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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Resaca | LSE:RSOX | London | Ordinary Share | COM SHS USD0.01 (DI) |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 4.50 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
TIDMRSOX
RNS Number : 4475U
Resaca Exploitation Inc
22 December 2011
for imMediate release 22 december 2011
Resaca Exploitation, Inc.
("Resaca" or "the Company")
Results for the fiscal year ended 30 June 2011
Resaca (AIM:RSOX), the oil and natural gas production, exploitation, and development company focused on the Permian Basin in the USA, is pleased to announce its results for the fiscal year ended 30 June 2011.
Highlights
Operational Highlights
-- Significant waterflood enhancements and infrastructure improvements at Cooper Jal and Penwell resulting in increased production at both properties.
-- Implemented second phase of refrac program at Cooper Jal
-- Successfully implemented first phase of well deepenings at Penwell property into lower San Andres formation.
-- Produced over 198,000 barrels of oil and over 237,000 MCF of gas for an average of 651 barrels of oil equivalent per day.
-- 20% increase in proved producing reserves from 30 June 2010 to 30 June 2011, after consideration of fiscal year production.
Hot Features
Premium
-- Proved reserves of 14.6 million barrels of oil equivalents ("MMboe") as of 30 June 2011.
-- Proved and probable reserves stand at 29.9 MMboe as of 30 June 2011.
-- Increased production from December 2010 to December 2011 by 15%
-- Completed sale of Grand Clearfork property and acquisition of Langlie Jal Unit in July 2011 and August 2011, respectively.
Financial Highlights
-- Oil and gas revenues of $16.5 million after hedging loss realizations of $2.0 million. -- Net loss of $7.3 million. -- EBITDA of $8.1 million, a 168% increase over prior fiscal year. -- EBITDA of $8.3 million excluding onetime costs, a 69% increase over prior fiscal year.
-- Closed new three year senior revolving credit facility with $33 million initial borrowing base.
-- Closed $20 million four year unsecured credit facility.
For further information please contact:
Resaca Exploitation, Inc.
J.P. Bryan, Chairman and Chief Executive
Officer +1 713-753-1300
John J. ("Jay") Lendrum, III, Vice Chairman +1 713-753-1400
Dennis Hammond, President and Chief
Operating Officer +1 713-753-1281
Chris Work, Chief Financial Officer +1 713-753-1406
Buchanan (Investor Relations) +44 (0)20 7466 5000
Tim Thompson
Helen Chan
Ben Romney
finnCap Limited (Nomad and Broker) + 44 (0) 20 7600 1658
Sarah Wharry, Corporate Finance
Victoria Bates, Corporate Broking
About Resaca
Resaca is an independent oil and gas development and production company based in Houston, Texas. Resaca is focused on the acquisition and exploitation of long-life oil and gas properties, utilizing a variety of primary, secondary and tertiary recovery techniques. Resaca's current properties are located in the Permian Basin of West Texas and Southeast New Mexico. Additional information is available at www.resacaexploitation.com.
Report and accounts
The report and accounts of Resaca for the year ended 30 June 2011 are being posted to shareholders and will be available on the company's website www.resacaexploitation.com.
CHIEF EXECUTIVE OFFICER'S STATEMENT
I am pleased to present the Report and Accounts for Resaca Exploitation for the year ended 30 June 2011.
We began the fiscal year arranging financing to fund our exploitation program and successfully closed two financings in January 2011. Our new subordinated debt facility and senior bank facility provided us with liquidity to fund our $13 million capital program and acquisitions while lowering our cash borrowing costs.
Our capital program focused on our primary properties - the Cooper Jal Unit ("CJU") and our Penwell properties, the Jordan San Andres Unit ("JSAU" and the Edwards Grayburg Unit ('EGBU"). At CJU, we completed eleven of our planned fifteen refracs with positive results, upgraded production equipment and infrastructure, and increased reservoir pressure through optimization and expansion of the existing waterflood by cleaning out water injection wells, converting shut-in wells to water injection wells, and by installing a new horizontal water injection pump. As a result of this work, the current injection rate at the field is now over 23,000 barrels of water per day ("bwpd"), up from 17,000 bwpd earlier this year. We expect to continue to increase water injection until we achieve our injection rate goal of 25,000 bwpd. Currently, we are continuing our exploitation program at CJU by returning abandoned wells to production, drilling out bridge plugs to access shut-in production, and further upgrading our infrastructure and artificial lift equipment to handle the increased oil and water levels resulting from our positive waterflood response and to increase our gas production.
At JSAU, we completed two of four planned well deepening operations into the Lower San Andres interval. In order to handle the significant water production from these wells, we have upgraded our artificial lift equipment on these wells and we are currently upgrading our oil and water handling infrastructure. Once these upgrades are completed, we will have a better understanding of the potential production and reserves that could be accessed through additional vertical well deepenings or possibly significant horizontal drilling program. In addition to well deepenings, we expanded and optimized the existing waterflood by cleaning out water injection wells, converting shut-in wells to water injection wells, and by installing a new horizontal water injection pump. The result of these efforts is a doubling of the injection rate at Jordan from 3,500 bwpd to over 10,000 bwpd currently.
At our Edwards Grayburg Unit ("EGBU"), our focus has been on cleaning out and stimulating producing wells, cleaning out water injection wells, upgrading our water injection facilities, and upgrading field infrastructure. Our water injection rates at EGBU have increased from 1,500 bwpd to nearly 4,000 bwpd.
The result of our efforts is a production increase of 14 percent from December 2010 to December 2011, with December 2010 production averaging 644 barrels of oil equivalent per day ("boepd") and December 2011 production to date averaging 737 boepd, both net to Resaca. We fully expect to exit 2011 producing 800 boepd net to Resaca. My personal objective is to increase net daily production to 1,000 boepd by the end of March, 2012.
Regarding acquisition and divestitures, we acquired 1,375 gross and net acres adjacent to JSAU during the fiscal year. We plan to evaluate the lower San Andres potential on this property as well as the property's waterflood potential. Shortly after the end of the fiscal year, we sold our Grand Clearfork Unit property and acquired a 73% working interest in the Langlie Jal Unit ("LJU"). The LJU property has already proven to be an ideal complement to our nearby CJU property. Since the acquisition, we have increased our net production at LJU from 58 boepd in August to over 80 boepd in December by returning certain inactive wells to production and by redirecting water injection into reactivated water injection wells. Longer term, we believe this asset has significant production potential from many of the same opportunities we have identified at Copper Jal, including uphole recompletions, refracs of currently producing zones, additional waterflood enhancement and optimization, infill drilling and potential CO2 flooding. We believe this acquisition was a very important milestone for Resaca.
With nearly 30 MMboe of heavily oil weighted 2P reserves as of 30 June 2011, we believe Resaca has significant enterprise value.Our properties have expected production lives in excess of 40 years and our 2P reserves are 92% oil. Despite producing 237,000 boe of our reserves during the fiscal year, our proved producing reserves increased by 20 percent from 30 June 2010 to 30 June 2011. It should be noted that none of the lower San Andres potential at JSAU or the JSAU offset acreage is included in any of our reserve estimates and the Grand Clearfork Sale and LJU purchase are not reflected in our 30 June 2011 reserves.
We are excited about the results from our exploitation projects, our reserve base and the opportunities we see in our fields. We look forward to further success in 2012.
J.P. Bryan Chairman and Chief Executive Officer
12 Greenway Plaza, 12th Floor
Houston, TX 77046
Phone 713-561-6500
Fax 713-968-7128
Web www.uhy-us.com
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Resaca Exploitation, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Resaca Exploitation, Inc. (formerly Resaca Exploitation, L.P.) and subsidiary (the "Company") as of June 30, 2011 and 2010, and the related consolidated statements of operations, owners' equity (deficit), and cash flows for each of the three years in the period ended June 30, 2011. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note B to the consolidated financial statements, in 2010, the Company adopted SEC Release 33--8995 and the amendments to ASC Topic 932, Extractive Industries - Oil and Gas, resulting from ASU 2010-03 (collectively, the "Modernization Rules").
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Resaca Exploitation, Inc. and Subsidiary as of June 30, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended June 30, 2011, in conformity with accounting principles generally accepted in the United States of America.
UHY LLP
Houston, Texas
December 16, 201
June 30,
-----------------------------------------------------
2011 2010
--------------------------------- --- --------------------- ------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 1,005,863 $ 481,853
Restricted cash - 25,000
Accounts receivable 3,169,637 1,539,451
Other receivable, net 1,480,986 2,130,227
Due from affiliates, net 186,917 -
Prepaids and other current assets 556,957 663,915
Deferred tax assets 490,433 238,276
------------------------------------------ --------------------- ------------------------------
Total current assets 6,890,793 5,078,722
------------------------------------------ --------------------- ------------------------------
Property and Equipment, at cost
Oil and gas properties - full cost
method 146,934,137 131,463,011
Fixed assets 1,929,998 1,714,900
------------------------------------------ --------------------- ------------------------------
148,864,135 133,177,911
Accumulated, depreciation, depletion
and amortization (17,551,787) (13,396,813)
------------------------------------------ --------------------- ------------------------------
131,312,348 119,781,098
Other property 270,783 270,783
------------------------------------------ --------------------- ------------------------------
Total property and equipment 131,583,131 120,051,881
------------------------------------------ --------------------- ------------------------------
Deferred finance costs, net 949,835 822,765
------------------------------------------ --------------------- ------------------------------
Total assets $ 139,423,759 $ 125,953,368
------------------------------------- -------- --------------- --------- -------------------
LIABILITIES AND OWNERS' EQUITY
(DEFICIT)
Current liabilities
Accounts payable and accrued
liabilities $ 5,076,906 $ 5,597,302
Capital lease obligations, 65,839
current -
Derivative liabilities 1,912,550 899,307
Total current liabilities 7,055,295 6,496,609
Senior credit facility 28,500,000 35,000,000
Unsecured debt 18,600,262 -
Notes payable, affiliates 2,043,973 1,854,722
Capital lease obligations, net 56,165
of current portion -
Deferred tax liabilities 490,433 238,276 128,553
Derivative liabilities 5,982,504 744,708
Asset retirement obligations 4,138,677 4,114,974
Commitments and contingencies
Stockholders' equity:
Common stock 196,632 193,895
Additional paid-in capital 97,408,857 95,105,080
Accumulated deficit (25,049,039) (17,794,896)
------------------------------------------ --------------------- ------------------------------
Total stockholders' equity $ 72,556,450 $ 77,504,079
------------------------------------- -------- --------------- --------- -------------------
Total liabilities and stockholders'
equity $ 139,423,759 $ 125,953,368
-------------------------------------- -------- --------------- --------- -------------------
See accompanying notes to consolidated financial statements.
Years Ended June 30,
-------------------------------------------------------------------------
2011 2010 2009
----------------------------------- ---------------------------- --------------------- --------------------
Income
Oil and gas revenues $ 16,534,071 $ 15,053,740 $ 14,154,035
Unrealized gain (loss) from price
risk management activities (4,169,839) 642,254 11,468,361
Unrealized gain from change in
fair value of warrant derivative
liabilities 580,800
Interest and other income 463 7,676 51,640
----------------------------------- ---------------------------- --------------------- --------------------
Total income 12,945,495 15,703,670 25,674,036
----------------------------------- ---------------------------- --------------------- --------------------
Costs and expenses
Lease operating expenses 5,323,058 6,104,811 6,622,739
Production and ad valorem taxes 1,201,119 1,110,664 1,250,357
Depreciation, depletion and
amortization 4,154,973 3,816,752 3,370,759
Accretion expense 191,892 173,830 281,290
General and administrative
expenses 1,925,046 4,811,823 2,984,286
Share based compensation costs 2,306,514 4,345,282 4,102,854
Provision for credit losses 400,000 250,000 -
Inventory write down - - 318,411
Interest expense 3,924,218 3,274,160 4,024,708
Loss on extinguishment of debt 772,443
Other expense - - 8,206
----------------------------------- ---------------------------- --------------------- --------------------
Total costs and expenses 20,199,263 23,887,322 22,963,610
----------------------------------- ---------------------------- --------------------- --------------------
Income (loss) before taxes (7,253,768) (8,183,652) 2,710,426
Income tax expense (375) (2,458) -
----------------------------------- ---------------------------- --------------------- --------------------
Net income (loss) $ (7,254,143) $ (8,186,110) $ 2,710,426
----------------------------------- ----------------------- --- ----------------- ---------- ----
EARNINGS PER SHARE
----------------------------------- ---------------------------- --------------------- --------------------
Basic weighted--average shares
outstanding 19,651,159 19,363,865 18,451,748
Diluted weighted--average shares
outstanding 19,651,159 19,363,865 18,455,907
Basic earnings (loss) per share $ (0.37) $ (0.42) 0.15
Diluted earnings (loss) per share $ (0.37) $ (0.42) 0.15
----------------------------------- ----------------------- --- ------------- ------------------
See accompanying notes to consolidated financial statements.
Common Stock
----- -------------------------------
Additional Total Partners'
Paid-in Accumulated Stockholders' Capital
Shares Par value Capital Deficit Equity (Deficit)
------------------- ----- -------------- --------------- -------------------- ------------------- ------------------------ -----------
Balance at June 30,
2008 - - - - - $ (11,922,961)
Conversion from
partnership
to corporation 7,925,013 79,250 317,001 (12,319,212) (11,922,961) 11,922,961
Conversion of debt
to equity 4,064,109 40,641 9,959,359 10,000,000
Initial public
offering,
net 6,462,583 64,626 74,796,242 74,860,868
Share based
compensation 4,102,854 4,102,854
Net income 2,710,426 2,710,426
------------------- ---------------- --------------- -------------------- ------------------- ------------------------ -----------
Balance at June 30,
2009 18,451,705 184,517 89,175,456 (9,608,786) 79,751,187 -
Stock issued upon
vesting of
restricted
stock 273,701 2,737 (2,737) -
Stock issued for
the
acquisition of
assets 664,050 6,641 1,587,079 1,593,720
Share based
compensation 4,345,282 4,345,282
Net loss (8,186,110) (8,186,110)
------------------- ---------------- --------------- -------------------- ------------------- ------------------------ -----------
Balance at June 30,
2010 19,389,456 193,895 95,105,080 (17,794,896) 77,504,079 -
Stock issued upon
vesting of
restricted
stock 273,701 2,737 (2,737) -
Share based
compensation 2,306,514 2,306,514
Net loss (7,254,143) (7,254,143)
------------------- ---------------- --------------- -------------------- ------------------- ------------------------ -----------
Balance at June 30,
2011 19,663,157 $ 196,632 $ 97,408,857 $ (25,049,039) $ 72,556,450 $ -
------------------- ---------------- --------------- -------------------- ------------------- ------------------------ -----------
See accompanying notes to consolidated financial statements.
Years Ended June 30,
---------------------------------------------------------------
2011 2010 2009
------------------------------------------------------------ ---------------------------- ---------------- ---------------
Cash flows from operating activities
Net income (loss) $ (7,254,143) $ (8,186,110) $ 2,710,426
Adjustments to reconcile net income
(loss) to net cash provided by
(used in) operating activities
provided by (used in) operating
activities
- Depreciation, depletion and amortization 4,154,973 3,816,752 3,370,759
- Accretion expense 191,892 173,830 281,290
* Amortization of deferred finance costs (including
accelerated amortization due to extinguishment of
debt) 327,505 791,515
accelerated amortization due to
extinguishment of debt) 865,545 327,505 791,515
327,505 791,515
- Provision for credit losses 400,000 250,000 -
- Payment of interest in kind 1,195,362 - -
- Amortization of debt discount 66,900 - -
- Unrealized (gain) loss from price
risk management activities 4,169,839 (642,254) (11,468,361)
* Unrealized gain from change in fair value of warrant
derivative liabilities
derivative liabilities (580,800) - -
- Share based compensation costs 2,306,514 4,345,282 4,102,854
- Inventory write down - - 318,411
Changes in operating assets and
liabilities
- Accounts receivable (1,380,945) (2,251,671) 968,352
- Prepaids and other current assets 106,958 113,603 2,011,273
- Accounts payable and accrued
liabilities (520,396) 2,571,516 (1,492,527)
- Due to affiliates, net 2,334 831,517 (5,544,658)
- Settlement of asset retirement
obligations (165,237) - (2,389)
------------------------------------------------------------ ---------------------------- ---------------- ---------------
Net cash provided by (used in)
operating activities 3,558,796 1,349,970 (3,953,055)
------------------------------------------------------------ ---------------------------- ---------------- ---------------
Cash flows from investing activities
Restricted cash 25,000 342,184 (367,184)
Investment in oil and gas properties (15,474,077) (4,381,933) (19,987,934)
Investment in other property - (4,500) (84,084)
Investment in fixed assets (93,094) (133,721) (82,684)
------------------------------------------------------------ ---------------------------- ---------------- ---------------
Net cash used in investing activities (15,542,171) (4,177,970) (20,521,886)
------------------------------------------------------------ ---------------------------- ---------------- ---------------
Cash flows from financing activities
Proceeds from notes payable 48,643,600 3,153,889 10,735,000
Payments on notes payable (35,143,600) - (60,188,889)
Proceeds from initial public offering,
net of direct expenses - - 74,860,868
Deferred finance costs (992,615) (174,317) (790,214)
------------------------------------------------------------ ---------------------------- ---------------- ---------------
Net cash provided by financing
activities 12,507,385 2,979,572 24,616,765
------------------------------------------------------------ ---------------------------- ---------------- ---------------
Net increase in cash and cash equivalents 524,010 151,572 141,824
Cash and cash equivalents, beginning
of year 481,853 330,281 188,457
------------------------------------------------------------ ---------------------------- ---------------- ---------------
Cash and cash equivalents, end
of year $ 1,005,863 $ 481,853 $ 330,281
------------------------------------------------------------ ---------------------------- ---------------- ---------------
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the year for interest $ 1,975,547 $ 2,938,877 $ 3,233,193
Non cash investing and financing
activities
- Establishment of asset retirement
obligations $ 1,972 $ 1,898 $ 126,768
- Acquisition of assets under capital $ 122,004 - -
lease obligations
- Conversion of debt to equity $ - $ - $ 10,000,000
- Assets acquired for issuance $ - $ 1,593,720 $ -
of stock
------------------------------------------------------------ ----- --------------------- ---------------- -----------
See accompanying notes to consolidated financial statements.
Note A - Organization and Nature of Business
Resaca Exploitation, L.P. (the "Partnership") was formed on March 1, 2006 for the purpose of acquiring and exploiting interests in oil and gas properties located primarily in New Mexico and Texas. The Partnership was funded and began operations on May 1, 2006. Resaca Exploitation, G.P. served as the sole general partner (.667%) and various limited partners owned the remaining 99.333%. Under the terms of the Limited Partnership Agreement, profits and losses were allocated to the general partner and limited partners based upon their ownership percentages.
On July 10, 2008, the Partnership converted from a Delaware partnership to a Texas corporation and became Resaca Exploitation, Inc. ("Resaca"). Following conversion, Resaca became subject to federal and certain state income taxes and adopted a June 30 year end for federal income tax and financial reporting purposes. On July 17, 2008, Resaca completed an initial public offering (the "Offering") on the Alternative Investment Market of the London Stock Exchange. In the initial public offering, Resaca raised $83.4 million before expenses (see Note H).
Resaca Operating Company ("ROC"), a wholly-owned subsidiary, was formed on October 16, 2008 for the purpose of operating Resaca's oil and gas properties. Resaca and ROC are referred to collectively as the "Company". Activities for ROC are consolidated in the Company's financial statements.
Note B - Summary of Significant Accounting Policies and Basis of Presentation
Principles of Consolidation: The consolidated financial statements include the accounts of Resaca and ROC. All significant intercompany accounts and transactions have been eliminated.
Cash and Cash Equivalents: Cash in excess of the Company's daily requirements is generally invested in short-term, highly liquid investments with original maturities of three months or less. Such investments are carried at cost, which approximates fair value and, for the purposes of reporting cash flows, are considered to be cash equivalents. The Company maintains its cash in bank deposits with various major financial institutions. These accounts, at times, exceed federally insured limits. The Company monitors the financial condition of the financial institutions and has not experienced any losses on such accounts.
Restricted Cash: The Company collateralizes any open letters of credit with cash (see Note G). At June 30, 2011 and 2010, the Company had outstanding open letters of credit collateralized by cash of $0 and $25,000, respectively.
Accounts Receivable: Accounts receivable primarily consists of accrued revenues for oil and gas sales. The Company routinely assesses the recoverability of all material receivables to determine their collectability.
Allowance for Doubtful Accounts: The Company accrues a reserve on a receivable when, based on the judgment of management, it is likely that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of June 30, 2011 and 2010, the Company had an allowance for doubtful accounts of $650,000 and $250,000, respectively.
Inventory: Inventory totaling $485,807 and $607,531 at June 30, 2011 and 2010, respectively, consists of piping and tubulars valued at the lower of cost or market and is included within prepaids and other current assets in the accompanying balance sheets.
Oil and Gas Properties: Oil and gas properties are accounted for using the full-cost method of accounting. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. This includes any internal costs that are directly related to acquisition, exploration and development activities, including salaries and benefits, but does not include any costs related to production, general corporate overhead or similar activities. During the years ended June 30, 2011, 2010 and 2009, the Company capitalized $306,111, $373,360 and $638,942, respectively, in overhead relating to these internal costs.
No gains or losses are recognized upon the sale or other disposition of oil and natural gas properties except in transactions that would significantly alter the relationship between capitalized costs and proved reserves.
Under the full cost method, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at 10% (the "Ceiling Limitation"). In arriving at estimated future net revenues, estimated lease operating expenses, development costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The excess, if any, of the net book value above the Ceiling Limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. The Company prepared its ceiling test at June 30, 2011 and 2010, and no impairment was deemed necessary. Reserve estimates used in determining estimated future net revenues have been prepared by an independent petroleum engineer at year end.
The costs of unevaluated oil and natural gas properties are excluded from the amortizable base until the time that either proven reserves are found or it has been determined that such properties are impaired. The Company currently has no material capitalized costs related to unevaluated properties. All capitalized costs are included in the amortization base as of June 30, 2011 and 2010.
Note B - Summary of Significant Accounting Policies and Basis of Presentation (Continued)
Depreciation and Amortization: All capitalized costs of oil and natural gas properties and equipment, including the estimated future costs to develop proved reserves, are amortized using the unit-of-production method based on total proved reserves. Depreciation of fixed assets is computed on the straight-line method over the estimated useful lives of the assets, typically three to five years.
General and Administrative Expenses: General and administrative expenses are reported net of recoveries from owners in properties operated by the Company.
Revenue Recognition: The Company recognizes oil and gas revenues from its interests in oil and natural gas producing activities as the hydrocarbons are produced and sold.
Accounting for Price Risk Management Activities and Other Derivative Instruments: The Company periodically enters into certain financial derivative contracts utilized for non-trading purposes to hedge the impact of market price fluctuations on its forecasted oil and gas sales. The Company follows the provisions of Accounting Standards Codification ("ASC") 815, Accounting for Derivative Instruments and Hedging Activities ("ASC 815"), for the accounting of its hedge transactions. ASC 815 establishes accounting and reporting standards requiring that all derivative instruments be recorded in the consolidated balance sheet as either an asset or liability measured at fair value and requires that the changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The Company has certain over-the-counter collar contracts to hedge the cash flow of the forecasted sale of oil and gas sales. The Company did not elect to document and designate these contracts as hedges. Thus, the changes in the fair value of these over-the-counter collars are reflected in earnings for the years ended June 30, 2011, 2010 and 2009.
The Company has common stock warrants outstanding in connection with the unsecured credit facility agreement (the "Chambers Facility") (see note E), which contains price protection provisions (or down-round provisions) which reduces the strike price of the warrants in the event the Company issues additional shares at a more favorable price than the strike price. The warrants are measured and carried at fair value as a derivative liability on the Company's consolidated balance sheet. The fair value of the warrants on the date of issuance of $2,662,000 was recognized as a discount to the unsecured credit facility at the time the Company received the proceeds from the credit facility. The discount will be accreted to the credit facility, over the period from the funding date through the maturity date, using the effective interest rate method.
Income Tax: The Company is subject to federal income tax, Texas state margin tax, and New Mexico state income tax. The Company follows the guidance in ASC 740, Accounting for Income Taxes, which requires the use of the asset and liability method of accounting for deferred income taxes and provides deferred income taxes for all significant temporary differences.
The Company follows ASC 740-10, Accounting for Uncertainty in Income Taxes. The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.
Deferred Finance Costs: The Company capitalizes all costs directly related to obtaining financing and such costs are amortized to interest expense over the life of the related facility. During the years ended June 30, 2011 and 2010, the Company incurred and capitalized finance costs of $992,615 and $174,317, respectively. At June 30, 2011 and 2010, the deferred finance costs balance is presented net of accumulated amortization of $173,113 and $1,853,766, respectively.
Use of Estimates: Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates.
Independent petroleum and geological engineers have prepared estimates of the Company's oil and natural gas reserves at June 30, 2011 and 2010. Proved reserves, estimated future net revenues and the present value of our reserves are estimated based upon a combination of historical data and estimates of future activity. We have based our present value of proved reserves on spot prices on the date of the estimate for periods prior to December 31, 2009. However, in accordance with the current authoritative guidance, effective December 31, 2009, the Company calculated its estimate of proved reserves using a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each period within the twelve-month period prior to the end of the reporting period. The reserve estimates are used in calculating depreciation, depletion and amortization and in the assessment of the Company's ceiling limitation. Significant assumptions are required in the valuation of proved oil and natural gas reserves which, as described herein, may affect the amount at which oil and natural gas properties are recorded. Actual results could differ materially from these estimates.
Asset Retirement Obligations: The Company follows ASC 410 ("ASC 410"), Asset Retirement and Environmental Obligations. ASC 410 requires that an asset retirement obligation ("ARO") associated with the retirement of a tangible long-lived asset be Note B - Summary of Significant Accounting Policies and Basis of Presentation (Continued)
recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depreciated such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the company's credit-adjusted risk-free interest rate.
Inherent in the fair value calculation of ARO are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.
The following table is a reconciliation of the asset retirement obligation:
Years Ended June 30,
--------------------------------------------
2011 2010
--------------------------------------------- -------------------------- -----------
Asset retirement obligation, beginning of
the year $ 4,114,974 $ 3,939,246
Liabilities incurred 1,972 1,898
Liabilities settled (165,237) -
Accretion expense 191,892 173,830
Revisions in estimated liabilities (4,924) -
---------------------------------------------- -------------------------- -----------
Asset retirement obligation, end of the year $ 4,138,677 $ 4,114,974
---------------------------------------------- -------------------------- -----------
Share-Based Compensation: The Company follows ASC 718 ("ASC 718"), Compensation-Stock Compensation, for all equity awards granted to employees. ASC 718 requires all companies to expense the fair value of employee stock options and other forms of share-based compensation over the requisite service period. The Company's share-based awards consist of stock options and restricted stock.
Common Stock: On June 23, 2010, the Board of Directors approved a one for five reverse stock split effective June 24, 2010. Accordingly, all common shares, incentive plans and related amounts for all periods presented reflect the stock reverse split.
Earnings per Share: Basic earnings per share are computed by dividing net income by the weighted-average number of shares of common stock outstanding during the period. Diluted earnings per share are computed by dividing net income by the sum of the weighted-average number of shares of common stock outstanding during the period and the dilutive effect of restricted stock awards and the assumed exercise of stock options using the treasury stock method.
Subsequent Events: The Company evaluates events and transactions that occur after the balance sheet date but before the financial statements are available for issuance. The Company evaluated such events and transactions through December 16, 2011, the date the financial statements were available to be issued. See Note O.
Recently Adopted Accounting Principles:
Modernization of Oil and Gas Reporting: On December 31, 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting, which revises disclosure requirements for oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the new rules change the requirements for determining oil and gas reserve quantities. These rules permit the use of new technologies to determine proved reserves under certain criteria and allow companies to disclose their probable and possible reserves. The new rules also require companies to report the independence and qualifications of their reserve preparer or auditor and file reports when a third party is relied upon to prepare reserve estimates or conducts a reserve audit. The new rules also require that oil and gas reserves be reported and the full-cost ceiling limitation be calculated using a twelve-month average price rather than period-end prices. The new rules are effective for annual reports on for fiscal years ending on or after December 31, 2009. Additionally, the Financial Accounting Standards Board ("FASB") issued authoritative guidance on oil and gas reserve estimation and disclosures, as set forth in Accounting Standards Update ("ASU") No. 2010-03, Extractive Activities-Oil and Gas (Topic 932), to align with the requirements of the SEC's revised rules. The Company implemented the new disclosure requirements for estimating reserves related to the Company's oil and natural gas operations as of June 30, 2010 as disclosed in Note P.
ASU 2010-06: In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820). ASU 2010-06 Subtopic 820-10 provides new guidance on improving disclosures about fair value measurements. The new standard requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement. Specifically, the new standard will now require: (a) a reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for transfers, and (b) in the reconciliation for fair value measurements using significant unoberservable inputs, a reporting entity should present separately information about
Note B - Summary of Significant Accounting Policies and Basis of Presentation (Continued)
purchases, sales, issuances, and settlements. In addition, the new standard clarifies the requirements of the following existing disclosures: (a) for purposes of reporting fair value measurements for each class of assets and liabilities, a reporting entity needs to use judgment in determining the appropriate classes of assets and liabilities, and (b) a reporting entity should provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. We adopted the requirements of this standard for interim and annual reporting periods beginning after December 15, 2009, or the quarter ended March 31, 2010 and we adopted the requirements of this standard for fiscal years beginning after December 15, 2010, the year ended June 30, 2011. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.
Note C - Other Receivable
In September 2009, the Company entered into a merger agreement with Cano Petroleum, Inc. (the "Cano merger agreement"), subsequently terminated in July 2010. The Cano merger agreement provided for Resaca and Cano to, among other things, share equally certain expenses related to the printing, filing and mailing of the registration statement, the proxies/prospectuses, and the solicitation of stockholder approvals. Following the termination of the Cano merger agreement, Resaca requested that Cano reimburse Resaca for Cano's share of such expenses. Resaca has recorded a receivable of approximately $1.5 million, net of a $650,000 provision for credit losses, related to this reimbursement request. On September 2, 2010, Cano filed an action against Resaca in the Tarrant County District Court seeking a declaratory judgment to clarify the scope and determine the amount of any expenses that are reimbursable by Cano under the Cano merger agreement. Resaca disputes the allegations by Cano and management believes the amount recorded on Resaca's balance sheet will ultimately be collected from Cano.
Note D - Related Party Transactions
The Company receives support services from Torch Energy Advisors Incorporated ("TEAI") and its subsidiaries, which include office administration, risk management, corporate secretary, legal services, corporate and litigation legal services, graphic services, tax department services, financial planning and analysis, information management, financial reporting and accounting services, and engineering and technical services. The Company was charged by TEAI and a subsidiary of TEAI $960,904, $1,440,241 and $1,998,916 during the years ended June 30, 2011, 2010 and 2009, respectively, for such services. The majority of such fees are included in general and administrative expenses.
In the ordinary course of business, the Company incurs payable balances with TEAI resulting from the payment of costs and expenses of the Company and from the payment of support services fees. Such amounts had been settled on a regular basis, generally monthly. However, a Subordinated Unsecured Note was issued on June 30, 2010 for the outstanding balance payable to TEAI of $1,854,722 as of June 30, 2010. The principal balance payable to TEAI was amended on December 15, 2010 to be $1,915,800 (see Note E).
Note E - Notes Payable
On June 26, 2009, the Company entered into a $50 million, three-year Senior Secured Revolving Credit Facility ("CIT Facility") with CIT Capital USA Inc. ("CIT") with a maturity date of July 1, 2012, which replaced a credit facility entered into in 2006. The initial borrowing base of the CIT Facility was $35 million and CIT served as administrative agent. Interest on the CIT Facility was set at LIBOR plus 5.5% subject to a 2.5% LIBOR floor. Recourse for the CIT Facility was limited to the Company, as borrower, and the note was secured by all of the Company's oil and gas properties. Throughout the term of the CIT Facility, the interest rate was 8.0%. As a condition of closing the CIT Facility, the Company entered into additional natural gas hedges for January 2011 through June 2012 and additional oil hedges for June 2011 through June 2012. Additionally, upon closing of the CIT facility, the Company wrote off $536,579 in deferred financing costs associated with a previous facility with third parties and paid debt extinguishment fee of $250,000. The CIT Facility contained, among other terms, provisions for the maintenance of certain financial ratios and restrictions on additional debt. On December 22, 2009, the Company executed an amendment to the CIT Facility which amended some of the financial ratio requirements. On January 6, 2011, the CIT Facility was paid in full from proceeds received from the debt issuances described below.
On May 18, 2010, the Company, TEAI, and CIT entered into an agreement, which provided that, if the CIT Facility was not repaid in full by June 30, 2010, the outstanding payable by the Company to TEAI as of June 30, 2010 would be contractually subordinated to amounts payable under the CIT Facility. On June 30, 2010, the Company entered into a Subordinated Unsecured Note ("Torch Note") with TEAI for $1,854,722. The Torch Note had a maturity date of October 1, 2012 and bore interest at Amegy Bank N. A.'s prime rate plus two percent. At June 30, 2010 the interest rate was 7.0%. On December 15, 2010 the Torch Note was amended to increase the outstanding balance to $1,915,800, the interest provisions, provide for subordination to the Chambers Facility in addition to the Company's secured credit facility and extend the maturity date to
Note E - Notes Payable (Continued)
January 31, 2014. At June 30, 2011 the interest rate was 12.0%. The maturity date shall be accelerated in the event the senior debt issuance described below is repaid in full. Interest shall only be payable in kind.
On January 7, 2011, the Company entered into a $20 million, four-year unsecured credit facility (the "Chambers Facility") which bears interest at 9.5% per year. Resaca also has the option to pay interest under the Chambers Facility in kind for the first two years at an interest rate of 12% per year. The Chambers Facility contains certain financial ratio restrictions and other customary covenants. This credit facility matures December 31, 2014. Proceeds from the Chambers Facility were used to repay a portion of the CIT Facility, to fund future acquisitions and for general corporate purposes. In conjunction with the funding, Resaca issued warrants to the lenders under the Chambers Facility to purchase approximately 4.8 million shares of Resaca common stock at $1.93 per share. The purchase price for the Resaca common shares under the warrants is subject to customary weighted average dilution protections if Resaca issues stock at a price below the purchase price under the warrants. In addition, the exercise price and the number of shares the lenders are able to purchase under the warrants will be adjusted in the case of certain Company distributions, dilutive equity issuances, share subdivisions, or share combinations. The warrants were recorded and are adjusted every reporting period to fair value (See Note J). As a result of the issuance of stock as part of the purchase price for the Langlie Jal Unit as described in Note O, the warrant price was adjusted to $1.92 per share in August 2011. The Company has elected to pay interest in kind through December 1, 2012. As of June 30, 2011 the Company was not compliant with all of the covenants and received a waiver from Chambers for such noncompliance.
On January 7, 2011, the Company entered into a $75 million senior secured revolving credit facility (the "Regions Facility") with Regions Bank ("Regions"). The Regions Facility contains certain financial ratio restrictions and other customary covenants, including a requirement to hedge at least 75% of proved developed producing reserves through December 31, 2014. This credit facility matures January 7, 2014. Proceeds from the Regions Facility were used to repay a portion of the CIT Facility, to fund future acquisitions and for general corporate purposes. The Regions Facility is governed by semi-annual borrowing base redeterminations assigned to the Company's proved crude oil and natural gas reserves. An initial borrowing base of $33 million was established based on the Company's reserves and the borrowing base has not been redetermined. Under the Regions, Facility, $28.5 million was outstanding at June 30, 2011. The interest rate on outstanding borrowings was 4% at June 30, 2011. At June 30, 2011, the Company was in compliance with the covenants related to this facility.
Scheduled maturities as of June 30, 2011 are as follows:
Year Ending June 30,
--------------------- ----------
2012 -
2013 -
2014 30,543,973
2015 18,600,262
-------------------------- ----------
$ 49,144,235
--- ----------
Note F - Price Risk Management and Other Derivative Financial Instruments
The Company enters into hedging transactions with a major counterparty to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas zero-cost collars and swaps. Any gains or losses resulting from the change in fair value are recorded to unrealized gain (loss) from price risk management activities, whereas gains and losses from the settlement of hedging contracts are recorded in oil and gas revenues.
With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar.
Cash settlements for the years ended June 30, 2011, 2010 and 2009 resulted in a decrease in crude oil and natural gas sales in the amount of $1,970,796, $383,995, and $413,141, respectively.
Note F - Price Risk Management and Other Derivative Financial Instruments (Continued)
As of June 30, 2011, we had the following contracts outstanding:
Crude Oil Natural Gas
--------------------------------------------
Total Total Total
Volume Contract Asset Volume Contract Asset Asset
Period (Bbls) Price (1) (Liability) (MMBtus) Price (1) (Liability) (Liability)
($) ($) ($) ($)
------------ ------ ------------- --- ----------- ---- ---------- ----------- ----------------- ------------------
Collars
7/11 - 12/11 9,000 60.00/77.00 $ (920,926 ) 11,000 5.50/6.90 $ 75,409 $ (845,517 )
1/12 - 6/12 6,000 60.00/77.00 (730,836 ) (730,836 )
Swaps
7/11 - 12/11 1,700 82.45 (140,007 ) (140,007 )
7/11 - 5/12 1,300 102.05 58,813 58,813
1/12 - 6/12 3,900 84.05 (328,346 ) 7,500 6.30 73,250 (255,096 )
6/12 - 3/13 1,100 100.00 (5,691 ) (5,691 )
7/12 - 12/12 10,000 84.05 (923,100 ) (923,100 )
1/13 - 12/13 9,200 84.95 (1,613,442 ) (1,613,442 )
4/13 - 12/13 500 98.50 (9,990 ) (9,990 )
1/14 - 12/14 8,600 85.50 (1,348,988 ) (1,348,988 )
--------------- ------ ------------- ------------- --- ---------- ----------- --- --- ---------- ------ ------------
Total $ (5,962,513 ) $ 148,659 $ (5,813,854 )
--------------- ------ ------------- ------------- --- ---------- ----------- --- --- ---------- ------ ------------
(1) The contract price is weighted-averaged by contract volume.
The following table quantifies the fair values, on a gross basis, of all our derivative contracts and identifies its balance sheet location as of June 30, 2011:
Asset Derivatives (Liability) Derivatives
------------------------- ---------------------------
Balance Balance
Sheet Sheet Total Asset
Location Fair Value Location Fair Value (Liability)
----- ----------------------- ------------ ---------- ----------- ---------- -----------
Derivatives not
designated as hedging
instruments under
ASC 815
Commodity Contracts Derivative financial Derivative financial
instruments instruments
Current
Current Liability $ 211,011 Liability $ (2,123,561) $ (1,912,550)
Non-current Non-current
Liability - Liability (3,901,304) (3,901,304)
Non-current Non-current
Warrants Liability - Liability (2,081,200) (2,081,200)
Total derivatives
not designated
as hedging instruments
under ASC 815 211,011 (8,106,065) (7,895,054)
------------------------------ ------------ ---------- ----------- ---------- -----------
Total derivatives $ 211,011 $ (8,106,065) $ (7,895,054)
------------ ---------- ----------- ---------- -----------
While notional amounts are used to express the volume of puts and over-the-counter options, the amounts potentially subject to credit risk, in the event of nonperformance by the third parties, are substantially smaller. The Company does not anticipate any material impact to its financial position or results of operations as a result of nonperformance by third parties on financial instruments related to its option contracts.
Note G - Commitments and Contingencies
The Company, from time to time, is involved in certain litigation arising out of the normal course of business, none currently outstanding of which, in the opinion of management, will have any material adverse effect on the financial position, results of operations or cash flows of the Company as a whole.
On September 2, 2010, Cano filed an action against Resaca in the Tarrant County District Court seeking a declaratory judgment to clarify the scope and determine the amount of any expenses that are reimbursable by Cano under the Cano merger agreement. Resaca disputes the allegations by Cano and management believes the amount recorded on Resaca's balance sheet will ultimately be collected from Cano.
The Company had open letters of credit of approximately of $0 and $25,000 at June 30, 2011 and 2010, respectively, which were fully collateralized by restricted cash balances.
Note H - Initial Public Offering
On July 17, 2008, the Company completed an initial public offering on the AIM of the London Stock Exchange. In the initial public offering, the Company raised $83.4 million before expenses.
Note I - Share-Based Compensation
In conjunction with the initial public offering, certain officers and directors were granted restricted stock awards for an aggregate 821,103 shares of our common stock that vest ratably over three years, and, 341,357 stock options, each option to purchase one share of our common stock at an exercise price of 6.70 British pounds per share. The options were cancelled and new options for 341,357 shares were issued on January 18, 2011 with an exercise price of $1.61 and vesting period of one year and expiration date on January 8, 2019. The Company has adopted a Share Incentive Plan ("The Plan") to foster and promote the long-term financial success of the Company and to increase shareholder value by attracting, motivating and retaining key personnel. The Plan is considered an important component of total compensation offered to key employees and outside directors. The Plan consists of stock option and restricted stock awards. The Company expenses the fair-value of the share-based payments over the requisite service period of the awards. At June 30, 2011, there was $388,667 in unrecognized compensation expense related to non-vested restricted stock grants and non-vested stock option grants. We expect approximately $266,382, $84,064 and $38,221 to be recognized during the fiscal years 2012, 2013 and 2014, respectively. The restricted stock vests over a three-year period while the stock options vest over a three or one-year period. At June 30, 2011 there were 433,680 stock options and 242,948 shares of restricted stock outstanding. Additionally, the Board of Directors has the ability to authorize the issuance of another 621,144 stock options and restricted stock to key personnel.
The following summary represents restricted stock awards outstanding at June 30, 2011, 2010 and 2009:
Grant Date
Shares Fair Value
---------------------------- -------- ----------
Awards outstanding at June
30, 2009 821,103 $11,018,184
Restricted Shares vested (273,701) (3,672,728)
Restricted Shares forfeited - -
----------------------------- -------- ----------
Awards outstanding at June
30, 2010 547,402 $ 7,345,456
Restricted Shares vested (273,701) (3,672,728)
Restricted Shares forfeited (30,753) (412,666)
----------------------------- -------- ----------
Awards outstanding at June
30, 2011 242,948 $ 3,260,062
----------------------------- -------- ----------
For stock options, the Company determines the fair value of each stock option at the grant date using a Black-Scholes pricing model, with the following assumptions used for the grants made on the date indicated:
7/17/2008 1/21/2009 9/25/2009 11/16/2009 1/18/2011
--------------------------- ---------- ---------- ---------- ----------- ----------
Risk-free interest rate 3.35% 3.35% 2.37% 2.18% 1.97%
Volatility factor 50% 50% 81% 88% 74%
Expected dividend yield
percentage 0% 0% 0% 0% 0%
Weighted average expected
life in years 3.5 3.5 3.5 3.5 4.5
--------------------------- ---------- ---------- ---------- ----------- ----------
Note I - Share-Based Compensation (Continued)
Stock option awards have a three year or one year vesting period and expire five years or seven years after the vesting date. A summary of stock options awarded during the 12 months ended June 30, 2011, 2010 and 2009 is as follows:
Average Grant Date
Exercise
Shares Price Fair Value
---------------------------- -------- -------- ----------
Options outstanding at June
30, 2009 351,357 $ 10.48 $ 1,829,000
Grants 119,000 3.92 276,647
Exercised or
forfeited (10,000) (1.84) (6,463)
---------------------------- -------- -------- ----------
Options outstanding at June
30, 2010 460,357 $ 8.97 $ 2,099,184
Grants 341,347 1.61 323,883
Exercised or
forfeited (368,024) (10.23) (1,885,268)
---------------------------- -------- -------- ----------
Options outstanding at June
30, 2011 433,680 $ 2.11 $ 537,799
---------------------------- -------- -------- ----------
A summary of stock options outstanding at June 30, 2011 is as follows:
Converted Option Awards Remaining Option Awards
Exercise Exercise
Grant Date Price Price Outstanding Option Life Exercisable
----------- --------- --------- ------------- ----------- -------------
09/25/09 GBP 2.50 $ 4.00 * 79,000 6.24 26,333
11/16/09 GBP 2.35 3.74 * 13,333 0.64 13,333
01/18/11 $ 1.61 1.61 341,357 7.55 -
----------- --------- --------- ------------- ----------- -------------
$ 2.00 433,690 7.12 39,666
----------- --------- --------- ------------- ----------- -------------
*Exercise price is denominated in British pounds and has been converted at a rate of $1.6018 USD/GBP.
On June 17, 2011, the Resaca board of directors approved the issuance of 175,000 shares and 240,000 shares of restricted stock to certain Resaca executives and 120,000 of stock options to Resaca non-executive directors. These restricted shares and options were issued subsequent to June 30, 2011.
Note J - Fair Value Measurements
ASC 820 requires enhanced disclosures regarding the assets and liabilities carried at fair value. The pronouncement establishes a fair value hierarchy such that "Level 1" measurements include unadjusted quoted market prices for identical assets or liabilities in an active market, "Level 2" measurements include quoted market prices for identical assets or liabilities in an active market which have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but observable through corroboration with observable market data, including quoted market prices for similar assets, and "Level 3" measurements include those that are unobservable and of a highly subjective measure.
The fair value of the warrants was determined using a Monte Carlo valuation model. At June 30, 2011 the assumptions used in the model to determine the fair value of the outstanding warrants included the warrant exercise price of $1.93 per share, the Company's stock price at June 30, 2011 of $1.50 per share, volatility of 45% and a risk free discount rate of 0.9%.
Note J - Fair Value Measurements (Continued)
The Company utilizes the market approach for recurring fair value measurements of its oil and gas hedges. The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities that are accounted for at fair value on a recurring basis as of June 30, 2011. As required by ASC 820, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement:
Significant
Market Prices Other Significant
for Identical Observable Unobservable
Items (Level Inputs (Level Inputs (Level
1) 2) 3) Total
---------------------- ------------- ------------- ------------- ---------
Assets:
Oil and Gas Hedges $ - $ - $ - $ -
----------------------- ------------- ------------- -------------
Total Assets $ - $ - $ - $ -
----------------------- ------------- ------------- ------------- ---------
Liabilities:
Oil and Gas Hedges $ - $ 5,813,854 $ - $5,813,854
Derivative Warrants - - 2,081,200 2,081,200
----------------------- ------------- ------------- ------------- ---------
Total Liabilities $ - $ 5,813,854 $ 2,081,200 $7,895,054
----------------------- ------------- ------------- ------------- ---------
Total Net Liabilities $ - $ 5,813,854 $ 2,081,200 $7,895,054
----------------------- ------------- ------------- ------------- ---------
The carrying amounts of the Company's cash and cash equivalents, receivables and payables approximate the fair value at June 30, 2011 and 2010 because of their short-term maturities. The carrying amounts of the Company's debt instruments at June 30, 2011 and 2010 approximate their fair values due to either the interest rates being at market or minimal change during the period for the interest rates related to debt with fixed interest rates.
Note K - Income Taxes
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax provisions. The Company's income tax expense is composed of the following:
Years Ended June 30,
-------------------------------
2011 2010 2009
----------------------------- -------- ---------- -----
Current income tax expense
Federal $ - $ - $ -
State 375 2,458 -
----------------------------- -------- ---------- -----
Total current tax expense 375 2,458 -
----------------------------- -------- ---------- -----
Deferred income tax expense
Federal - - -
State - - -
----------------------------- -------- ---------- -----
Total deferred tax expense - - -
----------------------------- -------- ---------- -----
Total income tax expense $ 375 $ 2,458 $ -
----------------------------- ---- ------ -----
Note K - Income Taxes (Continued)
The significant components of the Company's deferred tax assets and liabilities are as follows:
Years Ended June 30,
-------------------------------
2011 2010
----- ------- ---------------------------------------- ---- --- -------------- --------------
Current
Deferred tax assets:
Unrealized loss on commodity derivatives $ 707,644 $ 332,744
Allowance for doubtful accounts 240,500 92,500
Inventory impairment 117,812 117,812
-------------------------------------- ---------------------- --- ---------- ----------
Total current deferred tax assets 1,065,956 543,056
Less valuation allowance (575,523) (304,780)
-------------------------------------- ---------------------- --- ---------- ----------
Net current deferred tax
assets $ 490,433 $ 238,276
-------------------------------------- ---------------------- --- ---------- ----------
Long-Term
Deferred tax assets:
Deferred compensation expense $ 808,842 $ 1,477,693
Net operating loss carryovers 8,792,827 6,782,687
Unrealized loss on commodity derivatives 1,228,587 275,542
Amortization of loan costs - -
-------------------------------------- ---------------------- --- ---------- ----------
Total long-term deferred tax assets 10,830,256 8,535,922
Less valuation allowance (5,847,397) (4,790,636)
-------------------------------------------------------------- --- ---------- ----------
Net long-term deferred tax assets 4,982,859 3,745,286
Deferred tax liabilities:
Depreciation, depletion and amortization (5,473,292) (3,983,562)
-------------------------------------------------------------- ---
Total long-term deferred tax liabilities (5,473,292) (3,983,562)
-------------------------------------------------------------- --- ---------- ----------
Net long-term deferred tax
liabilities $ (490,433) $ (238,276)
-------------------------------------- ---------------------- --- ---------- ----------
The following reconciles our income tax expense to the amount calculated at the statutory federal income tax rate:
Years Ended June 30,
-----------------------------------------
2011 2010 2009
------------- ---------- ----------
Income tax expense (benefit) at
statutory rate $ (2,538,819) $(2,864,279) $ 948,649
State taxes, less federal benefit (144,910) (163,279) 52,868
Deferred tax benefit recorded on conversion
to corporation - - (4,411,495)
Income attributable to period as
a partnership - - (26,204)
Reversal of benefit recorded on deferred
compensation 1,358,909 1,358,909 -
Change in valuation allowance 1,327,504 1,661,982 3,433,434
Permanent and other (2,309) 9,125 2,748
------------- ---------- ----------
Income tax expense $ 375 $ 2,458 $ -
============= ========== ==========
At June 30, 2011, 2010 and 2009, the Company had net operating loss ("NOL") carryforwards for federal income tax purposes of approximately $23.8 million, $18.3 million and $7.9 million, respectively. The NOLs will expire between 2029 and 2030.
A valuation allowance has been established with respect to the excess of the Company's deferred tax assets over its deferred tax liabilities at June 30, 2011 and June 30, 2010 because such net deferred tax assets do not meet the deferred tax asset realization criteria set forth in ASC 740 that it is more likely than not that the Company will realize a benefit of these net deferred tax assets in future periods.
The Company adopted ASC 740-10-25 for the twelve months ended June 30, 2009 as described in Note B. The adoption did not have an impact on the financial statements of the Company. There were no changes in unrecognized tax benefits during the 12 months ended June 30, 2011 or June 30, 2010. All tax benefits recognized relate to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions.
The Company files income tax returns in the U.S. (federal and state jurisdictions). Tax years 2008 to 2010 remain open for all jurisdictions. However, for the 2007 tax year, and the tax period from January 1, 2008 to July 10, 2008, the Company was a partnership for federal and New Mexico income tax purposes. Therefore, for those tax periods, any adjustments to the Company's taxable income would flow through to Resaca's partners in those jurisdictions. The Company's accounting policy is to recognize interest and penalties, if any, related to unrecognized tax benefits as income tax expense. The Company does not have an accrued liability for interest and penalties at June 30, 2011.
Note L - Stockholders' Equity
As described in Note A, the Company converted from a partnership to a corporation on July 10, 2008. As such, partners' capital was converted to stockholders' equity. At June 30, 2011, stockholders' equity was composed of the following:
Common Stock ($.01 par value) $ 196,632 Additional Paid-in Capital 97,408,857 Accumulated Deficit (25,049,039) ---------------------------- ------------- Total Stockholders' Equity $ 72,556,450 ---------------------------- -------------
On June 23, 2010, the Board of Directors approved a one for five reverse stock split effective June 24, 2010. At June 30, 2011, the Company had 230,000,000 common shares authorized and 19,663,157 shares issued and outstanding.
Note M - Employee Benefit Plans
Under the Resaca Exploitation, Inc 401(k) Plan (the "Plan") established in fiscal year 2009, contributions are made to the Plan by qualified employees at their election and our matching contributions to the Plan are made at specified rates. Our contribution to the Plan for the years ended June 30, 2011, 2010 and 2009 was $30,078, $34,094 and $16,043, respectively.
Note N - Liquidity
As of June 30, 2011, the Company had an accumulated deficit of approximately $25 million. Management believes that cash on hand, borrowings currently available under the Company's credit facility (approximately $4.5 million at June 30, 2011) and anticipated cash flows from operations will be sufficient to satisfy its currently expected working capital obligations and limited capital expenditure requirements through June 30, 2012. However, the Company may need to raise additional capital beyond what is currently available to further develop its properties. There can be no assurance that such capital will be available at terms acceptable to the Company, or at all.
Note O - Subsequent Events
On July 15, 2011 the Company sold the Grand Clearfork Field located in Pecos County, Texas for $4.1 million. On August 3, 2011 the Company purchased the Langlie Jal Unit located in Lea County, New Mexico for $8.3 million, comprised of $6.9 million in cash payment and the issuance of 845,254 shares of common stock.
Note P - Supplementary Financial Information for Oil and Gas Producing Activities (unaudited)
The Company has interests in oil and natural gas properties that are principally located in Texas and New Mexico. The Company does not own or lease any oil and natural gas properties outside the United States.
The Company retains independent engineering firms to provide year-end estimates of the Company's future net recoverable oil and natural gas reserves. Estimated proved net recoverable reserves as shown below include only those quantities that can be expected to be commercially recoverable. Estimated reserves for the years ended June 30, 2011 and 2010 were computed using benchmark prices based on the unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas during each month of the fiscal years ended June 30, 2011 and 2010, as required by SEC Release No. 33-8995, Modernization of Oil and Gas Reporting, effective for fiscal years ending on or after December 31, 2009, while estimated reserves for the fiscal year ended June 30, 2009 were based on oil and natural gas spot prices as of the end of the period presented. Costs were estimated using costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods.
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure is required for re-completion.
Note P - Supplementary Financial Information for Oil and Gas Producing Activities (unaudited) (Continued)
Costs Incurred in oil and natural gas producing activities are as follows:
Years ended June 30,
------------------------------------
2011 2010 2009
----------------------------------- ----------- --------- ----------
Acquisition of proved properties $ - $ - $ 7,000,000
Acquisition of unproved properties - - -
Development costs 15,474,077 4,381,933 12,987,934
Exploration costs - - -
---------- --------- ----------
Total costs incurred $15,474,077 $4,381,933 $19,987,934
------------------------------------ ---------- --------- ----------
The following reserves data only represent estimates and should not be construed as being exact.
Natural Total Reserves
Proved Reserves Oil (bbl) Gas (mcf) BOE
------------------ -------------- ---- ---------- ---------- --------------
June 30, 2008 14,731,580 18,940,840 17,888,387
Revision of prior estimates (2,795,448) (5,639,312) (3,735,334)
Extensions, discoveries and
other additions - - -
Improved recovery - - -
Production (189,276) (286,790) (237,074)
Purchases 220,974 284,113 268,326
Sales - - -
----------------------- --------- ---- ---------- ---------- --------------
June 30, 2009 11,967,830 13,298,851 14,184,305
Revision of prior estimates 556,830 (360,093) 496,815
Extensions, discoveries and
other additions - - -
Improved recovery - - -
Production (194,070) (243,168) (234,598)
Purchases - - -
Sales - - -
----------------------- --------- ---- ---------- ---------- --------------
June 30, 2010 12,330,590 12,695,590 14,446,522
Revision of prior estimates 453,724 (78,371) 440,662
Extensions, discoveries and
other additions - - -
Improved recovery - - -
Production (198,244) (235,349) (237,469)
Purchases - - -
Sales - - -
------------------ -------------- ---- ---------- ---------- --------------
June 30, 2011 12,586,070 12,381,870 14,649,715
---------------------------------------- ---------- ---------- --------------
Proved developed reserves,
June 30, 2009 6,722,220 7,501,841 7,972,527
Proved developed reserves,
June 30, 2010 6,978,160 6,855,640 8,120,767
Proved developed reserves,
June 30, 2011 7,226,270 6,737,960 8,349,263
---------------------------------- ---- ---------- ---------- --------------
Note P - Supplementary Financial Information for Oil and Gas Producing Activities (unaudited) (Continued)
Resaca Reserve Explanation:
For the reserves at June 30, 2009, the reduction for revisions of prior estimates pertain to reductions in estimated recoverable PDNP reserves at our Cooper Jal Complex Unit of 1,274 MBOE and other revisions of 2,461 MBOE related to the decline of commodity prices and forecast changes which reduce the economic life of our assets, as compared to proved reserves as of June 30, 2009. The specific field changes are as follows:
-- At the Cooper Jal Complex, PDP reserves decreased 652 MBOE due to commodity related price effects and production performance and were offset by a shift of 272 MBOE of reserves from the PUD category (net reduction of 380 MBOE). PDNP reserves decreased 1,274 MBOE due to a decrease in expected production rate based on performance. PUD reserves decreased 272 MBOE due to the drilling of 4 wells now contained in the PDP category and commodity related price effects.
-- At the Penwell Complex, PDP reserves decreased 264 MBOE, PDNP reserves decreased 880 MBOE, and PUD reserves decreased by 11 MBOE due to commodity related price effects.
-- At the Grand Clearfork Unit, PDP reserves decreased 110 MBOE, PDNP reserves decreased by 6 MBOE, and PUD reserves decreased by 12 MBOE due to commodity related price effects.
-- At Resaca's Minor Properties, PDP reserves decreased 416 MBOE, PDNP reserves decreased by 77 MBOE, and PUD reserves decreased by 33 MBOE due to commodity related price effects.
For the reserves at June 30, 2010, revisions of prior estimates provided an increase of 496 MBOE to total proved reserves. Forecast changes provided an overall increase of 383 MBOE, while extended economic limits provided an increase of 113 MBOE.
The specific field forecast changes are as follows:
-- At the Cooper Jal Complex, total proved reserves increased by 196 MBOE. This was comprised of a PDP increase of 534 MBOE due to commodity related price effects and production performance. This was offset by a decrease of 416 MBOE in the PDNP category due to forecast revisions and well activity, while PUD reserves increased 78 MBOE due to forecast revisions.
-- At the Penwell Complex, total proved reserves increased 117 MBOE due to forecast revisions. PDP reserves decreased 82 MBOE, PDNP reserves increased 177 MBOE due to the addition of six wells, and PUD reserves increased 22 MBOE due to forecast revisions.
-- At the McElroy Field, PDP reserves increased 59 MBOE based on forecast revisions.
-- At the Kermit Field, proved reserves decreased by 26 MBOE. PDP reserves decreased 42 MBOE based on forecast revisions, while PDNP reserves increase by 16 MBOE due to wells requiring workovers.
-- At Resaca's remaining minor fields, proved reserves increased by 37 MBOE based on forecast revisions.
For the reserves at June 30, 2011, revisions of prior estimates provided an increase of 441 MBOE to total proved reserves. Forecast changes provided an overall increase of 263 MBOE, while extended economic limits provided an increase of 178 MBOE.
The specific field forecast changes are as follows:
-- At the Cooper Jal Complex, total proved reserves decreased by 12 MBOE. This was comprised of a PDP increase of 347 MBOE due to performance revisions, offset by a decrease of 320 MBOE in the PDNP category as a result of project work performed, while PUD reserves decreased 39 MBOE due to forecast revisions
-- At the Edwards Grayburg Field, total proved reserves increased 135 MBOE in the PDP category due to a shift of reserves from the possible reserve category due to the reactivation of a waterflood in the field.
-- At the Jordan San Andres Field, total proved reserves increased 143 MBOE due to performance related to the expansion of the waterflood in the field and some contribution from the deeper San Andres formation.
-- At the McElroy Field, PDP reserves increased 76 MBOE based on forecast revisions.
Note P - Supplementary Financial Information for Oil and Gas Producing Activities (unaudited) (Continued)
-- At the Kermit Field, total proved reserves increased by 69 MBOE. The increase was in PDP reserves due to forecast revisions and reactivation of additional wells.
-- At Resaca's remaining minor fields, proved reserves increased by 30 MBOE based on forecast revisions.
Future Net Cash Flows:
The following table sets forth unaudited information concerning future net cash flows for oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities.
2011 2010 2009
----------------------------------- -------------- ------------ ------------
Future cash inflows $1,161,768,240 $969,357,000 $861,425,080
Future production costs 247,396,380 248,093,970 240,965,980
Future development costs 105,330,690 97,930,260 97,151,200
Future income tax expenses 260,767,366 193,329,417 154,507,384
------------- ----------- -----------
Future net cash flows 548,273,804 430,003,353 368,800,516
10% annual discount for estimating
timing of cash flows 337,516,680 262,692,278 232,638,214
------------- ----------- -----------
Standarized measure of discounted
future net cash flows $ 210,757,124 $167,311,075 $136,162,302
----------------------------------- ------------- ----------- -----------
Changes in Standardized Measure of Discounted Future Net Cash Flows:
2011 2010 2009
------------------------------------- ------------ ------------ ------------
Balance, beginning of year $167,311,075 $136,162,302 $ 445,776,281
Net changes in prices and production
costs 68,839,214 31,397,849 (422,942,878)
Net changes in future development
costs (18,353,529) (4,669,565) 1,582,866
Sales of oil and gas produced,
net (11,211,013) (8,948,939) (7,531,296)
Purchases of reserves - - 9,746,378
Sales of reserves - - -
Extensions and discoveries - - -
Revisions of previous quantity
estimates 10,701,688 9,157,783 (65,785,772)
Previously estimated development
costs incurred 15,474,077 4,381,934 5,953,630
Net change in income taxes (29,853,095) (17,108,769) 168,296,809
Accretion of discount 24,253,410 19,320,691 67,886,705
Timing differences and other (16,404,703) (2,382,211) (66,820,421)
------------------------------------- ----------- ----------- ------------
Balance, end of year $210,757,124 $167,311,075 $ 136,162,302
------------------------------------- ----------- ----------- ------------
Note Q - Director Compensation
During the year ended June 30, 2011, Resaca directors J.P. Bryan, Jay Lendrum, Judy Ley Allen, Richard Kelly Plato, and John William Sharp Bentley each received director's fees in the amount of $50,000. No equity grants were made and no salaries, bonuses or pension contributions were paid to or for the benefit of any Resaca directors during the year ended June 30, 2011. On June 17, 2011, the Resaca board of directors approved the issuance of 175,000 shares and 240,000 shares of restricted stock to certain Resaca executives and 120,000 of stock options to Resaca non-executive directors. These restricted shares and options were issued subsequent to June 30, 2011.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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