$ |
570,233 |
|
|
$ |
- |
|
Unrealized loss oil price hedges
|
|
$ |
(75,609 |
) |
|
$ |
(398,840 |
) |
|
$ |
- |
|
(1)
|
Prior to January 1, 2010, the Company did not enter any derivative financial instruments.
|
Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are recognized in the unrealized gain (loss) on hedge contracts line on the consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the realized gain (loss) line on the consolidated statement of income. As of December 31, 2011, the Company recorded an unrealized loss on its only active swap of $75,609.
NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value:
●
|
|
Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
|
●
|
|
Level 2 – Include other inputs that are directly or indirectly observable in the marketplace.
|
●
|
|
Level 3 – Unobservable inputs which are supported by little or no market activity.
|
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
The Company measures its cash equivalents and investments at fair value. The Company’s cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits are primarily classified within Level 1. Cash equivalents and short-term investments are valued primarily using quoted market prices utilizing market observable inputs.
Derivative Instruments
The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, and the credit rating of its counterparty. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.
In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
At December 31, 2011, the types of derivative instruments utilized by the Company included commodity swaps (see Note 5). The oil derivative markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
Asset Retirement Obligation
The income valuation technique is utilized determine the fair value of its asset retirement obligation liability at the point of inception by taking into account 1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which is based on estimates from reserve engineers; 3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.
Convertible Notes Payable Conversion Feature
In February 2011, the Company issued in a private placement $8,400,000 aggregate principal amount of three year 8% Senior Secured Convertible Debentures (“Debentures”) with a group of accredited investors. As of December 31, 2011, the Debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $4.25 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. The Company engaged a third party to complete a valuation of this conversion feature as of December 31, 2011 (see Note 7). The valuation was completed using Level 3 inputs.
The following table provides a summary of the fair values of assets and liabilities measured at fair value:
December 31, 2011
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
Liability
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
$ |
- |
|
|
$ |
(75,609 |
) |
|
$ |
- |
|
|
$ |
(75,609 |
) |
Convertible notes payable
Conversion feature
|
|
|
- |
|
|
|
- |
|
|
|
(1,300,000 |
) |
|
|
(1,300,000 |
) |
Total liability at fair value
|
|
$ |
- |
|
|
$ |
(75,609 |
) |
|
$ |
(1,300,000 |
) |
|
$ |
(1,375,609 |
) |
December 31, 2010
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
Liability
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
$ |
- |
|
|
$ |
(398,840 |
) |
|
$ |
- |
|
|
$ |
(398,840 |
) |
Total liability at fair value
|
|
$ |
- |
|
|
$ |
(398,840 |
) |
|
$ |
- |
|
|
$ |
(398,840 |
) |
The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of December 31, 2011:
|
|
Convertible debt feature (1)
|
|
Beginning balances, December 31, 2010
|
|
|
- |
|
Additions of convertible debt feature
|
|
|
(1,300,000 |
) |
Ending balance as of December 31, 2011
|
|
|
(1,300,000 |
) |
(1)
|
The Company entered into the convertible debt during the year ended December 31, 2011.
|
The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the twelve months ended December 31, 2011 and December 31, 2010.
NOTE 7 - LOAN AGREEMENTS
Term Notes
The Company entered into three separate loan agreements with Hexagon Investments, LLC (“Hexagon”) during 2010. All three loans bear annual interest of 15% and mature on June 30, 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 $6.0 million loan agreement, with an original maturity date of December 1, 2010. Effective April 14, 2010, the Company entered into a $15.0 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 notes 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.
The Company 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 $1,600,000. 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 half of 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2 million as payment on the notes. In November 2011, Hexagon extended the maturity to January 1, 2013. In March 2012, Hexagon agreed to extend the maturity of the notes to June 30, 2013, and in connection there with, the Company agreed to make minimum monthly note payments of $325,000, effective immediately. In November 2011, Hexagon also temporarily advanced the Company an additional amount of $309,000, which was repaid in full in February 2012.
The Company is subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements. As of December 31, 2011, 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 Notes Payable
In February 2011, the Company completed a private placement of $8,400,000 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 Recovery Energy 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 $400,000 of Debentures equal to 5% of the gross proceeds from the sale. The Company is amortizing the $400,000 over the life of the loan as deferred financing costs. The Company amortized $88,888 of deferred financing costs into interest expense during the year ended December 31, 2011 and has $311,112 of deferred financing costs to be amortized over a straight-line basis until January 2014.
In December, 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share. Therefore, the Debenture are currently convertible into shares of common stock. This amendment was consideration to the Debenture holders in exchange for their agreement to release a mortgage on certain properties so the properties could be sold. The sale of these properties was completed effective December 31, 2011.
The Company engaged a third party valuation firm to complete a valuation of both the conversion feature and the inducement. This valuation resulted in an estimate of the inducement expense of $2.8 million and estimate of the derivative liability as of December 31, 2011 of $1.3 million. A previous independent valuation of the derivative liability estimated the derivative liability as of March 31, 2011 at approximately $5.1 million. The reduction in the derivative value from $5.1 million as of March 31, 2011 to $1.3 million as of December 31, 2011 resulted in a derivative gain of $3.8 million during the year ended December 31, 2011. As of December 31, 2011, the convertible debt is recorded as follows:
|
|
As of
December 31, 2011
|
|
Convertible debt
|
|
|
8,400,000 |
|
Debt discount
|
|
|
(3,470,932 |
) |
Total convertible debt, net
|
|
|
4,929,068 |
|
Annual debt maturities for our debt under our term notes and convertible notes payable obligations as of December 31, 2011 are as follows:
2012
|
|
|
1,150,966 |
|
2013
|
|
|
20,129,670 |
|
2014
|
|
|
8,400,000 |
|
Thereafter
|
|
|
-- |
|
Total
|
|
|
29,680,636 |
|
Interest Expense
For the years ending December 31, 2011 and December 31, 2010, the Company incurred interest expense of approximately $8,218,000 and $6,600,000, respectively, of which approximately $5.0 million and $4.0 million, respectively, were non-cash interest expense related to the amortization of the deferred financing costs, accretion of the convertible notes payable discount, and convertible notes payable interest paid in stock.
NOTE 8 - COMMITMENTS and CONTINGENCIES
Environmental and Governmental Regulation
At December 31, 2011, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates, and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2011, the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.
Legal Proceedings
The Company may from time to time be involved in various other legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial positions of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.
Potential Stock Grants Under Employment/Appointment Agreements
Until May 2010, the employment agreements for our chief executive officer and former chief financial officer contained provisions which provided these individuals additional stock grants if the Company achieved certain market capitalization milestones. In May 2010, the employment agreements were modified and our chief executive officer and former chief financial officer were no longer entitled to stock grants based on market capitalization milestones.
Operating Leases
The Company leases an office space under a one year operating lease in Denver, Colorado. Rent expense for the years ended December 31, 2011 and December 31, 2010, was $82,068 and $54,500, respectively. The Company will have minimum lease payments of $72,000 for the year ending December 31, 2012.
NOTE 9 - RELATED PARTY TRANSACTIONS
Since its inception, five property acquisitions the Company completed have been with the same seller, Davis. As of December 31, 2011, Davis owned approximately 19.1 % of the common stock of the Company. The cash portion of the purchase price for the first three acquisitions was financed with loans from Hexagon, which owned approximately 15.7% of the stock issued and outstanding at December 31, 2011. Hexagon received overriding royalty interests in both the Albin Field assets and the State Line Field assets. Hexagon also received warrants to purchase 500,000 shares of the Company’s common stock at $10.00 per share in connection with the financing of an acquisition and warrants to purchase 250,000 shares the Company’s common stock for $6.00 per share in connection with amendments to the loan agreements. A representative of Hexagon also served on the Company’s Board of Directors, until his resignation on January 31, 2012.
The Company entered into an exploration and development agreement with TRW to drill two wells. The joint venture partners of TRW are also shareholders of the Company.
NOTE 10 - INCOME TAXES
The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2011 and 2010 were:
|
|
2011
|
|
|
2010
|
|
Deferred tax assets:
|
|
|
|
|
|
|
Oil and gas properties and equipment
|
|
$ |
(515,123 |
) |
|
$ |
(1,335,490 |
) |
Net operating loss carry-forward
|
|
|
11,291,513 |
|
|
|
7,285,426 |
|
Share based compensation
|
|
|
4,675,241 |
|
|
|
3,902,007 |
|
Abandonment obligation
|
|
|
205,145 |
|
|
|
188,728 |
|
Derivative instruments
|
|
|
176,514 |
|
|
|
148,384 |
|
Other
|
|
|
(91,304 |
) |
|
|
(30,896 |
) |
Total deferred tax asset
|
|
|
15,741,986 |
|
|
|
10,158,159 |
|
Valuation allowance
|
|
|
(15,741,986 |
) |
|
|
(10,158,159 |
) |
Net deferred tax asset
|
|
$ |
- |
|
|
$ |
- |
|
Reconciliation of the Company’s effective tax rate to the expected federal tax rate is:
|
|
2011
|
|
|
2009
|
|
Effective federal tax rate
|
|
|
35.00 |
% |
|
|
35.00 |
% |
Effect of permanent differences
|
|
|
-7.54 |
% |
|
|
-21.78 |
% |
State tax rate
|
|
|
2.20 |
% |
|
|
2.20 |
% |
Change in rate
|
|
|
0.00 |
% |
|
|
-0.23 |
% |
Other
|
|
|
0.00 |
% |
|
|
3.07 |
% |
Valuation allowance
|
|
|
-29.66 |
% |
|
|
-18.26 |
% |
Net
|
|
|
0 |
% |
|
|
0 |
% |
At December 31, 2011 and 2010, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $25,957,000 and $19,582,000, respectively,that may be offset against future taxable income. The Company has established a valuation allowance for the full amount of the deferred tax assets as management does not currently believe that it is more likely than not that these assets will be recovered in the foreseeable future. To the extent not utilized, the net operating loss carry-forwards as of December 31, 2011 will expire in 2031.
NOTE 11 - SHAREHOLDERS’ EQUITY
As of December 31, 2011, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 17,436,825 shares of common stock were issued and outstanding. No preferred shares were issued or outstanding. Preferred shares may be issued in such series as Preferred as determined by the Board of Directors. No lock-up or restricted shares were outstanding as of December 31, 2011.
Effective October 19, 2011, the Company completed a four-for-one reverse stock split on its common shares. All references to common stock, restricted stock, stock warrants, and common stock prices have been adjusted to reflect the effects of the reverse stock split.
In December 2011, the Company provided the 8% convertible debenture holders an inducement to convert their conversion price from $9.40 to $4.25. An inducement expense of $2.8 million was recognized in 2011. This transaction also increased additional paid-in capital by $2.8 million. This reduction in conversion price also increased potential dilutive shares outstanding as of December 31, 2011 by 1,082,854 shares from 893,617 to 1,926,471 shares reserved for possible conversion.
In connection with this inducement, the Company entered into an amendment to our 8% senior secured convertible debentures whereby, in addition to the inducement, the mortgage on certain of the Company's oil and gas leases was released and in substitution, we granted a lien on certain replacement oil and gas leases in Nebraska and Wyoming. As partial consideration for the substitution of this collateral, the amendment also provides the holders of the debentures with the first right of refusal to purchase up to 15% of any common stock, preferred stock or convertible debt offering by Recovery through December 31, 2012 at the offering price.
During the year ending December 31, 2011, the Company issued 2,983,233 shares of common stock. The stock issuances were comprised of 2,983,233 shares issued for acquisitions valued at $10,896,071, 10,000 shares issued for services valued at $82,000, 238,824 shares issued as restricted stock grants to employees valued at $6,161,111, 78,972 shares is for interest expense on the convertible notes payable valued at $559,860, 375,333 shares issued in connection with warrant exercises for $2,903,794 of cash.
In addition to the shares of common stock issued during the period, the Company issued convertible notes payable with a face value of $8.4 million. Based upon the current conversion price of $4.25 per share, these notes would convert into 1,976,471 shares of common stock. The conversion price is subject to other adjustments (See Note 7).
During the year ended December 31, 2010, the Company issued 11,749,467 shares of common stock. The stock issuances were comprised of 2,929,167 shares issued for acquisitions valued at $15,787,500, 502,216 shares issued for services valued at $2,256,239, 1,250,000 shares issued in connection with the loan agreements valued at $5,250,000, 2,235,797 shares issued as restricted stock grants to employees valued at $10,283,622, and 3,978,788 shares issued for $20,046,733 of cash.
During the year ended December 31, 2010, the Company issued common shares for cash. Included in these shares was a private placement of 3,975,300 units at $1.50 per unit, which included one share of common stock and one common stock purchase warrant. The warrants are exercisable at $1.50 per share through May 23, 2015. Warrants of 853,500 were subsequently exercised during 2010 for $5,121,000 of cash. In connection with the exercise, the Company granted a new warrant for each warrant exercised. The new warrants have an exercise price of $8.80 per share, which was slightly greater than the concurrent market price of the Company's common stock, and expire on September 29, 2015. The value of the new warrants, calculated at $2,953,450 using the Black Scholes method, was expensed as a warrant modification and included in general and administrative expenses.
Temporary Equity
As part of the reverse merger in 2009, 5,313 shares of common stock were issued and outstanding under a lock-up agreement that has terms which may result in the Company reacquiring the shares due to circumstances outside of the Company’s control and therefore the shares are preferential to common shares. The 5,313 shares, which were valued at $172,516, covered by the lock-up agreement were treated as temporary equity and reported separately from other shareholders’ equity. The lock-up period for 2,658 shares ended on September 21, 2010, with the other lock-up period ending on March 21, 2011. As a result, on March 21, 2011, the final 2,658 shares covered under the lock-up agreement were moved to permanent on equity.
Warrants
During 2010, the Company issued common shares for cash. Included in these shares was a private placement of 15,901,200 units at $1.50 per unit, which included one share of common stock and one common stock purchase warrant. The warrants are exercisable at $1.50 per share through May 23, 2015. 3,414,000 of these warrants were subsequently exercised during 2010 for $5,121,000 of cash. In connection with the exercise, the Company granted a new warrant for each warrant exercised. The new warrants have an exercise price of $2.20 per share, which was slightly greater than the concurrent market price of the Company's common stock, and expire on September 29, 2015. The value of the new warrants, calculated at $2,953,450 using the Black Scholes method, was expensed as a warrant modification and included in general and administrative expenses
On January 1, 2011, the Company issued 250,000 warrants with an exercise price of $6.00 per share to Hexagon which was valued at approximately $1,600,000 (See Note7).
A summary of warrant activity for the years ended December 31, 2011 and December 31, 2010 is presented below:
|
|
Warrants
(1)
|
|
|
Weighted-Average
Exercise
Price
(1)
|
|
Outstanding at December 31, 2009
|
|
|
187,500 |
|
|
$ |
14.00 |
|
Granted
|
|
|
6,430,233 |
|
|
|
6.68 |
|
Exercised, forfeited, or expired
|
|
|
(853,500 |
) |
|
|
6.00 |
|
Outstanding at December 31, 2010
|
|
|
5,764,233 |
|
|
|
7.04 |
|
Granted
|
|
|
250,000 |
|
|
|
6.00 |
|
Exercised, forfeited, or expired
|
|
|
(375,333 |
) |
|
|
6.16 |
|
Outstanding at December 31, 2011
|
|
|
5,638,900 |
|
|
$ |
6.33 |
|
(1)
|
On October 17, 2011, the Company performed a 4:1 reverse stock split. The values shown are reflecting the reverse stock split.
|
The aggregate intrinsic value of warrants was approximately $0 and $6,687,000 based on the Company’s closing common stock price of $5.20 and $8.20 as of December 31, 2011 and December 31, 2010, respectively, and the weighted average remaining contract life was 3.68 years and 4.15 years.
Assumptions used in estimating the fair value of the warrants issued for the periods indicated are presented below:
|
|
For the years ended December 31, |
|
|
|
2011
|
|
|
2010
|
|
Weighted-average volatility
|
|
|
97
|
%
|
|
|
80
|
%
|
Expected dividends
|
|
|
0.00
|
%
|
|
|
0.00
|
%
|
Expected term (in years)
|
|
|
3 – 5
|
|
|
|
3 – 5
|
|
Risk-free rate
|
|
|
2.02
|
%
|
|
|
1.49
|
%
|
The Company has not adopted a stock incentive plan for its management team. Members of the board of directors and the management team are periodically awarded restricted stock grants.
NOTE 12 - SHARE BASED COMPENSATION
The costs of employee services received in exchange for an award of equity instruments are based on the grant-date fair value of the award, recognized over the period during which an employee is required to provide services in exchange for such award.
During the year ended December 31, 2011, the Company granted 238,750 shares of restricted common stock to employees of which 207,016, vest during the year ended December 31, 2011. The Company will vest restricted stock of 192,000, 120,000, and 2,500 for the years ending December 31, 2012, 2013, and 2014, respectively. The fair value of these share grants was calculated to be approximately $4,370,808.
The Company recognized stock compensation expense of approximately $6,161,000, $917,000 and $2,714,000 for the years ended December 31, 2011, 2010 and 2009, respectively. During the year ended December 31, 2011, the Company had a one-time charge of $3,551,000 for stock compensation expense with the grant of 481,250 shares included in the separation agreement of the former chief financial officer, which was accounted for as a cancellation of an award and issuance of a new award.
A summary of restricted stock grant activity for the year ended December 31, 2011 is presented below
|
|
Shares (1)
|
|
Outstanding at March 6,2009
|
|
$ |
- |
|
Granted
|
|
|
371,050 |
|
Vested
|
|
|
- |
|
Outstanding at December 31, 2009
|
|
|
371,050 |
|
|
|
|
|
|
Granted
|
|
|
1,864,747 |
|
Vested
|
|
|
- |
|
Outstanding at December 31, 2010
|
|
|
2,235,797 |
|
|
|
|
|
|
Granted
|
|
|
932,500 |
|
Vested
|
|
|
(828,062 |
) |
Outstanding at December 31, 2011
|
|
$ |
2,340,235 |
|
(1)
|
On October 17, 2011, the Company affected a 4:1 reverse stock split. The values shown are reflecting the reverse stock split.
|
The Company will recognize $1,066,000, $366,615 and $12,478 for the years ending December 31, 2012, 2013, and 2014, respectively.
NOTE 13 – DRILLING RIGS
In May 2009, two drilling rigs were contributed to the Company for a note of $3,250,000. These rigs were recorded at estimated fair value as this was lower than their predecessor cost basis. The note holder subsequently converted the note for 2,100,000 shares of common stock (Note 3). These rigs required certain capital improvements prior to their ability to be functional in operations.
In 2009, management determined that future drilling operations were not part of their strategic plans. Management estimated the net realizable value to be $500,000; therefore, an impairment of $2,750,000 was recorded for the period ending December 31, 2009.
In May 2010, the Company entered into a purchase and sale agreement for the rigs. The Company sold the rigs for $700,000 under which the Company received $100,000 in cash and the balance in a five-year secured note. The acquirer defaulted on the note and the Company is now pursuing the remedies afforded to it under the note and security agreement. The Company believes it is in a first lien position on the underlying collateral, however, in 2010 the Company elected to fully reserve the $400,000 note receivable as the ability to recover the amount and the value of the underlying collateral was uncertain.
NOTE 14: SUBSEQUENT EVENTS
On March 19, 2012, the Company entered into agreements with its existing convertible debenture holders to extend the amount of its debenture debt by up to an additional $5.0 million. Proceeds resulting from the increase in the debentures will 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 this offering will be pledged as collateral to secure the expanded debt.
The initial closing related to these agreements will be in the amount of $1.5 million and is expected to occur prior to March 23, 2012. On or before September 15, 2012, convertible debenture holders may elect to purchase up to an additional $3.5 million in additional debentures. All terms of the expansion convertible debentures are substantively identical to the existing convertible debentures (see Note 7).
NOTE 15- SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The following table sets forth information for the years ended December 31, 2011, 2010 and 2009 with respect to changes in the Company's proved (i.e. proved developed and undeveloped) reserves:
|
|
Crude Oil (Bbls)
|
|
|
Natural Gas
(Mcf)
|
|
December 31, 2009
|
|
|
- |
|
|
|
- |
|
Purchase of reserves
|
|
|
643,955 |
|
|
|
- |
|
Revisions of previous estimates
|
|
|
123,679 |
|
|
|
- |
|
Extensions and discoveries
|
|
|
58,463 |
|
|
|
323,493 |
|
Sale of reserves
|
|
|
- |
|
|
|
- |
|
Production
|
|
|
(133,709 |
) |
|
|
(14,914 |
) |
December 31, 2010
|
|
|
692,388 |
|
|
|
308,579 |
|
Purchase of reserves
|
|
|
- |
|
|
|
- |
|
Revisions of previous estimates
|
|
|
(268,718 |
) |
|
|
(44,919 |
) |
Extensions, discoveries
|
|
|
266,000 |
|
|
|
- |
|
Sale of reserves
|
|
|
|
|
|
|
|
|
Production
|
|
|
(81,433 |
) |
|
|
(115,583 |
) |
December 31, 2011
|
|
|
608,237 |
|
|
|
148,077 |
|
Proved Developed Reserves, included above:
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
- |
|
|
|
- |
|
Balance, December 31, 2010
|
|
|
277,669 |
|
|
|
308,579 |
|
Balance, December 31, 2011
|
|
|
215,693 |
|
|
|
148,077 |
|
Proved Undeveloped Reserves, included above:
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
- |
|
|
|
- |
|
Balance, December 31, 2010
|
|
|
414,719 |
|
|
|
- |
|
Balance, December 31, 2011
|
|
|
392,545 |
|
|
|
- |
|
The Company did not have any reserves as of December 31, 2009.
As of December 31, 2011 and December 31, 2010, we had estimated proved reserves of 608,237 and 692,388 barrels of oil, respectively and 24,680 and 308,579 thousand cubic feet ("MCF") of natural gas, respectively. Our reserves are comprised of 96% and 93% crude oil and 4% and 7% natural gas on an energy equivalent basis.
The following values for the December 31, 2011 and December 31, 2010 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31 natural gas price of $3.96 and $4.39 per MMBtu (NYMEX price) and crude oil price of $88.16 and $77.78 per barrel (West Texas Intermediate price). All prices are then further adjusted for transportation, quality and basis differentials.
During the years ended December 31, 2010, the Company completed multiple acquisitions which included proved reserves associated with producing properties. Included in the Company's December 31, 2010 proved reserves classified as 'Purchase of reserves' in the table above, are $3,760,000 and 643,955 barrels of crude oil attributable to the acquisitions.
The following summary sets forth the Company's future net cash flows relating to proved oil and gas:
|
|
For the Year Ended December 31,
(in thousands)
|
|
|
|
2011
|
|
|
2010
|
|
|
2009 (1)
|
|
Future oil and gas sales
|
|
$ |
55,295 |
|
|
$ |
51,816 |
|
|
$ |
- |
|
Future production costs
|
|
|
(16,579 |
) |
|
|
(11,614 |
) |
|
|
- |
|
Future development costs
|
|
|
(8,481 |
) |
|
|
(8,063 |
) |
|
|
- |
|
Future income tax expense (2)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
30,235 |
|
|
|
32,139 |
|
|
|
- |
|
10% annual discount
|
|
|
(10,221 |
) |
|
|
(8,544 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$ |
20,014 |
|
|
$ |
23,595 |
|
|
$ |
- |
|
(1)
|
Prior to January 2010, the Company did not own any oil and gas assets.
|
(2)
|
Our calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all years reported. We expect that all of our Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company's operations, and resulting NOLs, are attributable to our oil and gas assets. There were no taxes in any year as the tax basis and NOL's exceeded the future net revenue.
|
The principle sources of change in the standardized measure of discounted future net cash flows are:
|
|
2011
|
|
|
2010
|
|
|
2009 (1)
|
|
Balance at beginning of period
|
|
$ |
23,595 |
|
|
$ |
- |
|
|
$ |
- |
|
Sales of oil and gas, net
|
|
|
(5,342 |
) |
|
|
(7,655 |
) |
|
|
- |
|
Net change in prices and production costs
|
|
|
8,006 |
|
|
|
3,084 |
|
|
|
- |
|
Net change in future development costs
|
|
|
- |
|
|
|
(4,563 |
) |
|
|
- |
|
Extensions and discoveries
|
|
|
5,883 |
|
|
|
5,067 |
|
|
|
- |
|
Acquisition of reserves
|
|
|
|
|
|
|
18,967 |
|
|
|
- |
|
Sale of reserves
|
|
|
|
|
|
|
- |
|
|
|
- |
|
Revisions of previous quantity estimates
|
|
|
(14,804 |
) |
|
|
5,245 |
|
|
|
- |
|
Previously estimated development costs incurred
|
|
|
|
|
|
|
- |
|
|
|
- |
|
Net change in income taxes
|
|
|
|
|
|
|
- |
|
|
|
- |
|
Accretion of discount
|
|
|
2,360 |
|
|
|
2,043 |
|
|
|
- |
|
Other
|
|
|
316 |
|
|
|
1,407 |
|
|
|
- |
|
Balance at end of period
|
|
$ |
20,014 |
|
|
$ |
23,595 |
|
|
$ |
- |
|
Revisions in 2011 of previous quantity estimates relate principally to the exclusion of certain proven undeveloped well locations that were included in the reserve estimates dated December 31, 2010.
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
NOTE 16- QUARTERLY RESULTS (UNAUDITED)
The following tables contain selected unaudited statement of operations information for each quarter of 2011 and 2010. The Company believes that the following information reflects all normal recurring adjustments necessary for a fair presentation of the information for the periods presented. The operating results for any quarter are not necessarily indicative of results for any future period.
|
Year Ended December 31, 2011
|
|
|
Fourth
|
|
Third
|
|
Second
|
|
First
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
1,944,454 |
|
|
$ |
2,630,933 |
|
|
$ |
2,811,429 |
|
|
$ |
1,273,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(6,297,854 |
) |
|
|
(939,330 |
) |
|
|
(4,069,541 |
) |
|
|
(2,052,133 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
|
(7,295,537 |
) |
|
|
(3,027,618 |
) |
|
|
(4,762,881 |
) |
|
|
(3,743,187 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$ |
(0.47 |
) |
|
$ |
(0.19 |
) |
|
$ |
(0.30 |
) |
|
$ |
(0.25 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
|
15,543,758 |
|
|
|
15,775,135 |
|
|
|
15,635,346 |
|
|
|
14,778,206 |
|
|
Year Ended December 31, 2010
|
|
|
Fourth
|
|
Third
|
|
Second
|
|
First
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
1,519,702 |
|
|
$ |
2,552,790 |
|
|
$ |
5,194,849 |
|
|
$ |
490,351 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(4,191,728 |
) |
|
|
(5,900,630 |
) |
|
|
(792,880 |
) |
|
|
(2,242,252 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
|
(6,230,293 |
) |
|
|
(7,491,246 |
) |
|
|
(3,196,779 |
) |
|
|
(2,820,715 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$ |
(1.47 |
) |
|
$ |
(2.53 |
) |
|
$ |
(1.99 |
) |
|
$ |
(1.04 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
|
9,167,803 |
|
|
|
2,962,882 |
|
|
|
6,362,922 |
|
|
|
2,927,759 |
|
RECOVERY ENERGY, INC.
(UNAUDITED)
|
|
September 30,
|
|
December 31,
|
|
|
|
2012
|
|
2011
|
|
Assets
|
|
Current assets
|
|
|
|
|
|
|
Cash
|
|
$ |
698,276 |
|
|
$ |
2,707,722 |
|
Restricted cash
|
|
|
949,618 |
|
|
|
932,165 |
|
Accounts receivable
|
|
|
1,217,181 |
|
|
|
2,227,466 |
|
Prepaid assets
|
|
|
96,671 |
|
|
|
75,376 |
|
Commodity price derivative receivable
|
|
|
370,000 |
|
|
|
- |
|
Total current assets
|
|
|
3,331,746 |
|
|
|
5,942,729 |
|
|
|
|
|
|
|
|
|
|
Oil and gas properties (full cost method), at cost:
|
|
|
|
|
|
|
|
|
Unevaluated properties
|
|
|
43,541,930 |
|
|
|
45,697,481 |
|
Evaluated properties
|
|
|
40,460,933 |
|
|
|
32,113,143 |
|
Wells in progress
|
|
|
3,986,919 |
|
|
|
6,425,509 |
|
Total oil and gas properties, at cost
|
|
|
87,989,782 |
|
|
|
84,236,133 |
|
|
|
|
|
|
|
|
|
|
Less accumulated depreciation, depletion ,amortization, and impairment
|
|
|
(18,174,968 |
) |
|
|
(12,099,098 |
) |
Net oil and gas properties, at cost
|
|
|
69,814,814 |
|
|
|
72,137,035 |
|
|
|
|
|
|
|
|
|
|
Other assets:
|
|
|
|
|
|
|
|
|
Office equipment, net
|
|
|
95,980 |
|
|
|
106,286 |
|
Prepaid advisory fees
|
|
|
304,402 |
|
|
|
574,160 |
|
Deferred financing costs, net
|
|
|
1,026,192 |
|
|
|
2,341,595 |
|
Restricted cash and deposits
|
|
|
186,240 |
|
|
|
186,055 |
|
Total other assets
|
|
|
1,612,814 |
|
|
|
3,208,096 |
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
74,759,374 |
|
|
$ |
81,287,860 |
|
The accompanying notes are an integral part of these consolidated financial statements
RECOVERY ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2012
|
|
|
2011
|
|
Liabilities and Shareholders' Equity
|
|
Current liabilities
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
1,183,415 |
|
|
$ |
2,050,768 |
|
Commodity price derivative liability
|
|
|
- |
|
|
|
75,609 |
|
Related party payable
|
|
|
- |
|
|
|
16,475 |
|
Accrued expenses
|
|
|
2,183,053 |
|
|
|
1,354,204 |
|
Short term loans payable
|
|
|
873,142 |
|
|
|
1,150,967 |
|
Total current liabilities
|
|
|
4,239,610 |
|
|
|
4,648,023 |
|
|
|
|
|
|
|
|
|
|
Long term liabilities
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
|
893,754 |
|
|
|
612,874 |
|
Term loans payable
|
|
|
19,419,197 |
|
|
|
20,129,670 |
|
Convertible debentures notes payable, net of discount
|
|
|
9,595,053 |
|
|
|
4,929,068 |
|
Convertible debentures conversion derivative liability
|
|
|
1,300,000 |
|
|
|
1,300,000 |
|
Total long-term liabilities
|
|
|
31,208,004 |
|
|
|
26,971,612 |
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
35,447,614 |
|
|
|
31,619,635 |
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies – Note 8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders’ equity
|
|
|
|
|
|
|
|
|
Preferred stock, 10,000,000 authorized, none issued and outstanding as of September 30, 2012 and December 31, 2011
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Common stock, $0.0001 par value: 100,000,000 shares authorized; 18,016,143 and 17,436,825 shares issued and outstanding as of September 30, 2012 and December 31, 2011, respectively
|
|
|
1,801 |
|
|
|
1,744 |
|
Additional paid in capital
|
|
|
120,566,897 |
|
|
|
118,146,119 |
|
Accumulated deficit
|
|
|
(81,256,938 |
) |
|
|
(68,479,638 |
) |
Total shareholders' equity
|
|
|
39,311,760 |
|
|
|
49,668,225 |
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders’ equity
|
|
$ |
74,759,374 |
|
|
$ |
81,287,860 |
|
The accompanying notes are an integral part of these consolidated financial statements
RECOVERY ENERGY, INC.
(UNAUDITED)
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$ |
1,775,383 |
|
|
$ |
1,650,702 |
|
|
$ |
4,685,713 |
|
|
$ |
5,534,325 |
|
Gas sales
|
|
|
168,897 |
|
|
|
161,029 |
|
|
|
397,298 |
|
|
|
446,386 |
|
Operating fees
|
|
|
42,853 |
|
|
|
85,372 |
|
|
|
132,362 |
|
|
|
110,282 |
|
Realized gain on commodity price derivatives
|
|
|
37,341 |
|
|
|
733,830 |
|
|
|
49,729 |
|
|
|
402,256 |
|
Unrealized gains (losses) on commodity price derivatives
|
|
|
(130,000 |
) |
|
|
- |
|
|
|
445,609 |
|
|
|
222,788 |
|
Total Revenues
|
|
|
1,894,474 |
|
|
|
2,630,933 |
|
|
|
5,710,711 |
|
|
|
6,716,037 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
397,793 |
|
|
|
344,927 |
|
|
|
1,033,635 |
|
|
|
1,114,220 |
|
Production taxes
|
|
|
198,781 |
|
|
|
191,364 |
|
|
|
561,278 |
|
|
|
630,718 |
|
General and administrative
|
|
|
1,515,868 |
|
|
|
1,981,026 |
|
|
|
5,099,932 |
|
|
|
8,837,802 |
|
Depreciation, depletion and amortization
|
|
|
1,069,068 |
|
|
|
1,052,946 |
|
|
|
2,897,156 |
|
|
|
3,194,301 |
|
Impairment of evaluated properties
|
|
|
- |
|
|
|
- |
|
|
|
3,274,718 |
|
|
|
- |
|
Total costs and expenses
|
|
|
3,181,510 |
|
|
|
3,570,263 |
|
|
|
12,866,719 |
|
|
|
13,777,041 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from operations
|
|
|
(1,287,036 |
) |
|
|
(939,330 |
) |
|
|
(7,156,008 |
) |
|
|
(7,061,004 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
333 |
|
|
|
62,000 |
|
|
|
(372 |
) |
|
|
63,115 |
|
Convertible debentures conversion derivative gain (losses)
|
|
|
600,000 |
|
|
|
(13,338 |
) |
|
|
700,000 |
|
|
|
1,587,699 |
|
Interest expense
|
|
|
(2,149,931 |
) |
|
|
(2,136,950 |
) |
|
|
(6,320,919 |
) |
|
|
(6,123,496 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss
|
|
$ |
(2,836,634 |
) |
|
$ |
(3,027,618 |
) |
|
$ |
(12,777,299 |
) |
|
$ |
(11,533,686 |
) |
Net loss per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$ |
(0.16 |
) |
|
$ |
(0.19 |
) |
|
$ |
(0.72 |
) |
|
$ |
(0.75 |
) |
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
|
17,833,466
|
|
|
|
15,775,135 |
|
|
|
17,732,304 |
|
|
|
15,388,772 |
|
The accompanying notes are an integral part of these consolidated financial statements
RECOVERY ENERGY, INC.
(UNAUDITED)
|
|
Nine months ended September 30,
|
|
|
|
2012
|
|
|
2011
|
|
Cash flows provided by (used in) operating activities:
|
|
|
|
|
|
|
Net loss
|
|
$ |
(12,777,299 |
) |
|
$ |
(11,533,686 |
) |
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
|
|
|
|
|
|
|
|
|
Amortization of stock issued for services
|
|
|
707,504 |
|
|
|
373,234 |
|
Share based compensation
|
|
|
1,066,154 |
|
|
|
5,592,638 |
|
Impairment of evaluated properties
|
|
|
3,274,718 |
|
|
|
- |
|
Change in fair value of commodity price derivatives
|
|
|
(445,609 |
) |
|
|
(398,840 |
) |
Change in fair value of convertible debentures conversion derivative
|
|
|
(700,000 |
) |
|
|
(1,587,699 |
) |
Amortization of deferred financing costs, issuance of stock for convertible debentures interest, and accretion of debt discount
|
|
|
3,843,457 |
|
|
|
3,701,373 |
|
Depreciation, depletion, amortization and accretion
|
|
|
2,897,156 |
|
|
|
3,194,301 |
|
|
|
|
|
|
|
|
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(433,567 |
) |
|
|
(891,076 |
) |
Other assets
|
|
|
(21,294 |
) |
|
|
(19,674 |
) |
Accounts payable and other accruals
|
|
|
(867,353 |
) |
|
|
2,428,101 |
|
Restricted cash
|
|
|
(17,453 |
) |
|
|
144,001 |
|
Related party payable
|
|
|
(16,475 |
) |
|
|
15,067 |
|
Accrued expenses
|
|
|
742,982 |
|
|
|
297,330 |
|
Net cash provided by (used in) operating activities
|
|
|
(2,747,079 |
) |
|
|
1,315,070 |
|
|
|
|
|
|
|
|
|
|
Cash flows used in investing activities:
|
|
|
|
|
|
|
|
|
Acquisition of undeveloped properties
|
|
|
(436,023 |
) |
|
|
(9,033,007 |
) |
Sale of unevaluated properties
|
|
|
1,443,852 |
|
|
|
- |
|
Investment in operating bonds
|
|
|
(184 |
) |
|
|
(160 |
) |
Drilling capital expenditures
|
|
|
(4,278,785 |
) |
|
|
(6,876,232 |
) |
Additions of office equipment
|
|
|
(2,928 |
) |
|
|
(40,648 |
) |
Net cash used in investing activities
|
|
|
(3,274,068 |
) |
|
|
(15,950,047 |
) |
|
|
|
|
|
|
|
|
|
Cash flows provided by (used in) financing activities:
|
|
|
|
|
|
|
|
|
Proceeds from sale of common stock, units and exercise of warrants
|
|
|
- |
|
|
|
2,129,801 |
|
Net change in debts
|
|
|
(988,299 |
) |
|
|
(377,498 |
) |
Proceeds from debts
|
|
|
5,000,000 |
|
|
|
8,000,000 |
|
Net cash provided by (used in) financing activities
|
|
|
4,011,701 |
|
|
|
9,752,303 |
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
|
(2,009,446 |
) |
|
|
(4,882,674 |
) |
Cash and cash equivalents at beginning of period
|
|
|
2,707,722 |
|
|
|
5,528,744 |
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$ |
698,276 |
|
|
$ |
646,070 |
|
The accompanying notes are an integral part of these consolidated financial statements
RECOVERY ENERGY, INC.
AS OF SEPTEMBER 30, 2012
(UNAUDITED)
NOTE 1 – ORGANIZATION
Recovery Energy, Inc. (“Recovery”, “ours”, “us” or the “Company”), a Nevada corporation, is an independent oil and gas company engaged in the exploration, development and production of crude oil and natural gas. The Company has focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 126,000 net acres located in Wyoming, Colorado, and Nebraska.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying unaudited interim consolidated financial statements were prepared by Recovery in accordance with generally accepted accounting principles (“GAAP”) in the United States applicable to interim financial statements 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 results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year. Such financial statements conform to the presentation reflected in the Company's Annual Report on Form 10-K/A filed with the Securities and Exchange Commission (the "SEC") for the year ended December 31, 2011. The current interim period reported herein should be read in conjunction with the financial statements and summary of significant accounting policies and notes included in the Company's Annual Report on Form 10-K/A.
All common stock share information is retroactively adjusted for the effect of a 4:1 reverse stock split that was effective October 19, 2011.
Reclassification
Certain amounts in the December 31, 2011 consolidated financial statements have been reclassified to conform to the September 30, 2012 consolidated financial statement presentation. Such reclassifications had no effect on net income.
Principles of Consolidation
The accompanying consolidated financial statements include Recovery Energy, Inc. and its wholly−owned subsidiaries Recovery Oil and Gas, LLC, and Recovery Energy Services, LLC. All intercompany accounts and transactions have been eliminated in consolidation. Both subsidiaries were inactive and were dissolved in the fourth quarter of 2011.
Use of Estimates
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 ongoing 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 issuances of common stock, warrants and the valuation of the conversion rights related to the convertible debentures payable.
Liquidity
Cash used in operating activities during the nine months 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.)
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF SEPTEMBER 30, 2012
(UNAUDITED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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.
Oil and Gas Producing Activities
The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration, development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.
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. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that are not otherwise included in capitalized costs.
The costs of unevaluated properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties or the amount of the impairment is added to full cost pool which is subject to depletion calculations.
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 sum of i.) the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves, plus ii.) the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized.
The present value of estimated future net revenues was computed by applying a twelve month average of the first day of the month price of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.
The Company recognized impairment charges of $3.27 million during the nine months ended September 30, 2012.
Wells in Progress
Wells in progress represent wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations. During the nine months ended September 30, 2012, the Company transferred $4.98 million of costs from wells in progress in to the full cost pool.
Loss per Common Share
Earnings (losses) per share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earnings (losses) per share are computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares. Potentially dilutive securities, such as conversion derivatives and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive. As of September 30, 2012, a total of 6,238,900 and 3,152,941, respectively of outstanding warrants and derivative shares related to convertible debentures payable have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. Accordingly, basic shares equal diluted shares for all periods presented.
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF SEPTEMBER 30, 2012
(UNAUDITED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recent Accounting Pronouncements
The Company evaluates the pronouncements of various authoritative accounting organizations to determine the impact of new GAAP pronouncements and the impact on the Company.
In December 2011, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company is required to implement this guidance effective for the first quarter of fiscal 2014 and does not expect the adoption of ASU 2011-11 to have a material impact on its financial statements.
Various other accounting standards updates recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, are not expected to a have a material impact on the Company's financial position, results of operations or cash flows.
NOTE 3 – OIL AND GAS PROPERTIES
The Company did not complete any major purchases of undeveloped or producing oil and gas properties during the nine and three months ended September 30, 2012.
Effective December 31, 2011, the Company sold 2,838 net acres of undeveloped leases for consideration of approximately $4.5 million. An initial closing occurred on December 31, 2011, resulting in the Company receiving a cash payment on that date of $3.1 million. The final closing of this transaction occurred during the three months ended March 31, 2012, at which time the Company received additional net proceeds, after deductions of all closing expenses, of $1.4 million.
NOTE 4 – WELLS IN PROGRESS
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.
NOTE 5 - FINANCIAL INSTRUMENTS AND DERIVATIVES
The Company periodically enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. As of September 30, 2012, the Company maintained an active commodity swap for 100 barrels per day through December 31, 2012 at a price of $96.25 per barrel, a swap for 100 barrels per day for the period of January 1, 2013 through June 30, 2013 at a price of $106.25 per barrel, and a swap for 100 barrels per day for the period of January 1, 2013 through December 31, 2013 at a price of $96.90.
The amounts of gains and losses recognized as a result of our derivative financial instruments were as follows:
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF SEPTEMBER 30, 2012
(UNAUDITED)
NOTE 5 - FINANCIAL IN-STRUMENTS AND DERIVATIVES (Continued)
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
Realized gain on commodity price derivatives
|
|
$ |
37,341 |
|
|
$ |
733,830 |
|
|
$ |
49,729 |
|
|
$ |
402,256 |
|
Unrealized gains (losses) on commodity price derivatives
|
|
$ |
(130,000 |
) |
|
$ |
- |
|
|
$ |
445,609 |
|
|
$ |
222,788 |
|
Realized gains and losses occur as individual swaps mature and settle. These gains and losses are recorded as income or expenses in the periods during which applicable contracts settle. Swaps which are unsettled as of a balance sheet date are carried at fair market value, either as an asset or liability (See Note 6 — “Fair Value of Financial Instruments”). Unrealized gains and losses result from mark-to-market changes in the fair value of these derivatives between balance sheet dates. On November 5, 2012, the company liquidated all of its price derivatives for proceeds of $0.60 million.
NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs, used in the valuation methodologies in measuring fair value:
● Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
● Level 2 – Other inputs that are directly or indirectly observable in the marketplace.
● Level 3 – Unobservable inputs which are supported by little or no market activity.
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
The Company measures its cash equivalents and investments at fair value. The Company’s cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits are primarily classified within Level 1. Cash equivalents and short-term investments are valued primarily using quoted market prices utilizing market observable inputs.
Derivative Instruments
The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, and the credit rating of its counterparty. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.
In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
At September 30, 2012, the types of derivative instruments utilized by the Company included commodity swaps. The oil derivative markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF SEPTEMBER 30, 2012
(UNAUDITED)
NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
Asset Retirement Obligation
The income valuation technique is utilized to determine the fair value of its asset retirement obligation liability at the point of inception by taking into account: 1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which are based on estimates from reserve engineers; 3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.
Convertible Debentures Payable Conversion Feature
In February 2011, the Company issued in a private placement $8.40 million aggregate principal amount of three year 8% Senior Secured Convertible Debentures (“Debentures”) with a group of accredited investors. During the nine months ended September 30, 2012, the Company issued an additional $5.00 million of Debentures, resulting in a total of $13.40 million of Debentures outstanding as of September 30, 2012. As of September 30, 2012, the Debentures are convertible at any time at the holders’ option into shares of our common stock at $4.25 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. The Company engaged a third party to complete a valuation of this conversion feature as of September 30, 2012 (see Note 7—Loan Agreements). The valuation was completed using Level 3 inputs.
The following table provides a summary of the fair values of assets and liabilities measured at fair value:
September 30, 2012
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
Assets
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
-
|
|
|
$
|
370,000
|
|
|
$
|
-
|
|
|
$
|
370,000
|
|
Total assets, at fair value
|
|
$
|
-
|
|
|
$
|
370,000
|
|
|
$
|
-
|
|
|
$
|
370,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible debentures conversion derivative liability
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(1,300,000
|
)
|
|
$
|
(1,300,000
|
)
|
Total liability, at fair value
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(1,300,000
|
)
|
|
$
|
(1,300,000
|
)
|
December 31, 2011
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
Liability
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
-
|
|
|
$
|
(75,609
|
)
|
|
|
-
|
|
|
$
|
(75,609
|
)
|
Convertible debentures conversion derivative liability
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,300,000
|
)
|
|
|
(1,300,000
|
)
|
Total liability at fair value
|
|
$
|
-
|
|
|
$
|
(75,609
|
)
|
|
$
|
(1,300,000
|
)
|
|
$
|
(1,375,609
|
)
|
The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of September 30, 2012:
Beginning balance, December 31, 2011
|
|
$ |
(1,300,000 |
) |
Convertible debentures conversion derivative gain
|
|
|
700,000 |
|
Additions to derivative liability from Supplemental Debenture
|
|
|
(700,000 |
) |
Ending balance, September 30, 2012
|
|
$ |
(1,300,000 |
) |
The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the nine and three months ended September 30, 2012.
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF SEPTEMBER 30, 2012
(UNAUDITED)
NOTE 7 – LOAN AGREEMENTS
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 date of the loans 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 there with, the Company agreed to make minimum monthly note 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 of the loans 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 the current portion of long term debt.
The Company is subject to certain 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 Debentures. 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.
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF SEPTEMBER 30, 2012
(UNAUDITED)
NOTE 7 – LOAN AGREEMENTS (Continued)
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 Supplemental 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.
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF SEPTEMBER 30, 2012
(UNAUDITED)
NOTE 7 – LOAN AGREEMENTS (Continued)
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 three months ended September 30, 2012 and 2011, the Company incurred interest expense of approximately $2.15 million and $2.14 million, respectively, of which approximately $1.29 million and $1.50 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 $3.8 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.
NOTE 8 - COMMITMENTS AND CONTINGENCIES
Environmental and Governmental Regulation
At September 30, 2012, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates, and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of September 30, 2012, the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.
Legal Proceedings
The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial positions of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.
Other Contingencies
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.
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF SEPTEMBER 30, 2012
(UNAUDITED)
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 provision required to satisfy this provision will be approximately $3.3 million.
NOTE 9 - SHAREHOLDERS’ EQUITY
Common Stock
Effective October 19, 2011, the Company completed a four-for-one reverse stock split of its common shares. All references to common stock and common stock prices have been adjusted to reflect the effects of the reverse stock split.
As of September 30, 2012, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 18,016,143 shares of common stock were issued and outstanding. No preferred shares were issued or outstanding.
During the nine months ended September 30, 2012, the Company granted 356,865 shares of common stock as restricted stock grants to employees, board members, and consultants valued at $1.49 million. The Company also issued 197,619 shares for payment of quarterly interest expense on the convertible debentures valued at $0.69 million, and 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as placement agent of the Supplemental Debentures.
Warrants
During September 2012, the Company entered into an agreement to issue 600,000 warrants to a financial advisory group. The 600,000 warrants vest monthly in six equal amounts over the six month term of the agreement, have a term of 3 years, and a strike price of $5.00 per share. The Company records an expense for the value of the warrants on each vesting date. During the three months ended September 30, 2012, the Company recorded an expense of $0.08 million for the 100,000 warrants that were vested as of September 30, 2012. Additionally, the agreement provides that the Company will pay a monthly consulting fee of $10,000, with a final payment of $90,000 during the last month of the contract. The Company may cancel the agreement at any time to avoid any future cash payments or vesting of remaining unvested warrants.
A summary of warrant activity for the nine months ended September 30, 2012 is presented below:
|
|
|
|
|
Weighted-Average
|
|
|
|
Warrants
|
|
|
Exercise Price
|
|
Outstanding at December 31, 2011
|
|
|
5,638,900
|
|
|
$
|
7.04
|
|
Granted
|
|
|
600,000
|
|
|
|
5.00
|
|
Exercised, forfeited, or expired
|
|
|
-
|
|
|
|
-
|
|
Outstanding at September 30, 2012
|
|
|
6,238,900
|
|
|
$
|
6.84
|
|
The aggregate intrinsic value of the warrants was approximately $0 as of both September 30, 2012 and December 31, 2011, based on the Company’s closing common stock price of $4.40 and $3.01, respectively; and the weighted average remaining contract life was 2.81 years and 3.18 years, respectively.
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF SEPTEMBER 30, 2012
(UNAUDITED)
NOTE 10 - SHARE BASED COMPENSATION
In September 2012, the Company adopted the 2012 Equity Incentive Plan (the “Plan”). Each member of the board of directors and the management team has been periodically awarded restricted stock grants, and in the future will be awarded such grants under the terms of the Plan.
The costs of employee services received in exchange for an award of equity instruments are based on the grant-date fair value of the award, recognized over the period during which an employee is required to provide services in exchange for such award.
During the nine months ended September 30, 2012, the Company granted 256,866 shares of restricted common stock to employees and directors of which 52,698, 81,250, 81,250, and 25,001 shares vest during the years ended December 31, 2012, 2013, 2014, and 2015, respectively. The fair value of these share grants was calculated to be approximately $0.78 million. The Company also granted 100,000 shares to a consultant and 50,000 shares to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures, valued at $0.58 million
The Company recognized stock compensation expense of approximately $0.80 million and $0.37 million, respectively for the nine and three months ended September 30, 2012, and $5.59 million, and $0.92 million, respectively for the nine and three months ended September 30, 2011.
A summary of restricted stock grant activity for the nine months ended September 30, 2012 is presented below:
|
|
Shares
|
|
Balance outstanding at December 31, 2011
|
|
|
2,340,235
|
|
Granted
|
|
|
356,865
|
|
Vested
|
|
|
(385,749
|
)
|
Expired
|
|
|
(25,167
|
)
|
Balance outstanding at September 30, 2012
|
|
|
2,286,184
|
|
Total unrecognized compensation cost related to unvested stock grants was approximately $2.187 million as of September 30, 2012. The cost at September 30, 2012 is expected to be recognized over a weighted-average remaining service period of 3 years.
NOTE 11—SUBSEQUENT EVENTS
On November 5, 2012, the Company liquidated all of its price derivatives for proceeds of $0.60 million.