Petro One Energy Corp.
TSX VENTURE : POP
PINKSHEETS : CUDBF
FRANKFURT : C6K1

Petro One Energy Corp.

April 03, 2012 08:00 ET

Petro One-Q3 Update

VANCOUVER, BRITISH COLUMBIA--(Marketwire - April 3, 2012) - Petro One Energy Corp. (TSX VENTURE:POP)(PINKSHEETS:CUDBF)(FRANKFURT:C6K1) is pleased to report that development work is continuing at its Milton Viking field, credited by the Company's independent petroleum engineers during 2001 with 1.74 million BOEs of NI 51-101 proved + probable + possible reserves.

All six Milton wells are currently in test production, are producing oil and running smoothly. They are in the process of being fine-tuned to optimize production. The Company's business plan calls for it to continue that process into the early summer with the objective of establishing sustained and predictable production over a minimum three month period. As previously announced, the Company also plans to drill one or more horizontal wells in the Viking formation.

Set out below is selected information from the Company's interim Financial Statements and related Management Discussion & Analysis for the nine month period ended January 31, 2012. For additional information reference should be made to the full filings, which are available at sedar.com.

Testing of the discovery well, 10A-15- 30-27W3 was suspended temporarily during December, 2011 to install a pumpjack, considered desirable to establish consistent production over the long term, and bad winter weather thereafter resulted in several additional interruptions, but the well was nonetheless fully equipped and tested on pump for 256 hours during January, and production testing increased to 410 hours during February and 684 hours (28.5 days) during March. During testing, technical issues such as sanding and waxing, considered normal in the Viking, were satisfactorily resolved. The following table sets out the results of the test work received to date on 10A-15- 30-27W3.

Month Number
of
Production
Days
Calculated
BOPD
(1)
Gross
Oil
Sales
from
Test
Production
(2)
Natural
Gas
Mcf/day
(3)
BOE/day
(4)
July 2011 6.6 20.8 $3,128 947 179
August 2011 28.2 25.3 $52,900 469 103
September 2011 10.8 33.8 $38,213 454 109
October 2011 17.7 46.9 $54,354 236 86
November 2011 15.6 32.7 $36,500 217 69
December 2011 13.5 36.2 $22,341 197 69
January 2012 10.7 15.6 $15,828 34 21
Total $223,264
February 2012 17.1 10.9* $21,504 51 19
March 2012 28.5 15.5* Sale Proceeds Pending 98.37 31.96
* An estimate of oil production based on an on-site measurement of emulsion (oil and water) produced, assuming a 70% water cut. At a 50% water cut, the production would be 25.94 bopd.
(1) BOPD is calculated by dividing the total oil volume produced by the number of production days.
(2) Oil sales data is not yet available for March, 2012.
(3) Natural gas was flared and therefore did not add to revenues. Gas volumes for January - March 2012 are approximate.
(4) BOE means barrels of oil equivalent. It may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy efficiency conversion method primarily applicable at the burner tip, and does not represent a value equivalency at the wellhead.

Proceeds from sales of oil from well 10A-15 totaled $223,264 to January 31, 2012. In accordance with generally accepted accounting principles, proceeds from oil sales prior to January, 2012 have been recorded in the Company's financial statements as a reduction of capital expenses rather than as revenue from operations. The 10A-15- 30-27W3 well was re-classified from a test well to a production well in January, 2012, and proceeds from oil sales from that well are now being booked as revenue.

Test work conducted on the initial two wells (10A-15 and 11-15) during late 2011 indicated the need for an artificial lift system and the use of a wax inhibitor, as well as careful monitoring of casing and tubing pressures. As a result, testing of the remaining wells was temporarily suspended during the late fall until 10A-15 could be further evaluated and provide guidance for testing production from the other four wells. The resolution of the technical issues at 10A-15 has served as a guide to complete and production test the other five wells, all of which are now online and operating smoothly.

The other five wells all have confirmed oil production in the initial testing, but the Company does not yet have any oil production numbers for those wells because none of the oil has been delivered to the purchaser. At the time of this news release, the Company has only the emulsion (oil + water) production figures for test work on those wells, which results are tabulated below. The Company anticipates full initial production reports by early summer. The Company does not have the actual water cuts for those emulsions, so it is not possible to calculate actual oil production from those wells at the present time. However, water cuts of 50% and 70% are considered representative of the typical range of water cuts observed to date in the Milton wells after initial production, and estimates of oil production for March, 2012 are presented assuming the application of those water cuts.

Well Days
Oil
prod-
uced
in
March
2012
Oil
Production
Estimates
(1)
(bopd)
Days
Gas
prod-
uced
in
March
2012
Natural
Gas
Mcf/
day
BOE/day
Estimates
(1)
Emulsion
(bbl/day)
Oil
50%
Oil
30%
Oil
50%
Oil
30%
15-15- 30-27W3 22 59.83 29.91 17.95 18.21 25.14 34.10 22.14
11-15- 30-27W3 24 31.45 15.72 9.43 23.42 55.14 24.96 18.67
8-15- 30-27W3 11 38.01 19.00 11.40 2.0 1.47 19.25 11.65
7-15- 30-27W3 10 50.31 25.16 15.10 8.0 17.75 28.12 18.05
6-15- 30-27W3 22 73.94 22.18* 7.39* 21.625 230.59 60.61* 45.83*
* Well 6-15- 30-27 currently appears to be producing a greater percentage of water and greater volume of natural gas than the other Milton wells. Therefore, bopds are presented based on estimated water cuts of 70% and 90% instead of 50% and 70%. At a 50% water cut, the estimated oil production would be 36.97 bopd and the BOE/day would be 75.40.
(1) These are estimates only, based on water cuts of 50% and 70% respectively, which represent the range of water cuts observed to date in the Milton wells. Readers are cautioned that actual results will depend on the actual water cuts and will therefore vary, perhaps significantly, from the estimates set forth above.
(2) Natural gas is being flared and will therefore not add to revenues until and unless it is tied into a gas pipeline located on the property. Gas volumes are approximate.
(3) BOE means barrels of oil equivalent. It may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy efficiency conversion method primarily applicable at the burner tip, and does not represent a value equivalency at the wellhead.

By-product natural gas has been produced by some of the wells during testing. Preliminary work is underway to investigate the economics of a gathering system for the by-product gas from Petro One's Milton Viking field. A riser has been located on the northwest property boundary that provides a direct tie-in to an active pipeline operated by Altagas, and Petro One has been informed that the line has spare capacity. Additional testing will be necessary to determine whether a tie-in will be economic based on gas volumes produced over the next three months.

Core and logs have shown that the entire 10-metre thick Viking pay zone in the discovery hole is porous and oil bearing. A fluid sample analyzed by Core Laboratories in Calgary consisted of water-free oil with an API gravity of 30.6 at 15.6°C. Core analysis of the discovery well returned porosity values ranging from 16.8 to 23.5% with an arithmetic average of 21.2%, and permeability measurements ranged from 1.30 to 3,980 millidarcies with an arithmetic average of 1,035.90 millidarcies. Areas of lower seismic amplitude at the base of the Viking are interpreted to indicate higher porosity, and indicate some locations that are likely to have higher porosity than the initial discovery well. Geological maps incorporating the new data from the summer's drilling outline a 4 by 0.75 kilometre structural trough in the Viking that cuts across the property and remains open. Conglomerate in the lower Viking like that in the discovery well has been recognized in Petro One 6A-15- 30-27W3, and also in 11-9- 30-27W3 to the southwest, which drill stem tested 130,000 cubic feet of gas and 410 cubic feet of oil cut mud from the Upper Viking. Based on high resolution seismic, the Company has been credited with at least 20 undeveloped Viking drill locations on the property, and has tripled the size of its Milton acreage to three sections (777 hectares).

The underlying Middle Bakken sand is thick and a prolific producer in this area, and is located only 140 metres below the Viking, making it an attractive secondary target that can be tested for minimal extra cost. Based on recent seismic time structure mapping, Petro One has been credited with a best estimate NI 51-101 prospective resource of 798,000 barrels of oil in the Bakken, and a total of 9 Bakken drilling locations have been identified. The nearest producing oil wells in the Hoosier Bakken field are only 1.2 kilometres east of the nearest structural trap identified on Petro One's seismic. The Mannville, Success, and Birdbear formations were also identified in the report as secondary targets to be tested. The Company is in the process of making plans to drill the strongest of these deeper targets during the upcoming Viking development drilling program.

On November 16, 2011, the Company reported that the initial drill hole, 11-29-4-23W1, on its 100% owned J1 Rosebank property was successful. During initial testing, the well demonstrated a flow rate of 40 barrels per day of 30 degree API oil from limestone from both the Frobisher-Alida zone. Based on this result, Petro One was credited with NI 51-101 compliant proved + probable + possible reserves of 510,000 barrels of oil as shown in the table above, and three undeveloped horizontal and three undeveloped vertical drilling locations on the property. Shortly after that early test, the water cut increased to the point that the well was shut in pending further study. The water cut increase is believed by the Company's independent consultants to be attributable to the lower Alida zone. Therefore, the Company's independent consultants subsequently recommended that a horizontal leg approximately 600 metres in length be drilled from the existing wellbore into the adjacent portion of the oil bearing upper Frobisher.

Private Placement

Petro One also announces that it is in the process of completing the last of the deliveries against payment in connection with its non-brokered private placement announced on January 20, 2012 and increased to $2,450,000 on March 14, 2012. Proceeds from the financing will be used to fund expenses associated with the development of the Company's oil and gas properties.

The Company has paid to Aberdeen Gould Capital Markets Ltd. and its selling group, in the aggregate, cash finders' fees totaling $100,081.39, which is equal to 6% of the gross proceeds from a portion of the offering. In addition, the Company has issued finder's warrants exercisable to purchase 166,801 shares, which is equal to 6% of a portion of the Units issued by the Company pursuant to the offering. Each finder's warrant will be exercisable at the price of $0.80 until March 15, 2014, subject to acceleration at the Company's option if its shares close at $1.20 or higher for twenty (20) consecutive trading days at any time after four months after Closing. All shares and warrants issued pursuant to the offering are subject to a four-month hold period expiring at midnight on July 15, 2012. Any shares issued pursuant to the exercise of warrants or finders' warrants will also be subject to a four-month hold period expiring at midnight on July 15, 2012.

Petro One has 14 stand-alone properties in Saskatchewan and Manitoba, all of which have been credited with Independent NI 51-101 reserves and or prospective resources. In-depth technical reviews were recently completed to rank these properties in order of priority in readiness for drilling and or development.

NATIONAL INSTRUMENT 51-101 DISCLOSURE

The reserve and prospective resource estimates in this document were prepared by an independent qualified reserves evaluator in the form of a Form 51-101F1 report (the "Report") under National Instrument 51-101 ("NI 51-101") in accordance with the Canadian Oil and Gas Evaluation Handbook. It augments and updates an initial 51-101 report by the same evaluator dated June 1, 2010. These estimates were based on information available up to November 10, 2011. The reserves evaluator has consented in writing to the disclosure of information derived from the Report. Pursuant to s. 5.2 of NI 51-101, the Company advises that the estimates have been made assuming the development of the J5 Milton and J1 Rosebank properties will occur, without regard to the likely availability to the Company of funding required for that development.

BOE means barrels of oil equivalent. It may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy efficiency conversion method primarily applicable at the burner tip, and does not represent a value equivalency at the wellhead.

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.

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 + probable reserves.

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

Prospective resources described in the NI 51-101 Report and in this document are "undiscovered resources" as defined in the Canadian Oil and Gas Evaluation Handbook. Undiscovered resources are defined as those quantities of oil and gas estimated on a given date to be contained in accumulations yet to be discovered. The estimates of the potentially recoverable portions of undiscovered resources are classified as prospective resources. Prospective resources are defined as those quantities of oil and gas estimated on a given date to be potentially recoverable from undiscovered accumulations. They are technically viable and economic to recover. Pursuant to s. 5.9(d)(v) of NI 51-101, the Company cautions that that there is no certainty that any portion of the resource will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resource.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

Oil production during a period is generally expressed in terms of "barrels per day", which indicates the total oil produced during a period divided by the number of hours that the well was in production during that period. "Barrels per day" is indicative of flow rate while a well is in production and does not mean that such well was in constant production during such period.

ON BEHALF OF THE BOARD

Peter Bryant, President & Director

For further information, please visit the company's website at www.PetroOneEnergy.com.

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

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