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$4 per million British thermal units ("MMBtu")) available under the Argentine Gas Plus program and an assumed increase in third-party gas plant revenues to reflect current market rates.
The GCA Report was prepared using assumptions and methodology guidelines consistent with the Canadian Oil and Gas Evaluation Handbook and in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities. The Company's natural gas and natural gas liquid reserves are located in the Province of Santa Cruz in Argentina.
Oil and Gas Reserves Based on Forecast Prices and Costs
| |
|
Natural Gas |
|
Natural Gas Liquids |
| Reserves |
|
Gross(1)
(MMcf)(2) |
|
Net(1)
(MMcf) |
|
Gross(1)
(Mbbl)(2) |
|
Net(1)
(Mbbl) |
| Proved Developed Producing(3)(6) |
|
1,098 |
|
928 |
|
18 |
|
16 |
| Proved Developed Non-Producing(3)(7) |
|
- |
|
- |
|
- |
|
- |
| Proved Undeveloped(3)(8) |
|
25,688 |
|
21,812 |
|
433 |
|
370 |
| Total Proved(3) |
|
26,786 |
|
22,740 |
|
451 |
|
386 |
| Total Probable(4) |
|
15,424 |
|
13,094 |
|
260 |
|
224 |
| Total Proved Plus Probable(3)(4) |
|
42,210 |
|
35,834 |
|
711 |
|
610 |
| Total Possible(5) |
|
14,366 |
|
12,198 |
|
242 |
|
207 |
| Total Proved Plus Probable Plus Possible(3)(4)(5) |
|
56,576 |
|
48,032 |
|
953 |
|
817 |
Net Present Values of Future Net Revenue Based on Forecast Prices and Costs
| Reserves |
|
Before Deducting Income Tax
Discounted at 10%
(US$MM) |
|
After Deducting Income Tax
Discounted at 10%
(US$MM) |
| Proved Developed Producing(3)(6) |
|
1 |
|
1 |
| Proved Developed Non-Producing(3)(7) |
|
- |
|
- |
| Proved Undeveloped(3)(8) |
|
35 |
|
26 |
| Total Proved(3) |
|
36 |
|
27 |
| Total Probable(4) |
|
87 |
|
57 |
| Total Proved Plus Probable(3)(4) |
|
123 |
|
84 |
| Total Possible(5) |
|
49 |
|
32 |
| Total Proved Plus Probable Plus Possible(3)(4)(5) |
|
172 |
|
116 |
| 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
| Year |
|
Gas
US$/MMbtu |
|
NGL
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
SOURCE: ArPetrol Ltd.
For further information:
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
