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.
-- 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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