ArPetrol Ltd. announces financial and operating results for the fourth quarter and year-end 2014

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Apr 23, 2015, 08:30 ET

CALGARY, April 23, 2015 /CNW/ - ArPetrol Ltd. ("ArPetrol" or the "Company") (TSXV: RPT) is pleased to announce its financial and operating results for the three months and year ended December 31, 2014 and to provide an operational update on activities this year to date as well as an outlook for the remainder of 2015. The consolidated financial statements and management's discussion and analysis, have been filed on SEDAR at www.sedar.com and posted on the Company's website at www.arpetrol.com.

Fourth Quarter and Fiscal 2014 Summary

Operating and Financial

The Company's processing revenues, production sales, and funds flow from operations were all up significantly year-over-year (see Highlights table, below).

ArPetrol had working capital of $1.5 million at December 31, 2014, an improvement of almost $2.3 million from December 31, 2013.

The Company had drawn $1.0 million on its short-term loan at the end of the third quarter of 2014. The short-term loan was fully repaid at December 31, 2014. The Company had no long-tem debt at year-end.

The Company's midstreaming activities continue to provide strong revenues and operating netbacks (as defined below). During the fourth quarter of 2014 the Company's processed an average of 75 million cubic feet per day (Mmcf/d) of third-party natural gas compared to 76 Mmcf/d in the third quarter of 2014 and 77 Mmcf/d during the fouth quarter of 2013. Total year 2014 processing volumes were up by 2.5% versus total year 2013 but operating netbacks had improved by almost $800,000, or 25%, year over year.

The Company's fourth quarter production averaged 186 barrels of oil equivalent per day (boe) per day, a decrease of 58 boe per day from the third quarter of 2014. The lower production volumes were the result of the December maintenance shut-down. The fourth quarter 2014 average realized natural gas price was $4.43 per thousand cubic feet (Mcf), $0.40 per Mcf lower than the average price realized in the third quarter of 2014. The average price realized for natural gas liquids (NGL) in the fourth quarter of 2014 was $89.03 per barrel (bbl), an increase of $4.74 per bbl over the third quarter of 2014.

The Company made $114,282 in capital expenditures during the quarter and expended $325,000 on maintenance projects during a planned December shut-down. The maintenance project costs were charged to operating expenses during the quarter.

Summary of Results
		Three Months Ended Dec 31,		Year ended Dec 31,
		(Unaudited)
		2014	2013	2014	2013
Financial
(Cdn$ except shares outstanding)
Processing revenues		2,047,011	2,220,761	8,583,910	6,602,270
Production sales		543,366	432,047	2,594,807	1,995,079
Funds flow from operations ⁽¹⁾		59,073	(2,905,037)	1,037,039	(4,262,655)
Cash generated from (used in) operating activities		800,361	(2,135,525)	1,303,018	(3,929,268)
Net income (loss)		(73,804)	(290,350)	1,340,222	(3,726,040)
Capital expenditures		114,282	6,886	262,437	175,310
Weighted average shares outstanding (millions)
	– basic and diluted ⁽²⁾⁽³⁾	22,901,468	22,901,468	22,901,468	22,901,468
Per Share Funds flow from operations ⁽²⁾		0.00	(0.13)	0.05	(0.19)
Per Share Net income (loss)⁽²⁾		0.00	(0.01)	0.06	(0.16)

Operations

Processing
	Processing Volumes – Mcf per day	73,518	77,713	75,604	73,745
	Processing Revenue	2,047,011	2,220,761	8,593,910	6,602,270
	Operating Netback ⁽¹⁾	339,450	1,274,291	3,935,021	3,158,186
	Average Operating Netback - $ per Mcf processed ⁽¹⁾	0.04	0.18	0.15	0.12

Production
	Natural gas – Mcf per day	1,031	878	1,216	1,094
	NGL – bbls per day	15	18	20	23
	Total – boe per day ⁽¹⁾	186	164	223	205
Average sales price
	Natural gas – $ per Mcf	4.43	3.65	4.47	3.46
	NGL – $ per bbl	89.03	82.77	83.85	73.30
Average operating netback - $ per boe⁽¹⁾		(4.58)	(1.99)	3.03	0.64


Notes:
(1)	See advisories at the end of this news release with respect to non-IFRS measures and boe presentation.
(2)	All outstanding warrants, stock options and convertible debentures were excluded in calculating the weighted-average number of dilutive common share outstanding, as they were determined to be anti-dilutive.
(3)	On June 2, 2014, the Company completed a consolidation of its issued and outstanding common shares on the basis of 25 pre - consolidation common shares for each 1 post-consolidation common share. All share and per share numbers have been adjusted to reflect this consolidation.

All values in this news release are in Canadian dollars unless otherwise indicated.

Restatement of 2014 Prior Quarters

In the fourth quarter of 2014 the Company reclassified $2.6 million of non-cash foreign exchange gains from the Consolidated Statement of Net Income to the Consolidated Statement of Comprehensive Income. These gains had been initially recorded in the Consolidated Statement of Net Income in the second quarter of 2014.

As a result the changes to the revised quarter numbers are as follows:

$Cdn	Three Months Ended June 30, 2014	Six Months Ended June 30, 2014	Nine Months Ended September 30, 2014
Net Income (Loss) as previously reported	2,445,603	4,089,184	4,020,424
Reclassification of non-cash foreign exchange gains	(2,606,398)	(2,606,398)	(2,606,398)
Adjusted Net Income (Loss)	(160,795)	1,482,786	1,414,026
Other Comprehensive Income (Loss) as previously reported	(5,111,449)	(4,290,089)	(4,153,893)
Adjusted Other Comprehensive Income (Loss)	(2,505,052)	(1,683,691)	(1,547,495)
Per Share Net income (Loss) previously reported	0.11	0.18	0.18
Adjusted Per Share Net income (Loss)	(0.01)	0.06	0.06

This reclassification did not change the previously reported statement of financial position, cash flow from operating activities or funds flow from operations. The Company will restate 2014 comparative information with the reclassifications stated above in future 2015 quarterly filings.

Reserves

The Company has obtained an independent audit of the natural gas and natural gas liquid (NGL) reserves attributable to ArPetrol's interest in the Faro Virgenes concession as prepared by Gaffney, Cline & Associates Inc. effective December 31, 2014 (the "GCA Report").

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 NGL reserves are located in the Province of Santa Cruz, Argentina.

Summary of Oil and Gas Reserves Based on Forecast Prices and Costs
	Natural Gas		NGL
Reserves Category	Gross⁽¹⁾(MMcf)⁽²⁾	Net⁽¹⁾(MMcf)	Gross⁽¹⁾(Mbbls)⁽²⁾	Net⁽¹⁾(Mbbls)
Proved Developed Producing⁽³⁾⁽⁶⁾	-	-	-	-
Proved Developed Non-Producing⁽³⁾⁽⁷⁾	-	-	-	-
Proved Undeveloped⁽³⁾⁽⁸⁾	24,893	21,159	422	359
Total Proved⁽³⁾	24,893	21,159	422	359
Total Probable⁽⁴⁾	17,422	14,809	293	249
Total Proved Plus Probable⁽³⁾⁽⁴⁾	42,315	35,968	715	608
Total Possible⁽⁵⁾	14,807	12,586	248	211
Total Proved Plus Probable Plus Possible⁽³⁾⁽⁴⁾⁽⁵⁾	57,122	48,554	964	819

Net Present Values of Oil and Gas Future Net Revenue Based on Forecast Prices and Costs
Reserves Category	Before Deducting Income Tax Discounted at 10% (US$MM)	After Deducting Income Tax Discounted at 10% (US$MM)
Proved Developed Producing⁽³⁾⁽⁶⁾	-	-
Proved Developed Non-Producing⁽³⁾⁽⁷⁾	-	-
Proved Undeveloped⁽³⁾⁽⁸⁾	7	5
Total Proved⁽³⁾	7	5
Total Probable⁽⁴⁾	52	35
Total Proved Plus Probable⁽³⁾⁽⁴⁾	59	40
Total Possible⁽⁵⁾	50	32
Total Proved Plus Probable Plus Possible^(3)(4)(5)	109	72


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 previously have 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 previously have 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, comparable 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 NGL 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 net present values of future net revenue (forecast) are based on ArPetrol's future scenario of gas and NGL. The forecast gas prices start with US$3.65/MMBtu equivalent according to an existing contract, increasing to US$4.00/MMBtu in 2016, escalated at 4% per year thereafter. Future capital costs were derived from development program forecasts prepared by ArPetrol for the field. Recent historical operating expense data were utilized as the basis for operating cost projections. Capital and operating expenses were indexed at 4% per year since 2014 to account for inflation.
(13)	See advisories at the end of this news release with respect to non-IFRS measures and boe presentation

Processing Assets

In the 2014 GCA Report the treatment of third party processing fees was revised from prior years. In prior years fees collected from third party gas processing at the Company owned plant were included in the reserves calculation. Third party fees were removed from the calculation in 2014 in accordance with the Canadian Oil and Gas Evaluation Handbook. This change reduced both reserve volumes and corresponding reserve cash flows.

In total, however, future cash flows from the Company's assets in Argentina will still include cash flows from third party processing. The Company's mid-stream processing activities would be expected to add an estimated US$25 million to the total net present value of future net revenues (after deducting income tax, discounted at 10%). This is based on the estimated production profile for the third-party fields and resultant processing volumes multiplied by the standard processing fee under the current gas processing contract with the fee escalating at 2% per year.

Based on these assumptions the estimated net present value of future net revenue of proved plus probable reserves and third party processing fees was US$63 million at December 31, 2014 versus US$77 million at December 31, 2013 (all after deducting income tax, discounted at 10%).

Subsequent to December 31, 2014

In January 2015 the Company received approval to commence a normal course issuer bid permitting it to repurchase, for cancellation, up to 1,822,521 of its common shares. The normal course issuer bid commenced on January 6, 2015 and is approved for one year. To date the Company has purchased 122,000 of its common shares for $39,275 at an average price of $0.32 per share.

Outlook

ArPetrol has made significant progress towards a stable revenue generating company with a balance sheet that supports its operations and is expected to provide funds to pursue new initiatives.

ArPetrol continues to repatriate significant funds from Argentina to Canada through the repayment of intercompany loans. During the first three months of 2015, repayment of loan principal and interest to Canada totaled $700,000.

The Company's 2015 outlook includes estimated processing volumes of 70 to 80 MMcf/d and production of 190 to 240 boe/d.

The Company continues to look for farm-in partners to allow us to accelerate the development of the defined reserves at Faro Virgenes.

Finally, ArPetrol continues to evaluate at all strategic opportunities available to the Company. YPF S.A. and Enap SiPetrol Argentina S.A., the third-party providers of natural gas processed at the Company's Faro Virgenes plant, recently announced a significant multi-year expansion to their Magallanes field. We see this increase in activity in southern Santa Cruz as a positive sign for our business development activities in the region. Additionaly, we are actively pursuing new mid-stream opportunities through-out the region.

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 85 MMcf per day. The Company's common shares are listed on the TSXV under the symbol "RPT".

Forward-Looking Information

This news release contains certain forwardlooking information relating, but not limited, to the Company's reserves and related future net revenue, continued positive cash flow in 2015, processing revenue and cash flow, estimated production volumes and processing volumes, the pursuit of farm-in and growth opportunities, and the Company's ability to repatriate funds from Argentina to Canada. Forwardlooking information typically contains statements with words such as "anticipate", "believe", "forecast", expect", "plan", "intend", "estimate", "propose", "project", or similar words suggesting future outcomes. The Company cautions readers and prospective investors in the Company's securities not to place undue reliance on forwardlooking 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. Forward-looking information is based on management's current expectations and assumptions regarding, among other things, the ability to sustain consistent processing and production volumes, future production and processing revenue, future economic conditions, future currency and exchange rates, the ability to repatriate funds from Argentina, future pricing, continued political stability in the areas in which the Company is operating, the reduction of G&A and expenses, and the Company's continued ability to obtain and retain qualified management and staff and equipment in a timely and cost-efficient manner. 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; 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 disruptions at the gas plant, increased maintenance costs or other expenditures at the gas plant, interruptions to production and processing revenue, production declines, changes in commodity prices and revenues, increased costs, unavailability of funding, 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 forwardlooking information included herein is expressly qualified in its entirety by this cautionary statement. The forwardlooking information included herein is made as of the date hereof and the Company assumes no obligation to update or revise any forwardlooking information to reflect new events or circumstances, except as required by law.

Non-IFRS Measures

This news release includes references to financial measures commonly used in the oil and natural gas industry. The terms "operating netback" (production and processing revenue less royalties, turnover taxes and operating expenses) and "funds flow from operations" (cash generated from operating activities before changes in non-cash working capital) do not have any standardized meaning under International Financial Reporting Standards ("IFRS") and may not be comparable with similar measures presented by other companies. Funds flow from operations should not be considered an alternative to, or more meaningful than, cash generated from operating activities, net income (loss) or other measures determined in accordance with IFRS, as an indicator of the Company's performance.

See the management's discussion and analysis for the year ended December 31, 2014, filed on SEDAR at www.sedar.com and on the Company's website, for further discussion, including a reconciliation of funds flow from operations to cash generated from operating activities which is the most directly comparable measure calculated in accordance with IFRS. There is no IFRS measure that is reasonably comparable to operating netbacks and a detailed calculation of such netbacks is presented in the "Results of Operations" section.

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. The 6:1 conversion ratio 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

	Natural Gas	NGL
Year	(US$/MMBtu)	(US$/bbl)
2015	3.65	71.00
2016	4.00	73.15
2017	4.16	75.37
2018	4.33	77.65
2019	4.50	80.00
2020	4.68	83.20
2021	4.87	86.53
2022	5.06	89.99
2023	5.26	93.59
2024	5.47	97.34
2025	5.69	101.23
2026	5.92	105.28

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 NGL 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 NGL 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.

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 including additional information on the risks and level of uncertainty associated therewith, will be contained in the Company's statement of reserves data and other oil and gas information for the year ended December 31, 2014 which is available on SEDAR at www.sedar.com.

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.