ArPetrol Ltd. Engages Advisor for Strategic Review Process and Provides Update on Reserves, Gas Plant, Operations and Financial

ArPetrol Ltd. Engages Advisor for Strategic Review Process and Provides Update 
on Reserves, Gas Plant, Operations and Financial Condition 
CALGARY, Jan. 15, 2013 /CNW/ - ArPetrol Ltd. ("ArPetrol" or the "Company") 
(TSXV: RPT) provides the following update regarding its strategic review 
process, reserves, gas plant, operations and financial condition. 
Strategic Review Process 
The board of directors of the Company (the "Board") continues to believe in 
the underlying value of its assets, as demonstrated by the latest reserves 
review that has been conducted, and has initiated a process to identify, 
examine and consider a broad range of strategic alternatives available to the 
Company. The Company has retained Raymond James Ltd. ("Raymond James") as its 
financial advisor to assist the Board with its strategic review process. 
Raymond James will assist in the identification, evaluation and negotiation of 
potential strategic transactions including, but not limited to, a financing, 
farm-out, joint venture, merger, sale of the Company, disposition of assets or 
other strategic transaction involving a third party. 
Reserves 
The Company has obtained an independent audit of the natural gas and natural 
gas liquid reserves attributable to ArPetrol's interest in the Faro Virgenes 
concession as prepared by Gaffney, Cline & Associates Inc. effective December 
31, 2012 (the "GCA Report"). 
The GCA Report presented a 3% decrease in proved plus probable natural gas 
reserves (gross) from 43,369 million cubic feet ("MMcf") as of December 31, 
2011 to 42,210 MMcf as of December 31, 2012. This decrease was due to volumes 
produced in 2012 and an adjustment to gas shrinkage. The GCA Report also 
presented a 28% increase to the net present value of future net revenue of 
proved plus probable reserves (before deducting income tax; discounted at 10%) 
from US$96 million as of December 31, 2011 to US$123 million as of December 
31, 2012. This increase was due to a combination of higher realized natural 
gas pricing (US$4 per million British thermal units ("MMBtu")) available under 
the Argentine Gas Plus program and an assumed increase in third-party gas 
plant revenues to reflect current market rates. 
The GCA Report was prepared using assumptions and methodology guidelines 
consistent with the Canadian Oil and Gas Evaluation Handbook and in accordance 
with National Instrument 51-101, Standards of Disclosure for Oil and Gas 
Activities. The Company's natural gas and natural gas liquid reserves are 
located in the Province of Santa Cruz in Argentina. 
Oil and Gas Reserves Based on Forecast Prices and Costs 
                           Natural Gas         Natural Gas Liquids 
                  Gross((1) )   Net((1) )   Gross((1) )   Net((1) )
Reserves              (MMcf)((2))    (MMcf)     (Mbbl)((2))    (Mbbl) 
Proved Developed          1,098         928           18           16
Producing((3)(6)) 
Proved Developed             -            -            -            -
Non-Producing((3)
(7)) 
Proved Undeveloped(      25,688       21,812          433         370
(3)(8)) 
Total Proved((3))        26,786       22,740          451         386 
Total Probable((4))      15,424       13,094          260         224 
Total Proved Plus        42,210       35,834          711         610
Probable((3)(4)) 
Total Possible((5))      14,366       12,198          242         207 
Total Proved Plus        56,576       48,032          953         817
Probable Plus
Possible((3)(4)(5)) 
Net Present Values of Future Net Revenue Based on Forecast Prices and Costs 


                          Before Deducting    After Deducting Income
                            Income Tax                 Tax


                     Discounted at 10%      Discounted at 10%
Reserves                      (US$MM)                (US$MM) 
Proved Developed                     1                       1
Producing((3)(6)) 
Proved Developed                     -                       -
Non-Producing((3)(7)) 
Proved Undeveloped((3)               35                      26
(8)) 
Total Proved((3))                    36                      27 
Total Probable((4))                  87                      57 
Total Proved Plus                   123                      84
Probable((3)(4)) 
Total Possible((5))                  49                      32 
Total Proved Plus                   172                     116
Probable Plus Possible
((3)(4)(5)) 
Notes:   
(1)    "Gross Reserves" are ArPetrol's working interest (operating or 


       non-operating) share before deduction of royalties and without
       including any royalty interests of ArPetrol. "Net Reserves" are
       ArPetrol's working interest (operating or non-operating) share
       after deduction of royalty obligations plus ArPetrol's royalty
       interests in reserves.

(2)    "MMcf" means million cubic feet and "Mbbl" means thousand
       barrels.

(3)    "Proved" reserves are those reserves that can be estimated with
       a high degree of certainty to be recoverable. It is likely that
       the actual remaining quantities recovered will exceed the
       estimated proved reserves.

(4)    "Probable" reserves are those additional reserves that are less
       certain to be recovered than proved reserves. It is equally
       likely that the actual remaining quantities recovered will be
       greater or less than the sum of the estimated proved plus
       probable reserves.

(5)     "Possible" reserves are those additional reserves that are less
       certain to be recovered than probable reserves. There is a 10%
       probability that the quantities actually recovered will equal or
       exceed the sum of the estimated proved plus probable plus
       possible reserves.

(6)     "Developed Producing" reserves are those reserves that are
       expected to be recovered from completion intervals open at the
       time of the estimate. These reserves may be currently producing
       or, if shut in, they must have previously been on production,
       and the date of resumption of production must be known with
       reasonable certainty.

(7)    "Developed Non-Producing" reserves are those reserves that
       either have not been on production, or have previously been on
       production but are shut in and the date of resumption of
       production is unknown.

(8)    "Undeveloped" reserves are those reserves expected to be
       recovered from known accumulations where a significant
       expenditure (for example, when compared to the cost of drilling
       a well) is required to render them capable of production. They
       must fully meet the requirements of the reserves classification
       (proved, probable, possible) to which they are assigned.

(9)    The reserve estimates provided herein are estimates only and
       there is no guarantee that the estimated reserves will be
       recovered.

(10)   Actual natural gas and natural gas liquid reserves may be
       greater than or less than the estimates provided herein.

(11)   The future net revenue estimates provided herein do not
       represent fair market value.

(12)   The pricing assumptions used in the GCA Report with respect to
       the net present value of future net revenue are set forth below.
       Cost assumptions are based on background project work conducted
       in 2011 which has been updated to reflect actual costs incurred
       in the 2012 Faro Virgenes drilling program and have been
       inflated at historical rates. The GCA Report assumes an increase
       in gas plant revenues due to the upcoming expiry of the existing
       gas processing contracts at the end of June 2013 and the
       assumption that new gas processing contracts will be achieved at
       market rates.

Gas Plant

The Company owns and operates a 100% interest in a gas processing plant with 
processing capacity of 85 MMcf/d, strategically located on the Faro Virgenes 
concession. The gas plant processes third party natural gas and liquids 
production, in addition to the Company's production from the Faro Virgenes 
concession. As most of the gas processed by the plant originates from third 
parties, the gas plant historically generated cash flow for ArPetrol 
independent of production or drilling results from the Faro Virgenes 
concession. Given the long useful life of the gas plant, ArPetrol expects the 
gas plant to continue to generate a stream of cash flow. Due to the upcoming 
expiry of the existing gas processing contracts at the end of June 2013, 
ArPetrol expects to negotiate new gas processing contracts at current market 
rates.

Operations update

Production volumes for the fourth quarter of 2012 were 252 barrels of oil 
equivalent per day ("boe/d"). This exceeded the total year average production 
volume of 247 boe/d. Average prices for natural gas and natural gas liquids 
for the fourth quarter were $2.80 per MMcf and $65.49 per barrel, 
respectively, compared to total year average prices of $2.83 per MMcf for 
natural gas and $68.95 per barrel for natural gas liquids.

Third-party processing volumes for the fourth-quarter of 2012 averaged 74 MMcf 
per day. This is an increase from the total year average third-party 
processing volumes of 68 MMcf per day.

Financial Condition and Outlook

ArPetrol has continued to meet with service providers regarding outstanding 
costs associated with its drilling program on the Faro Virgenes concession. 
ArPetrol expects a working capital deficiency as of December 31, 2012. 
ArPetrol is attempting to reduce its shortfall and to manage payment schedules 
with service providers for which it is behind in payments to allow sufficient 
time to provide a long-term solution for the Company. There is uncertainty 
regarding the Company's ability to continue to operate as a going concern. 
Additional information regarding ArPetrol's financial position can be found in 
the Company's financial statements and management's discussion and analysis 
for the three and nine months ended September 30, 2012 which are available on 
SEDAR at www.sedar.com.

About ArPetrol Ltd.

ArPetrol is a Calgary-based publicly traded company engaged in oil and natural 
gas exploration, development and production and third-party natural gas 
processing in Argentina, where it owns and operates a gas processing facility 
with capacity of 85MMcf per day. The Company's common shares are listed on the 
TSXV under the symbol "RPT".

Forward-Looking Information

This news release contains certain forward‐looking information relating, but 
not limited, to the Company's reserves and related future net revenue, the 
expected working capital deficiency, the ability the Company to reduce its 
shortfall and manage payment schedules with contractors, the ability to 
negotiate new gas processing contracts upon expiry of the existing contracts 
and achieve increased revenue thereunder, the continued generation of cash 
flow from the gas plant, the Company's ability to continue to operate as a 
going concern and the availability of future financing or another strategic 
alternative. The Company cautions readers and prospective investors in the 
Company's securities not to place undue reliance on forward‐looking 
information as, by its nature, it is based on current expectations regarding 
future events that involve a number of assumptions, inherent risks and 
uncertainties, which could cause actual results to differ materially from 
those anticipated by the Company. A number of factors could cause actual 
results to differ materially from those anticipated by the Company, including 
but not limited to risks associated with the oil and natural gas industry 
(e.g., operational risks in demobilization, or reactivating, drilling and 
completing the well; the ability to retain staff and equipment; and health, 
safety and environmental risks), weather delays and natural disasters, union 
activities, change in government policies, currency fluctuations and controls, 
a change in the manner and rates at which the Company is exchanging its 
currency, the risk of the expiry of the existing gas processing contracts 
without having new contracts in place, the risk of interruptions to production 
and processing revenue, production declines, changes in commodity prices and 
revenues, increased costs, unavailability of funding or a strategic 
alternative or transaction, and other risks associated with international 
activity and Argentina. ArPetrol operates outside of Canada and as such, is 
subject to a number of political risks over which it has no control. The 
forward‐looking information included herein is expressly qualified in its 
entirety by this cautionary statement. The forward‐looking information 
included herein is made as of the date hereof and the Company assumes no 
obligation to update or revise any forward‐looking information to reflect 
new events or circumstances, except as required by law.

Reserves and Oil and Gas Advisories

BOE Presentation. Production information is commonly reported in units of 
barrels of oil equivalent. For purposes of computing such units, natural gas 
is converted to equivalent barrels of oil using a conversion factor of six 
thousand cubic feet to one barrel. This conversion ratio of 6:1 represents 
energy equivalency, which is primarily applicable at the burner tip, and does 
not represent a value equivalency at the wellhead. Such disclosure of boe may 
be misleading, particularly if used in isolation.

Price Deck Assumptions


     Gas        NGL 
Year   US$/MMbtu   US$/bbl 
2013      2.50      70.00 
2014      4.00      73.50 
2015      4.20      77.18 
2016      4.41      81.03 
2017      4.63      85.09 
2018      4.86      89.34 
2019      5.11      93.81 
2020      5.36      98.50 
2021      5.63     101.45 
2022      5.91     104.50 
2023      6.21     107.63 
2024      6.52     110.86 
2025      6.84     114.19 
2026      7.18     117.61 
There are numerous uncertainties inherent in estimating quantities of reserves 
and related future net revenue. The reserves and related future net revenue 
set forth above are estimates only. In general, estimates of economically 
recoverable natural gas and natural gas liquid reserves and the related future 
net revenue are based upon a number of variable factors and assumptions, such 
as historical production from the properties, production rates, ultimate 
reserve recovery, timing and amount of capital expenditures, the scope and 
timing of the development program, expected pricing and gas processing 
revenue, marketability of oil and natural gas, royalty rates, the assumed 
effects of regulation by governmental agencies and future operating costs, all 
of which may vary materially. For these reasons, estimates of the economically 
recoverable natural gas and natural gas liquid reserves attributable to any 
particular group of properties, classification of such reserves based on risk 
of recovery and estimates of future net revenues associated with reserves 
prepared by different engineers, or by the same engineers at different times, 
may vary. The Company's actual production, revenues, taxes and development and 
operating expenditures with respect to its reserves will vary from estimates 
thereof and such variations could be material. Additional information 
regarding ArPetrol's reserves data and the risks and the level of uncertainty 
associated therewith can be found in the Company's annual information form for 
the year ended December 31, 2011 which is available on SEDAR at www.sedar.com. 
The reserve data provided in this news release presents only a portion of the 
disclosure required under National Instrument 51-101, Standards of Disclosure 
for Oil and Gas Activities. All of the required information will be contained 
in the Company's annual information form for the year ended December 31, 2012 
which will be available on SEDAR at www.sedar.com prior to the end of April, 
2013 once ArPetrol has completed the audit of its financial and operating 
results for the year. 
Additional information relating to the Company is also available on SEDAR at 
www.sedar.com.  
Neither the TSXV nor its Regulation Services Provider (as defined in the 
policies of the TSXV) accepts responsibility for the adequacy or accuracy of 
this release 
Tim Thomas, President and Chief Executive Officer t.thomas@arpetrol.com 
Or 
Ian Habke, Chief Financial Officer i.habke@arpetrol.com 
ArPetrol Ltd. Main Phone: 403-263-6738  
SOURCE: ArPetrol Ltd. 
To view this news release in HTML formatting, please use the following URL: 
http://www.newswire.ca/en/releases/archive/January2013/15/c5883.html 
CO: ArPetrol Ltd.
ST: Alberta
NI: OIL  
-0- Jan/15/2013 14:21 GMT
 
 
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