XNAS:RECV Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.20549
_______________
 
FORM 10-Q
_______________
 
x   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2012
 
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For the transition period from ______to______.
 
RECOVERY ENERGY, INC.
 (Exact name of registrant as specified in Charter)
 
NEVADA
 
333-152571
 
74-3231613
(State or other jurisdiction of incorporation or organization)
 
(Commission File No.)
 
(IRS Employee Identification No.)

1515 Wynkoop Street, Suite 200
Denver, CO80202
 (Address of Principal Executive Offices)
 _______________
 
(303) 951-7920
 (Issuer Telephone number)
_______________

Check whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the issuer was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company filer.  See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one):
 
Large Accelerated Filer o    Accelerated Filer x     Non-Accelerated Filer o     Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company as defined in Rule 12b-2 of the Exchange Act. Yes o  No x
 
State the number of shares outstanding of each of the issuer’s classes of common equity, as of August 1, 2012: 17,868,506 shares of Common Stock.  
 
 
 

 
 
Recovery Energy, Inc.

INDEX
 
PART I– FINANCIAL INFORMATION
 
Item 1.
Financial Statements (Unaudited)
 
 
Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011
1
 
Consolidated Statements of Operations for the three and six months ended June 30, 2012 and 2011
3
 
Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011
4
 
Notes to Consolidated Financial Statements
5
Item 2.
Management’s Discussion and Analysis of Financial Condition
15
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
30
Item 4.
Control and Procedures
31
 
PART II– OTHER INFORMATION
 
Item 1.
Legal Proceedings
32
Item 1A.
Risk Factors
32
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
33
Item 3.
Defaults Upon Senior Securities
33
Item 4.
Mine Safety Disclosures
33
Item 5.
Other Information
33
Item 6.
Exhibits and Reports on Form 8-K
33
 
SIGNATURES
 
 
 

 
 
Part 1. Financial Information
Item 1. Financial Statements

RECOVERY ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

 
    June 30,     December 31,  
    2012     2011  
Assets  
Current assets
           
  Cash
  $ 467,181     $ 2,707,722  
  Restricted cash
    864,669       932,165  
  Accounts receivable
    1,025,444       2,227,466  
  Commodity price derivative receivable
    500,000       -  
  Prepaid assets
    9,363       75,376  
Total current assets
    2,866,657       5,942,729  
                 
Oil and gas properties (full cost method), at cost:
               
  Unevaluated properties
    43,458,255       45,697,481  
  Evaluated properties
    40,415,934       32,113,143  
  Wells in progress
    4,724,643       6,425,509  
Total oil and gas properties, at cost
    88,598,832       84,236,133  
                 
Less accumulated depreciation, depletion ,amortization, and impairment
    (17,169,889 )     (12,099,098 )
Net oil and gas properties, at cost
   
71,428,943
      72,137,035  
                 
Other assets:
               
  Office equipment, net
    98,965       106,286  
  Prepaid advisory fees
    418,069       574,160  
  Deferred financing costs, net
    1,082,079       2,341,595  
  Restricted cash and deposits
    186,240       186,055  
Total other assets
    1,785,353       3,208,096  
                 
Total Assets
  $
76,080,953
    $ 81,287,860  
 
The accompanying notes are an integral part of these consolidated financial statements
 
 
1

 
 
RECOVERY ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
 
    June 30,     December 31,  
    2012     2011  
Liabilities and Shareholders' Equity  
Current liabilities
           
  Accounts payable
  $ 2,130,385     $ 2,050,768  
  Commodity price derivative liability
    -       75,609  
  Related party payable
    -       16,475  
  Accrued expenses
    1,947,688       1,354,204  
  Short term notes payable
    840,509       1,150,967  
Total current liabilities
    4,918,582       4,648,023  
                 
Long term liabilities
               
  Asset retirement obligation
    685,761       612,874  
  Term notes payable
    19,643,894       20,129,670  
  Convertible notes payable, net of discount
    8,033,274       4,929,068  
  Convertible notes conversion derivative liability
    1,600,000       1,300,000  
Total long term liabilities
    29,962,929       26,971,612  
                 
Total liabilities
    34,881,511       31,619,635  
                 
 Commitments and contingencies – Note 8
               
                 
 Shareholders’ equity
               
  Preferred stock, 10,000,000 authorized, none issued and outstanding
    -       -  
                 
  Common stock, $0.0001 par value: 100,000,000 shares authorized; 17,868,506 and 17,436,825 shares issued and outstanding  as of June 30, 2012 and December 31, 2011, respectively 
    1,787       1,744  
  Additional paid in capital
    119,617,955       118,146,119  
  Accumulated deficit
    (78,420,300 )     (68,479,638 )
Total shareholders' equity
   
41,199,442
      49,668,225  
                 
Total Liabilities and Shareholders’ Equity
  $
76,080,953
    $ 81,287,860  
 
The accompanying notes are an integral part of these consolidated financial statements
 
 
2

 
 
RECOVERY ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 
 
   
Three months ended June 30,
   
Six months ended June 30,
 
   
2012
   
2011
   
2012
   
2011
 
Revenue
                       
Oil sales
  $ 1,362,566     $ 2,081,809     $ 2,910,329     $ 3,883,623  
Gas sales
    98,725       176,528       228,401       285,357  
Operating fees
    45,676       16,682       89,509       24,910  
Realized gain (loss) of
commodity price derivatives
    73,301       (164,290 )     12,389       (331,574 )
    Unrealized gains on commodity price derivatives
    680,000       700,700       575,609       222,788  
Total revenues
    2,260,268       2,811,429       3,816,237       4,085,104  
                                 
Costs and expenses
                               
Production costs
    268,315       322,308       635,842       769,293  
Production taxes
    169,639       237,055       362,497       439,354  
General and administrative
    1,561,800       5,256,182       3,584,064       6,856,776  
Depreciation, depletion and amortization
    843,999       1,065,425       1,828,087       2,141,355  
Impairment of evaluated properties
    -       -       3,274,718       -  
Total costs and expenses
    2,843,753       6,880,970       9,685,208       10,206,778  
                                 
Loss from operations
    (583,485 )     (4,069,541 )     (5,868,971 )     (6,121,674 )
                                 
Other income (expense)
    (1,123 )     -       (705 )     1,115  
Convertible notes conversion derivative gain (loss)
    (190,163 )     1,601,037       100,000       1,601,037  
Interest expense
    (2,038,082 )     (2,294,377 )     (4,170,988 )     (3,986,546 )
                                 
Net loss
  $ (2,812,853 )   $ (4,762,881 )   $ (9,940,664 )   $ (8,506,068 )
Net loss per common share
                               
Basic and diluted
  $ (0.16 )   $ (0.30 )   $ $(0.56 )   $ $(0.56 )
Weighted average shares outstanding:
                               
Basic and diluted
    17,745,155       15,635,346       17,629,491       15,192,389  
 
The accompanying notes are an integral part of these consolidated financial statements

 
3

 
 
RECOVERY ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
   
Six months ended June 30,
 
   
2012
   
2011
 
Cash flows used in operating activities:
           
  Net loss
  $ (9,940,664 )   $ (8,506,068 )
  Adjustments to reconcile net loss to net cash provided by operating activities:
               
  Amortization of stock issued for services
    493,606       251,412  
  Share based compensation
    692,048       4,675,332  
  Impairment of evaluated properties
   
3,274,718
      -  
  Change in fair value of commodity price derivatives
    (575,609 )     (222,788 )
  Change in fair value of convertible debentures conversion derivative
    (100,000 )     (1,601,037 )
  Amortization of deferred financing costs, issuance of stock for  convertible debentures interest and accretion of discount
    2,582,909       2,203,725  
  Depreciation, depletion and amortization
   
1,828,087
      2,141,355  
                 
Changes in operating assets and liabilities:
               
  Accounts receivable
    (241,830 )     (2,853,269 )
  Other assets
    77,498       (59,158 )
  Accounts payable and other accruals
    79,617       3,297,906  
  Restricted cash
    67,496       10,053  
  Related party payable
    (16,475 )     12,606  
  Accrued expenses
    507,618       (18,830 )
Net cash used in operating activities
    (1,270,981 )     (668,761 )
                 
Cash flows used in investing activities:
               
  Additions to unevaluated properties
    (320,333 )     (9,008,928 )
  Sale of unevaluated properties
    1,443,852       -  
  Investment in operating bonds
    (184 )     (160 )
  Drilling capital expenditures
    (4,135,812 )     (3,541,453 )
  Additions of office equipment
    (649 )     (25,411 )
Net cash used in investing activities
    (3,013,126 )     (12,575,952 )
                 
Cash flows provided by financing activities:
               
  Proceeds from sale of common stock, units and exercise of warrants
    -       2,129,801  
  Net change in debts
    (796,236 )     (88,677 )
  Proceeds from debts
    2,839,802       8,000,000  
Net cash provided by financing activities
    2,043,566       10,041,124  
                 
Change in cash and cash equivalents
    (2,240,541 )     (3,203,589 )
Cash and cash equivalents at beginning of period
    2,707,722       5,528,744  
                 
Cash and cash equivalents at end of period
  $ 467,181     $ 2,325,155  
 
The accompanying notes are an integral part of these consolidated financial statements
 
 
4

 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF JUNE 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 conducted its focus on the Denver-Julesburg Basin (“DJ Basin”) where it holds 123,000 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 Energy, Inc. 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 June 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 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 issuances of common stock, warrants and the valuation of the conversion rights related to the convertible notes payable.
 
 
5

 
 
Liquidity
 
Cash used in operating activities during the six months ending ended June 30, 2012 was $1.27 million; this use of cash, coupled with the cash used in investing activities, exceeded cash provided by financing activities by $2.24 million, and resulted in a corresponding decrease in cash.  This net use of cash also substantially contributed to a $3.35 million decrease in working capital as of June 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 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 (see Note 7—Loan Agreements).  As of June 30, 2012, $ 2.8 million of the amount has been funded.  In August 2012, the Company restructured some of the terms of this offering, and completed the $5.0 million offering, resulting in the issuance of $2.2 million in additional convertible debentures (see Note 11—Subsequent Events.)
 
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 September 30, 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.
 
 
6

 
 
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 six ended June 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 six months ended June 30, 2012, the Company transferred $3.8 million of costs from wells in progress in to the full cost pool.
 
Loss per Common Share
 
Earnings (loss) per share is computed based on the weighted average number of common shares outstanding during the period presented.  In addition to common shares outstanding, earnings per share and 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 conversion derivatives and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive.  As of June 30, 2012, a total of 5,638,900 and 2,644,659, 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.

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 six and three months ended June 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.
 
 
7

 
 
 
NOTE 4 – WELLS IN PROGRESS
 
As of June 30, 2012, we had four wells in progress, including 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 $3.9 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 June 30, 2012, the current carrying costs would exceed the ceiling and partially flow through the income statement as an expense if the well were assumed to be non-productive as of June 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 in 2013.
 
NOTE 5 - FINANCIAL IN-STRUMENTS 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 June 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, and an additional 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.

The amounts of gains and losses recognized as a result of our derivative financial instruments were as follows:

 
Three months ended June 30,
   
Six months ended
 June 30,
 
 
2012
   
2011
   
2012
   
2011
 
Realized gain on commodity price derivatives
  $
73,301
    $
(164,290
)   $
12,389
    $
(331,574
)
Unrealized gains (loss) on commodity price derivatives
  $
680,000
    $
700,700
    $
575,609
    $
222,788
 
 
Realized gains and losses occurs 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.
  
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.
 
 
8

 
 
 
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 June 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.

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 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 Notes 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 six months ended June 30, 2012, the Company issued an additional $2.8 million of convertible debentures, resulting in a total of $11.24 million of Debentures outstanding as of June 30, 2012.  As of June 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 June 30, 2012 (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:
 
June 30, 2012

 
Level 1
 
Level 2
 
Level 3
 
Total
 
Assets
               
Derivative instruments
  $ -     $ 500,000     $ -     $ 500,000  
Total assets, at fair value
  $ -     $ 500,000     $ -     $ 500,000  
Liability
                               
Convertible notes conversion derivative liability
    -        -       (1,600,000 )     (1,600,000 )
Total liability, at fair value
  $ -     $ -     $ (1,600,000 )   $ (1,600,000 )


 
9

 
 
December 31, 2011
 
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Liability
               
Derivative instruments
  $ -     $ (75,609 )     -     $ (75,609 )
Convertible notes 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 June 30, 2012:
 
   
Convertible debt feature
 
Beginning balances, December 31, 2011(1)
  $
(1,300,000)
 
Increase in convertible notes conversion derivative liability
   
(300,000) 
 
Ending balance as of June 30, 2012
  $
(1,600,000)
 

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 six and three months ended June 30, 2012. 
 
NOTE 7 - LOAN AGREEMENTS

Term Notes

The Company entered into three separate loan agreements with Hexagon during 2010.  All three loans bear annual interest of 15% and mature on September 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 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 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.

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.
 
 
10

 
 
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 extended the maturity of the notes 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 November 2011, Hexagon also temporarily advanced the Company an additional amount of $0.31 million, which was repaid in full in February 2012.  In July 2012, Hexagon extended the maturity date to September 30, 2013.

As of June 30, 2012, the total debt outstanding under these facilities is $20.48 million, of which $0.84 million is carried as 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 June 30, 2012, the Company was in compliance with all covenants under the facilities.  If any of the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default and accelerate all principal and interest outstanding.

Convertible Debentures Payable
 
In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of three year 8% Senior Secured Convertible Debentures (the "Debentures") with a group of accredited investors.  Initially, the Debentures were convertible at any time at the holders' option into shares of our common stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. Interest on the Debentures is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or at the Company's option in shares of common stock, valued at 95% of the volume weighted average price of the common stock for the 10 trading days prior to an interest payment date.  The Company can redeem some or all of the Debentures at any time.  The redemption price is 115% of principal plus accrued interest.  If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price will include a make-whole premium equal to the remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable in common stock. T.R. Winston & Company LLC acted as placement agent for the private placement and received $0.40 million of Debentures equal to 5% of the gross proceeds from the sale.  The Company is amortizing the $0.40 million over the life of the loan as deferred financing costs.  The Company amortized $0.06 million of deferred financing costs into interest expense during the six months ended June 30, 2012 and has $0.21 million of deferred financing costs to be amortized through February 2014. 
 
On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to increase the amount of its Debentures by up to an additional $5.0 million (the “Supplemental Debentures”).  Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of Supplemental Debentures are to be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other working capital purposes. Any new producing properties that are developed from the proceeds of Supplemental Debentures are to be pledged as collateral to secure future payment of the Supplemental Debentures. All terms of the Supplemental Debentures are substantively identical to the Debentures.

As of June 30, 2012, we received $2.80 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 $3.8 million.  Five of these wells resulted in commercial production, and one well was plugged and abandoned.
 
In August 2012, the Company restructured the terms of the Supplemental Debenture offering and concluded the offering by issuing an additional $2.2 million of Supplemental Debentures (see Note 11— Subsequent Events.)
 
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 Debentures and Supplemental Debentures are currently convertible into 2,644,659 shares of common stock. This amendment was 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.
 
 
11

 
 
We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect to June 30, 2012, the Supplemental Debentures.    This valuation resulted in an estimated derivative liability as of June 30, 2012 and December 31, 2011 of $1.6 million and $1.3 million, respectively.  The portion of the derivative liability that is associated with the Supplemental Debentures, in the approximate amount of $0.40 million, has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.
 
As of June 30, 2012 and December 31, 2011, the convertible debt is recorded as follows:
 
   
As of
   
As of
 
   
June 30, 2012
    December 31, 2011  
Convertible debentures
  $ 11,239,802     $ 8,400,000  
Debt discount
    (3,206,528 )     (3,470,932 )
Total convertible debentures, net
  $ 8,033,274     $ 4,929,068  

Annual debt maturities for our debt under our term notes and convertible notes payable obligations as of June 30, 2012 are as follows:

Year 1
  $ 840,508  
Year 2
    30,883,697  
Thereafter
    --  
Total
  $ 31,724,205  

Interest Expense

For the three months ended June 30, 2012 and 2011, the Company incurred interest expense of approximately $2.04 million and $2.29 million, respectively, of which approximately $1.30 million and $1.37 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible notes payable discount, and convertible notes payable interest paid in stock.

For the six months ended June 30, 2012 and 2011, the Company incurred interest expense of approximately $4.17 million and $3.99 million, respectively, of which approximately $2.60 million and $2.20 million, respectively, were non-cash interest expense and 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 June 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 June 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.
 
 
12

 
 
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.
 
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 June 30, 2012, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 17,868,506 shares of common stock were issued and outstanding.  No preferred shares were issued or outstanding.  

During the six months ended June 30, 2012, the Company granted 343,750 shares of common stock as restricted stock grants to employees, board members, and consultants valued at $1.09 million.  The Company also issued 113,098 shares for payment of quarterly interest expense on the convertible debentures valued at $0.43 million for the six months ending June 30, 2012.

Warrants

A summary of warrant activity for the six months ended June 30, 2012 is presented below:
 
       
Weighted-Average
 
   
Warrants
 
Exercise Price
 
Outstanding at December 31, 2011
   
5,638,900
   
$
7.04
 
Granted
   
-
         
Exercised, forfeited, or expired
   
-
         
Outstanding at June 30, 2012
   
5,638,900
   
$
7.04
 
 
The aggregate intrinsic value of warrants was approximately $0 as of both June 30, 2012 and December 31, 2011, based on the Company’s closing common stock price of $2.76 and $3.01, respectively; and the weighted average remaining contract life was 3.06 years and 3.43 years, respectively.
 
NOTE 10 - SHARE BASED COMPENSATION

As of June 30, 2012, the Company has not adopted a stock incentive plan for its management team.  Each member of the board of directors and the management team has been periodically awarded restricted stock grants.
 
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.
 
 
13

 
 
 
During the six months ended June 30, 2012, the Company granted 243,750 shares of restricted common stock to employees and directors of which 109,375, 92,708, and 41,667 shares vest during the years ended December 31, 2013, 2014, and 2015, respectively. The fair value of these share grants was calculated to be approximately $0.43 million.  The Company also granted 100,000 shares to a consultant during the six months ended June 30, 2012.  These shares were valued at $0.35 million.

The Company recognized stock compensation expense of approximately $0.35 million and $0.69 million, respectively for the six and three months ended June 30, 2012, and $4.68 million, and $4.13 million, respectively for the six and three months ended June 30, 2011.
 
A summary of restricted stock grant activity for the six months ended June 30, 2012 is presented below:

   
Shares
 
Balance outstanding at December 31, 2011
    2,340,235  
Granted
    343,750  
Vested
    (353,884 )
Expired
    (25,167 )
Balance outstanding at June 30, 2012
    2,304,934  
 
Total unrecognized compensation cost related to unvested stock grants was approximately $2.718 million as of June 30, 2012.  The cost at June 30, 2012 is expected to be recognized over a weighted-average remaining service period of 3 years.
 
NOTE 11—SUBSEQUENT EVENTS
 
In August 2012, the Company agreed to restructure the Supplemental Debenture offering in order to secure funding of an additional $2.2 million.  Conclusion of these transactions resulted in total proceeds attributable to the Supplemental Debentures of $5.0 million, inclusive of the $2.8 million that had been received by the Company as of June 30, 2012.
 
Modifications to the Supplemental Debentures included increasing the original 5% carried working interest to 10% and adding a 15% net profits interest attributable to the first year of production from each well financed by the proceeds of the Supplemental Debentures, including in each case the wells drilled with the initial $2.8 million in the second quarter of 2012.  The holders of the Supplemental Debentures will also receive the same carried interest and one year of net profit interests on the next four wells the Company drills and completes (or plugs and abandons.)
 
The Company will record these transactions in its third quarter 2012 financial statements, and will include the estimated fair value of the carried working interests and net profits interest as a discount applicable to the convertible debentures.
 
 
14

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

  FORWARD-LOOKING STATEMENTS
 
This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to, any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations; any statements concerning future production, reserves or other resource development opportunities, any projected well performance or economics, or potential joint ventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements of belief; and any statements of assumptions underlying any of the foregoing.

Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “expect” or “anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this presentation. Except as required by law, we do not intend, and undertake no obligation, to update any forward-looking statement.

Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-looking statements, are subject to change and inherent risks and uncertainties. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in our amended Annual Report on Form 10-K/A for the year ended December 31, 2011.
 
The factors impacting these risks and uncertainties include, but are not limited to:

• estimated quantities and quality of oil and natural gas reserves;
• exploration, exploitation and development results;
• fluctuations in the price of oil and natural gas, including reductions in prices that would adversely affect our revenue, cash flow, liquidity and access to capital;
• availability of capital on an economic basis, or at all, to fund our capital needs;
• availability of, or delays related to, drilling, completion and production, personnel, supplies and equipment;
• the timing and amount of future production of oil and gas;
• the completion, timing and success of our drilling activity;
• the inability of management to effectively implement our strategies and business plans;
• potential default under our secured obligations or material debt agreements;
• lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements;
• declines in the values of our natural gas and oil properties resulting in write-downs;
• inability to hire or retain sufficient qualified operating field personnel;
• increases in interest rates or our cost of borrowing;
• deterioration in general or regional (especially Rocky Mountain) economic conditions;
• the strength and financial resources of our competitors;
• the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;
• inability to acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts;
• delays, denials or other problems relating to our receipt of operational consents and approvals from governmental entities and other parties;
• unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids;
• environmental liabilities;
• loss of senior management or technical personnel;
• adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations;
• changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate; and
• other factors, many of which are beyond our control.
 
Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.

For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, we urge you to carefully review and consider the disclosures made in the “Risk Factors” sections of our SEC filings, available free of charge at the SEC’s website (www.sec.gov).
 
We also may make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and the possibility of their occurring is not taken into consideration in the forward-looking statements.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward -looking statements, whether as a result of new information, future events, or otherwise.
 
 
15

 
 
Overview

Recovery Energy Inc. is a Denver based independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the Denver-Julesburg (“DJ”) Basin. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team and via the future exploration and development of the approximate 123,000 net acres of developed and undeveloped leases that are currently held by the Company, primarily in the northern DJ Basin.

Recent Developments
 
In February 2011, we issued in a private placement $8.4 million aggregate principal amount of three year 8% senior secured convertible debentures with a group of accredited investors.  In March 2012, some investors in the convertible debenture agreed to purchase up to $5.0 million of additional convertible debentures.  The additional capital (up to $5 million) to be provided by the expansion of the Convertible Debentures has been and is expected to be used to partially fund the 2012 Capital Budget, and specifically for the drilling and development of certain proven undeveloped and other properties held by the Company, and for general corporate purposes.  The initial funding under the March 2012 Agreement occurred in March and continued through June 2012 in the amount of $2.8 million.  These proceeds were used to fund the drilling and development of six new wells, resulting in a total investment of $3.8 million.  Five of these wells resulted in commercial production, and one well was plugged and abandoned.
 
In August 2012, the Company restructured the terms of the Supplemental Debenture offering and concluded the offering by issuing an additional $2.2 million of convertible debentures (see Note 11— Subsequent Events.)
 
In February 2012, the Company completed the sale of its Grover Prospect acreage.

In March 2012, Hexagon agreed to extend the maturity of its term notes to June 30, 2013, and in connection there with, we agreed to make minimum monthly note payments of $0.33 million, effective immediately. In July 2012, Hexagon agreed to extend the maturity of its term notes to September 30, 2013.

In April, 2012, we made the decision to temporarily abandon one of our unconventional Niobrara wells that was categorized as a well in progress as of December 31, 2011.  In conjunction with that decision, all capitalized drilling, completion and allocable lease costs related to this well in the amount of $4.8 million were transferred to developed properties.  This transfer of costs contributed to a $3.3 impairment charge of developed properties derived from the ceiling test completed as of March 31, 2012.
 
Results of Operations

Three Months Ended June 30, 2012 compared to the Three Months Ended June 30, 2011
 
The Company reported a net loss for the three months ended June 30, 2012 of approximately $2,813,000 compared to a net loss of approximately $4,763,000 for the three months ended June 30, 2011.
   
Three months ended June 30,
 
   
2012
   
2011
 
Revenues and other income:
           
  Oil sales
  $ 1,362,566     $ 2,081,809  
  Gas sales
    98,725       176,528  
  Realized (losses) on commodity hedges
    73,301       (164,290 )
  Unrealized (losses) on commodity price derivatives
    680,000       700,700  
  Other
    45,676       16,682  
Total revenues and other income 
    2,260,268       2,811,429  
Expenses:
               
  Production costs
    268,315       322,308  
  Production taxes
    169,639       237,055  
  General and administrative
    1,561,800       5,256,182  
  Depreciation, depletion and amortization
    843,999       1,065,425  
Total expenses
    2,843,753       6,880,970  
 Loss from continuing operations
    (583,485 )     (4,069,541 )
  Interest expense
    (2,038,082 )     (2,294,377 )
  Other
    (1,123 )     -  
  Conversion note derivative gain
    (190,163 )     1,601,037  
Net loss
  $ (2,812,853 )   $ (4,762,881 )
 
 
16

 
 
Oil and Gas Revenues and Production
Oil and gas revenues were $1.46 million for the three months ended June 30, 2012, as compared to $2.26 million for the three months ended June 30, 2011, a decrease of $.80 million, or 31%. Our production volume on a BOE basis was 20,858 for the three months ended June 30, 2012, as compared to 27,083 for the three months ended June 30, 2012 a decrease of 6,225 BOE, or 23%.  This decrease is primarily attributable to decline curves related to our Palm and State Line field wells, but partially offset by production from wells drilled during the three months ended June 30, 2012. The total decrease in revenue was caused by both a decrease in production volumes and a decrease in prices during the three months ended June 30, 2012. Oil price realization decreased by 21% from $94.05 to $74.70 per barrel from the three months ended June 30, 2012 and 2011. The decrease was offset by the Company realizing a gain on hedges of approximately $0.07 million during the three months ended June 30, 2012, compared to a realized hedge loss of approximately $0.164 million for the three months ended June 30, 2011.
 
A comparison of production and average prices for the three months ended June 30, 2012 and 2011, respectively, follows:
 
   
Three Months Ended
 
   
June 30,
 
   
2012
   
2011
 
Product:
           
Oil (Bbls)-volume
   
18,241
     
22,136
 
Oil (Bbls)- average price
 
$
74.70
   
$
94.05
 
                 
Natural Gas (Mcf)-volume
   
15,699
     
29,681
 
Natural Gas (Mcf)- average price
 
$
6.29
   
$
5.95
 
Barrels of oil equivalent (BOE)
   
20,858
     
27,083
 
Average daily net production (BOE)
   
229
     
298
 
 
Oil and gas production expenses, depreciation, depletion and amortization
 
   
Three Months Ended June 30,
 
Three Months Ended June 30,
 
   
2012
 
2011
 
   
(per BOE)
 
(per BOE)
 
Average price
 
$
73.57
   
$
77.32
 
                 
Production costs
   
12.86
   
 
  11.90
 
Production taxes
   
8.13
     
    8.75
 
Depletion and amortization
   
40.46 
     
  39.34
 
             
Total operating costs
   
61.45
   
 
  59.99
 
                 
Gross margin
 
$
12.12
   
$
 17.33
 
                 
Gross margin percentage
   
16
   
22%
 
 
 
17

 
 
Commodity Price Derivative Activities
Changes in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivative instruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted of swaps. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.

Commodity price derivative net realized gain was $0.07 million during the three months ended June 30, 2012, compared to a realized loss of $0.16 million for the three months ended June 30, 2011, for an increase in realized gain of $0.24 million, or 144% increase.  We also recorded an unrealized gain on commodity price derivatives of $0.68 million for the three months ended June 30, 2012 compared to a gain of $0.70 million during the three months ended June 30, 2011, for a decrease 3% of $0.02 million.

Production costs
Production costs were $0.27 million for the three months ended June 30, 2012, as compared to $0.32 million during the three months ended June 30, 2011, a change of $0.05 million, or 16%. Production costs decreased due to lower work over expenses incurred during the three months ended June 30, 2012 compared to the three months ended June 30, 2011.

Production taxes
Production taxes were $0.17 million for the three months ended June 30, 2012, as compared to $0.24 million during the three months ended June 30, 2011, a change of $0.07 million, or 29%. Production taxes decreased due to a decrease in oil and gas revenues of $1.52 million.

General and administrative expenses
General and administrative expenses were $1.56 million for the three months ended June 30, 2012, as compared to $5.26 million for the three months ended June 30, 2011, a decrease of $3.70 million, or 70%.  Our general and administrative expenses for the three months ended June 30, 2012 included approximately $0.35 million in non-cash compensation expense. General and administrative expenses for the three months ended June 30, 2011 included approximately $4.13 million in non-cash compensation expense.  Excluding non-cash components, cash general and administrative expenses were $1.03 million for the three months ended June 30, 2012 compared to $1.13 million for the three months ended June 30, 2011.  Cash general and administrative expenses during the three months ended June 30, 2012 decreased primarily as a result of a decrease in legal and accounting fees and third party fees related to transactions, but were also affected by general increases in other general and administrative expense areas.
 
Depreciation, depletion and amortization
Depreciation, depletion and amortization was $0.84 million for the three months ended June 30, 2012, as compared to $1.07 million during the three months ended June 30, 2011, a decrease of $0.23 million, or 21%. 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 $40.46 per BOE during the three months ended June 30, 2012, as compared to $39.34 during the three months ended June 30, 2011.

 
18

 
 
Interest Expense
Interest expense was $2.04 million during the three months ended June 30, 2012, compared to $2.29 million during the three months ended June 30, 2011, a decrease of $0.26 million, or 11%.  During the three months ended June 30, 2012, interest included non-cash charges of  $1.30 million, compared to $1.37 million in the comparable period of 2011.  Cash interest accruing on debt in 2012 decreased primarily as a result of lower average debt balances on term notes.

Six Months Ended June 30, 2012 compared to the Six Months Ended June 30, 2011
 
The Company reported a net loss for the six months ended June 30, 2012 of approximately $9,941,000 compared to a net loss of approximately $8,506,000 for the six months ended June 30, 2011.
 
   
Six months ended June 30,
 
   
2012
   
2011
 
Revenues and other income:
           
Oil sales
  $ 2,910,329     $ 3,883,623  
Gas sales
    228,401       285,357  
Realized (losses) on commodity hedges
    12,389       (331,574  
Unrealized (losses) on commodity price derivatives
    575,609       222,788  
Other
    89,509       24,910  
Total revenues and other income 
    3,816,237       4,085,104  
Expenses:
               
Production costs
    635,842       769,293  
Production taxes
    362,497       439,354  
General and administrative
    3,584,064       6,856,776  
Depreciation, depletion and amortization
    1,828,087       2,141,355  
Impairment of evaluated properties
    3,274,718       -  
Total expenses
    9,685,208       10,206,778  
                 
Loss from continuing operations
    (5,868,971 )     (6,121,674 )
Interest expense
    (4,170,988 )     (3,986,546 )
Other
    (705 )     1,115  
       Conversion note derivative gain
    (100,000 )     1,601,037  
Net loss
  $ (9,940,664 )   $ (8,506,068 )
 
Oil and Gas Revenues and Production
Oil and gas revenues were $3.14 million for the six months ended June 30, 2012, as compared to $4.17 million for the six months ended June 30, 2011, a decrease of $1.03 million, or 25%. Our production volume on a BOE basis was 40,149 for the six months ended June 30, 2012, as compared to 52,410 for the six months ended June 30, 2011 a decrease of 12,261 BOE, or 23%. This decrease is primarily attributable to decline curves related to our Palm and State Line field wells, but partially offset by production attributable to wells drilled during the six months ended June 30, 2012.
 
 
19

 
 
Production and average prices for the six months ended June 30, 2012 are presented in the following table:

 
Six Months Ended
 
 
June 30,
 
 
2012
 
2011
 
Product:
       
Oil (Bbls)-volume
   
34,368
      42,969  
Oil (Bbls)-average price
  $
84.60
    $ 90.38  
                 
Natural gas (Mcf)-volume
   
34,685
      56,650  
Natural gas (Mcf)-average price
  $
6.58
    $ 5.04  
Barrels of oil equivalent (BOE)
   
40,149
      52,410  
Average daily net production (BOE)
    221       290  

Oil and gas production expenses, depreciation, depletion and amortization
 
 
Six Months Ended June 30,
    Six Months
Ended June 30,
 
 
2012
    2011  
 
(per BOE)
    (per BOE)  
Average price
  $
78.49
    $ 73.22  
                 
Production costs
   
15.84
      14.68  
Production taxes
   
9.03
      8.38  
Depletion and amortization
   
45.53
      40.86  
                 
Total operating costs
   
70.40
      63.92  
                 
Gross margin
  $
8.09
    $ 9.30  
                 
Gross margin percentage
    10 %     13 %
 
Commodity Price Derivative Activities
Changes in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivative instruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted of swaps. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.

Commodity price derivative net realized gain was $0.01 million during the six months ended June 30, 2012, as compared to a realized loss of $0.33 million for the six months ended June 30, 2011, for an increase in realized gain of $0.34 million, or 104%.  We also recorded an unrealized gain on commodity price derivatives of $0.58 million for the six months ended June 30, 2012 compared to a gain of $0.22 million during the six months ended June 30, 2011.

Production costs
Production costs were $0.64 million during the six months ended June 30, 2012, as compared to $0.77 million for the six months ended June 30, 2012, a decrease of $0.13 million, or 17%.  Production costs decreased due to lower work over expenses during the six months ended June 30, 2012.
 
 
20

 
 
Production taxes
Production taxes were $0.36 million during the six months ended June 30, 2012, as compared to $0.44 million during the six months ended June 30, 2011, a decrease of $0.08 million, or 18%. Production taxes decreased due to the decrease of both revenues and BOE for the six months ended June 30, 2012.

General and administrative expenses
General and administrative expenses were $3.58 million for the six months ended June 30, 2012 compared to $6.86 million for the six months ended June 30, 2011, a decrease of $3.28 million, or 70%.  Our general and administrative expenses for the six months ended June 30, 2012 included approximately $0.69 million in non-cash compensation expense and $0.505 million for non-cash payment for consulting fees.  General and administrative expenses for the six months ended June 30, 2011 included approximately $4.68 million in non-cash compensation expense.  Excluding non-cash components, cash general and administrative expenses were $2.39 million for the six months ended June 30, 2012 compared to $2.17 million for the six months ended June 30, 2011.  Cash general and administrative expenses during the three months ended June 30, 2012 increased primarily as a result of a increases in payroll, legal and accounting fees and third party fees related to transactions, as well as general increases in other general and administrative expense areas.

Depreciation, depletion and amortization
Depreciation, depletion, and amortization were $1.83 million during the six months ended June 30, 2012, as compared to $2.14 million during the six months ended June 30, 2011, a decrease of $0.31 million, or 14.5%.  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 $45.53 per BOE during the six months ended June 30, 2012, as compared to $40.86 during the six months ended June 30, 2011.
 
Impairment of evaluated properties
Impairment of evaluated properties was $3.27 million during the six months ended June 30, 2012, as compared to no impairment during the six months ended June 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 $4.17 million during the six months ended June 30, 2012, compared to $3.99 million during the six months ended June 30, 2011, an increase of $0.18 million, or 5%.  During the six months ended June 30, 2012, interest included non-cash charges of $2.60 million, compared to $2.20 million for the six months ended June 30, 2011.  Cash interest accruing on debt in 2012 decreased primarily as a result of lower average term loan balances.

Liquidity and Capital Resources
 
Cash used in operating activities during the six months ending ended June 30, 2012 was $1.27 million; this use of cash, coupled with the cash used in investing activities, exceeded cash provided by financing activities by $2.24 million and resulted in a corresponding decrease in cash.  This net use of cash also substantially contributed to a $3.35 million decrease in working capital as of June 30, 2012 as compared to the working capital balance as of December 31, 2011.
 
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.  In March 2012, the Company secured commitments to fund up to $5 million of additional convertible debentures (see Note 7—Loan Agreements).  As of June 30, 2012, $2.8 million of the amount has been funded.  In August 2012, the Company restructured some of the terms of this offering, and completed the $5.0 million offering, resulting in the issuance of $2.2 million in additional convertible debentures (see Note 11— Subsequent Events.)
 
 
21

 
 
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 September 30, 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. 
 
2012 Capital Budget

Our anticipated 2012 capital expenditure budget is between $10-15 million, which is allocated primarily to the drilling and completion of oil and gas wells in the DJ Basin in Wyoming, Nebraska and Colorado targeting the conventional Dakota ‘D’ sand and Muddy ‘J’ sand targets.  In addition, approximately one-third of this budget may be directed toward additional development procedures on certain unconventional Niobrara shale properties. Through June 30, 2012, approximately $4.5 million has been expended and funded.  A complete allocation of the 2012 budget directed at Niobrara shale properties has not been determined at this time.
 
Our 2012 drilling program is designed to provide flexibility to accommodate both the timing of the securing of adequate capital and to identify suitable well locations.   We anticipate funding the 2012 capital program through a combination of the issuance of additional equity or debt securities, use of existing working capital and operating cash flows, and from cash provided by potential joint venture participants.  Approximately $5.0 million of the financing of the 2012 budget has already been secured via the March 2012 agreements that resulted in an increase in the convertible debentures, and the subsequent August 2012 amendment (see Note 11— Subsequent Events.)
 
Other factors that could cause us to further increase our level of activity and adjust our capital expenditure budget include a reduction in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, a further improvement in commodity prices or well performance that exceeds our forecasts, any of which could positively impact our operating cash flow. Factors that could cause us to reduce level of activity and adjust our capital budget include, but are not limited to, increases in service and materials costs, reductions in commodity prices or under-performance of wells relative to our forecasts, any of which could negatively impact our operating cash flow.
 
In order to fund the remainder of the 2012 budget, the Company will need to secure additional financing.  We may also choose to sell certain non-strategic assets in order to supplement the funding of our 2012 capital budget. 

We cannot give assurances that our working capital on hand, our cash flow from operations or any available capital or borrowings, equity offerings or other financings, or sales of non-strategic assets will be sufficient to fund our anticipated capital expenditures. If our existing and potential sources of investment capital  are not sufficient to undertake our planned 2012 capital expenditures, we may be required to reduce our 2012 drilling capital budget, curtail our expenditures and/or restructure our operations.

Capital Resources
 
Currently, the majority of our cash flows from operations are applied to the principal and interest of our loans.  Due to the continuing operating losses and the large amounts of capital expenditures during 2011 and continuing through 2012, our liquidity and working capital have deteriorated. While we believe that we have sufficient liquidity and capital resources to maintain our staff and continue our current production operations, we require additional capital to resolve our current working capital deficit and will also require substantial additional capital in order to fully test, develop and evaluate our 142,000 gross (123,000 net) undeveloped acres.  We expect to obtain this capital through a variety of sources, including, but not limited to, future debt and equity financings and potentially from future joint venture partners.  In the absence of near term major debt or equity financing or other similar transaction, we may be required to sell certain assets in order to meet obligations as they arise.  We can provide no assurance that we will be able to secure a major financing, nor can we predict the terms of any future potential financing transactions.
 
 
22

 
 
Information about our financial position is presented in the following table:
 
    June 30,
2012
    December 31,
2011
 
Financial Position Summary
           
Cash and cash equivalents
  $ 467,181     $ 2,707,722  
Working capital
  $ (2,051,925 )   $ 1,294,706  
Balance outstanding on term notes and convertible notes payable
  $ 31,724,205     $ 29,680,636  
Shareholders’ equity
  $
41,199,442
    $ 49,668,225  
 
During the six months ended June 30, 2012, our working capital decreased to $(2.05 million) from $1.29 million at December 31, 2011. The lower working capital and cash position is primarily the result of a deficit in cash provided by operating activities of $1.27 million and cash used by investing activities, but partially offset by cash provided by financing activities of $2.04 million.

A summary of cash flow results during the six months ended June 30, 2012 follows:
 
   
Six Months Ended
June 30,
 
   
2012
 
Cash provided by (used in):
     
Operating activities
  $ (1,270,981 )
Investing activities
    (3,013,126 )
Financing activities
    2,043,566  
         
Net change in cash
  $ (2,240,541 )

During the six months ended June 30, 2012, net cash used in operating activities was $1.27 million.  The primary changes in operating cash during the six months ended June 30, 2012 were $9.94 million of net loss, adjusted for non-cash charges of $1.83 million of depreciation, depletion and amortization expenses,  $1.19 million of stock-based compensation, $3.27 million of impairment of evaluated properties, $2.58 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 $0.10 million, and offset by a non-cash charge for the change in commodity price derivatives of $0.58 million.
 
During the six months ended June 30, 2012, net cash used in investing activities was $3.01 million. The primary changes in investing cash during the six months ended June 30, 2012 were $0.32 million related to our acquisitions of unproved acreage and drilling capital expenditures of $0.43 million, offset by the proceeds from the sale of undeveloped properties of $1.44 million.
 
 
23

 
 
During the six months ended June 30, 2012, net cash provided by financing activities was $2.04 million. The changes in financing cash during the six months ended June 30, 2012 were from net proceeds from the issuance of new convertible debentures of $2.84 million, offset by the net repayments of debt of $0.79 million.

Term Notes

The Company entered into three separate loan agreements with Hexagon during 2010.  All three loans bear annual interest of 15% and mature on September 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.
 
We entered into a loan modification agreement on May 28, 2010, which extended the maturity date of the loans to December 1, 2011.  In consideration for extending the maturity of the loans, Hexagon received 250,000 warrants with an exercise price of $6.00 per share.  The loan modification agreement also required the Company to issue 250,000 five year warrants to purchase common stock at $6.00 per share to Hexagon if the Company did not repay the loans in full by January 1, 2011. Since the loans were not paid in full by January 1, 2011, the Company issued 250,000 additional warrants with an exercise price of $6.00 per share to Hexagon which was valued at approximately $1.60 million.  This amount was recorded as a deferred financing cost and is being amortized over the remaining term of the loan.
 
In December 2010, Hexagon extended the maturity to September 1, 2011.  During the last half of 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2.0 million as payment on the notes. In November 2011, Hexagon extended the maturity to January 1, 2013.  In March 2012, Hexagon extended the maturity of the notes 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 November 2011, Hexagon also temporarily advanced the Company an additional amount of $0.31 million, which was repaid in full in February 2012.  In July 2012, Hexagon extended the maturity date to September 30, 2013.

As of June 30, 2012, the total debt outstanding under these facilities is $20.48 million, of which $0.84 million is carried as 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 June 30, 2012, the Company was in compliance with all covenants under the facilities.  If any of the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default and accelerate all principal and interest outstanding.

Convertible Debentures Payable

In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of three year 8% Senior Secured Convertible Debentures (the "Debentures") with a group of accredited investors.  Initially, the Debentures were convertible at any time at the holders' option into shares of our common stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. Interest on the Debentures is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or at the Company's option in shares of common stock, valued at 95% of the volume weighted average price of the common stock for the 10 trading days prior to an interest payment date.  The Company can redeem some or all of the Debentures at any time.  The redemption price is 115% of principal plus accrued interest.  If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price will include a make-whole premium equal to the remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable in common stock. T.R. Winston & Company LLC acted as placement agent for the private placement and received $0.40 million of Debentures equal to 5% of the gross proceeds from the sale.  The Company is amortizing the $0.40 million over the life of the loan as deferred financing costs.  The Company amortized $0.06 million of deferred financing costs into interest expense during the six months ended March 31, 2012 and has $0.21 million of deferred financing costs to be amortized over a straight-line basis until February 2014. 
 
 
24

 
 
On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to increase the amount of its Debentures by up to an additional $5.0 million (the “Supplemental Debentures”).  Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of Supplemental Debentures are to be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other working capital purposes. Any new producing properties that are developed from the proceeds of Supplemental Debentures are to be pledged as collateral to secure future payment of the Supplemental Debentures. All terms of the Supplemental Debentures are substantively identical to the Debentures.

As of June 30, 2012, we received $2.80 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 $3.8 million.  Five of these wells resulted in commercial production, and one well was plugged and abandoned.
 
In August 2012, the Company restructured the terms of the Supplemental Debenture offering and concluded the offering by issuing an additional $2.2 million of convertible debentures (see Note 11— Subsequent Events.)
 
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 Debentures and Supplemental Debentures are currently convertible into 2,644,659 shares of common stock. This amendment was 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.
 
We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect to June 30, 2012, the Supplemental Debentures.    This valuation resulted in an estimated derivative liability as of June 30, 2012 and December 31, 2011 of $1.6 million and $1.3 million, respectively.  The portion of the derivative liability that is associated with the Supplemental Debentures, in the approximate amount of $0.40 million, has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.
 
As of June 30, 2012 and December 31, 2011, the convertible debt is recorded as follows:
 
   
As of
   
As of
 
   
June 30, 2012
    December 31, 2011  
Convertible debentures
  $ 11,239,802     $ 8,400,000  
Debt discount
    (3,206,528 )     (3,470,932 )
Total convertible debentures, net
  $ 8,033,274     $ 4,929,068  

Annual debt maturities for our debt under our term notes and convertible notes payable obligations as of June 30, 2012 are as follows:

Year 1
  $ 840,508  
Year 2
    30,883,697  
Thereafter
    --  
Total
  $ 31,724,205  

 
25

 
 
Obligations and Commitments
 
We have the following contractual obligations and commitments as of June 30, 2012 (in thousands):

 
    
Payments due by period
 
 
Contractual obligations
    
Total
 
    
Within 1
year
 
    
2-3 years
 
    
4-5 years
 
    
More than
5 years
 
Secured debt
    
$
20,484,402
  
    
$
840,508
  
    
$
19,643,894
  
    
$
 
    
$
  
Interest on secured debt
    
 
4,799,051
  
    
 
3,059,491
  
    
 
1,739,560
  
    
 
  
    
 
  
Convertible debentures
    
 
11,239,802
  
    
 
  
    
 
11,239,802
  
    
 
  
    
 
  
Interest on convertible debentures
   
1,498,640
     
899,184
     
599,456
     
  
   
  
Operating leases
    
 
54,000
  
    
 
54,000
  
    
 
  
    
 
  
    
 
  
 
    
     
    
     
    
     
    
     
    
     
Total contractual cash obligations (1)
    
$
38,075,895
  
    
$
4,853,183
  
    
$
33,222,712
  
    
$
  
    
$
  
 
(1)  We could be liable for liquidated damages under registration rights agreements covering approximately 3.2 million shares of our common stock if we fail to maintain the effectiveness of a prior registration statement as required in the agreements. In such case, we would be required to pay monthly liquidated damages of up to $0.23 million. The maximum aggregate liquidated damages are capped at $1.37 million.
 
Off-Balance Sheet Arrangements
 
We do not have any off-balance sheet arrangements.

Plan of Operations
 
Our plan of operations for through the remainder of 2012 is to identify and develop oil and natural gas prospects from our existing inventory of undeveloped acreage. In this regard, we have gradually added structure and staffing to our company as we become the operator of an increasing number of acquired properties. By acting as the operator, we have greater control over operating, drilling and developmental decisions, and would expect to generally better control our overall finding costs as we increase our exploration and development activities.

We anticipate the investment of substantial capital during the next few years to evaluate, assess and develop our existing inventory 142,000 gross, 123,000 net acres of developed and undeveloped oil and gas leases.  
 
The acquisition and development of properties and prospects and the pursuit of fresh opportunities require that we maintain access to adequate levels of capital.   We will strive for an optimal balance between our property portfolio and our capital structuring that will allow for growth designed to build shareholder value and profitability.   The decisions around the balancing of capital needs and property holdings will be a challenge to us as well as all companies in the entire energy industry during this time of continued disruption in the financial markets and an increasingly complex global economic picture.  As a function of balancing properties and capital, we may decide to monetize certain properties to reduce debt or to allow us to acquire interests in new prospects or producing properties that may be better suited to the current economic and energy industry environment.
 
The business of oil and natural gas acquisition, exploration and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. Therefore, a principal part of our plan of operations is to raise the additional capital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties.  As explained above in the “Liquidity and Capital Resources” section, based on our present working capital and current rate of cash flow from operations, we will need to raise additional capital to partially fund our overhead, and fund our exploration and development budget through, at least, December 31, 2012.  We will seek additional capital through the sale of our securities and we will endeavor to obtain additional capital through debt and project financing.  However, as described further below, under the terms of our $21.0 million 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 $21.0 million credit facility.
 
 
26

 
 
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.  
 
As of June 30, 2012, we had four wells in progress, including 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 $3.9 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 June 30, 2012, the current carrying costs would exceed the ceiling and partially flow through the income statement as an expense if the well were assumed to be non-productive as of June 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 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 in 2013.
 
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.
 
 
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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 generally accepted accounting principles in the United States, or 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 June 30, 2012, using the average, first-day-of-the-month price during the 12-month period ending June 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.
 
 
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We believe estimated reserve quantities and the related estimates of future net cash flows are the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties.  Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used.  For example, the standardized measure calculation requires us to apply a 10% discount rate.  Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change.  We evaluate and estimate our oil and natural gas reserves as of December 31 of each year and quarterly throughout the year.  For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions.  Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.
 
Oil and Natural Gas Properties—Full Cost Method of Accounting
 
We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.
 
Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations.  These unevaluated properties are assessed quarterly to ascertain whether impairment has occurred.  When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations.
 
Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%.  Royalties paid, net of any tax credits received, are netted against oil and natural gas sales. 
 
In applying the full cost method, we perform a ceiling test on properties that restricts the capitalized costs, less accumulated depletion, from exceeding an amount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleum engineers.  The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the end of the applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financing costs, future site restoration costs and income taxes.  Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.
 
 
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Revenue Recognition
 
The Company derives revenue primarily from the sale of produced natural gas and crude oil.  The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses and are included in oil and gas production expense in the accompanying consolidated statements of operations.  Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production.  No revenue is recognized unless it is determined that title to the product has transferred to the purchaser.  At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive.  The Company uses its knowledge of its properties, their historical performance, NYMEX and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates.
 
Share Based Compensation
 
The Company accounts for share-based compensation by estimating the fair value of share-based payment awards made to employees and directors, including restricted stock grants, on the date of grant.  The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods.  

Derivative Instruments
 
Periodically, the Company entered into swaps to reduce the effect of price changes on a portion of our future oil production. We reflect the fair market value of our derivative instruments on our balance sheet.  Our estimates of fair value are determined by obtaining independent market quotes as well as utilizing a valuation model that is based upon underlying forward curve data and risk free interest rates.  Changes in commodity prices will result in substantially similar changes in the fair value of our commodity derivative agreements.  We do not apply hedge accounting to any of our derivative contracts, therefore we recognize mark-to-market gains and losses in earnings currently.
 
Item 3.     Quantitative and Qualitative Disclosures About Market Risk
 
Market risk represents the risk of loss that may impact our financial position, results of operations, or cash flows due to adverse changes in financial market prices, including interest rate risk, foreign currency exchange rate risk, commodity price risk, and other relevant market or price risks.
 
Commodities Price Risk.  Our financial condition, results of operations and capital resources are dependent upon the prevailing market prices of oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions.  It is impossible to predict future oil and natural gas prices with any degree of certainty.  Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically.  Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our development activities.
  
In order to protect the Company from uncertainty associated with oil and natural gas prices we entered into the following:
 
On December 21, 2011, we entered into a Commodity Fixed Price Swap contract that covers approximately 40% of our forecasted 2012 oil production.   This contract covers 100 bopd throughout 2012, or a total of 36,600 barrels, and establishes a fixed sales price per barrel of $96.25.  At the end of each month in 2012, the fixed price is compared to a floating price equal to the average of settlement prices of the Nymex Prompt month WTI crude oil contract.  If the fixed price is less than the floating price, then the Company will make an immediate payment to the swap counterparty equal to the difference in the fixed and floating prices multiplied by the monthly oil volume (3,000 barrels in a 30 day month).  Alternatively, if the fixed price is more than the floating price, then we will receive a payment from the swap counterparty equal to the difference between the fixed and floating prices multiplied by the monthly volume.
 
 
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On March 21, 2012, we entered into a similar Commodity Fixed Price Swap contract that covers 100 bopd throughout the first six months of 2013, or a total of 18,100 barrels, and establishes a fixed sales price per barrel of $106.25. 

As of June 30, 2012, based upon the estimated forward floating price we recorded an unrealized gain accrual related to these Swap contracts of approximately $0.50 million.
 
We may, from time to time, enter into other similar agreements in order to hedge oil prices from future substantial price swings.
 
Interest Rate Risk.  We have minimal interest rate risk as all of our debt currently provides for fixed interest rates.  However, we may enter into future transactions that could result in higher interest rates, or in floating or adjustable interest rates that could expose the Company to additional interest rate risks.
 
Foreign Currency Risk.  We do not currently have any substantial exposure to foreign currency risk.

Item 4.  Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2012, the end of the period covered by this report. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer.  Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of June 30, 2012, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
 
Changes in Internal Control Over Financial Reporting
 
We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment.  Changes may include such activities as implementing new, more efficient systems, consolidating activities and migrating processes.

In our Annual Report on Form 10K/A for the year ended December 31, 2011, we noted that the following material weaknesses in our internal control over financial reporting existed as of December 31, 2011:
 
  
Insufficient independent internal review and approval of critical accounting schedules used in the preparation of financial statements.
  
The financial statement close process did not permit timely preparation of necessary financial information and there is inadequate documentation of internal controls for some assertions in certain significant accounts.
  
Lack of effective controls over general ledger processing, spreadsheets and data back-up.

Since the date of that report, we have continued to design changes to our systems and are in the process of implementing new controls to address these issues, and expect to implement changes sufficient to resolve these internal control weaknesses before December 31, 2012.
 
 
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Other than as noted above, there were no other changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended June 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations in Control Systems
 
Our controls and procedures are designed at a reasonable assurance level. In designing and evaluating our controls and procedures, management recognizes that, because of inherent limitations, any system of controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance of achieving the desired objectives of the control system.  In addition, the design of a control system must reflect the fact that there are resource constraints, and management must apply its judgment in evaluating the benefits of possible controls relative to their costs.  Further, no evaluation of controls and procedures can provide absolute assurance that all errors, control issues and instances of fraud will be prevented or detected. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls.  The design of any system of controls and procedures is also based in part on certain assumptions regarding the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
 
 
PART II - OTHER INFORMATION
 
Item 1. Legal Proceedings.
 
Currently we are not aware of any material litigation pending or threatened by or against the Company.
 
Item 1A. Risk Factors.
 
There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2011 Annual Report on Form 10-K/A filed with the Securities and Exchange Commission, which we incorporate by reference herein, except that we have the following new risk factor which was included in our Quarterly Report on form 10-Q for the quarter ended March 31, 2012:
 
If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, wells in progress are deemed unsuccessful, or major tracts of undeveloped leases expire, or other similar adverse events occur, we may be required to write-down the carrying value of our evaluated properties.
 
We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling wells, completing productive wells, or plugging and abandoning non-productive wells, costs related to expired leases, or leases underlying  producing and non-producing wells, and overhead charges directly related to acquisition and exploration activities.  Under the full cost method of accounting, capitalized oil and natural gas property that comprise the full cost pool, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves.  This ceiling test is performed at least quarterly.  Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize impairment expense.  Effective with our report on Form 10-Q for the quarter ended March 31, 2012, we recognized impairment expenses in the amount of approximately $3.3 million related to impairment of the carrying value of the evaluated properties that comprised the full cost pool.  Future write-downs could occur for numerous reasons, including, but not limited to reductions in oil and gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserve estimates, or from the addition of non-productive capitalized costs to the full cost pool that do not result in corresponding increase in oil and gas reserves.  Impairments of unevaluated leases and plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full cost pool, without any corresponding increase in reserve values; as such, these situations could result in future additional impairment expenses.
 
 
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
 
On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to increase the amount of its Debentures by up to an additional $5.0 million (the “Supplemental Debentures”).  Under the terms of the Supplemental Debenture Agreements, proceeds derived from the issuance of Supplemental Debentures are to be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other working capital purposes.  Any new producing properties that are developed from the proceeds of Supplemental Debentures are to be pledged as collateral to secure future payment of the Debentures.  All terms of the Supplemental Debentures are substantively identical to the Debentures.
 
As of June 30, 2012, we received $2.80 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 $3.80 million.  Five of these wells resulted in commercial production, and one well was plugged and abandoned.  In August 2012, the Company agreed to restructure the Supplemental Debenture offering in order to secure funding of the additional $2.2 million, which occurred on August 9, 2012.
 
The $5.0 million of convertible debentures that have been issued are currently convertible into 1,176,471 shares of common stock, at the rate of $4.25 per common share, subject to adjustment under certain circumstances.   Under the terms of the March 19, 2012 agreements as amended, we have no obligation to register any of the convertible debentures that are or may be issued, or any of the underlying common stock that may be issued upon conversion of any such convertible debentures.
 
Item 3. Defaults Upon Senior Securities.
 
None.
 
Item 4. Mine Safety Disclosures
 
Not Applicable
 
Item 5. Other Information.
 
None.
 
Item 6. Exhibits and Reports of Form 8-K.
 
Exhibits
 
10.1 
Amendment to Securities Purchase Agreement dated as of February 2, 2011 relating to issuance of 8% Senior Secured Convertible Debentures due February 8, 2014
 
10.2 
Amendment to Securities Purchase Agreement dated as of March 12, 2012 relating to issuance of 8% Senior Secured Convertible Debentures due February 8, 2014
 
31.1
Certifications pursuant to Section 302 of Sarbanes Oxley Act of 2002
 
31.2
Certifications pursuant to Section 302 of Sarbanes Oxley Act of 2002
 
32.1
Certifications pursuant to Section 906 of Sarbanes Oxley Act of 2002
 
32.2
Certifications pursuant to Section 906 of Sarbanes Oxley Act of 2002
 
 
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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant caused this amended report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
Recovery Energy, Inc.
   
Date: August 9, 2012
By:
/s/ Roger A. Parker
   
Roger A. Parker
   
Chief Executive Officer
     
 
Date: August 9, 2012
By:
/s/ A. Bradley Gabbard
   
A. Bradley Gabbard
   
Chief Financial Officer
     
 
Date: August 9, 2012
By:
/s/ Eric Ulwelling
   
Eric Ulwelling
   
Principal Accounting Officer
 
 
 34

XNAS:RECV Quarterly Report 10-Q Filling

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XNAS:RECV Quarterly Report 10-Q Filing - 6/30/2012
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