PINECREST ENERGY INC The Company also announces that its audited consolidated financial statements and the related Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2015 have been filed on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com and are available on the Company's website at www.virginiahillsoil.com.
On April 15, 2015, the Company completed a corporate reorganization as part of a plan of arrangement (the "Arrangement") pursuant to section 193 of the Business Corporations Act (Alberta). Pursuant to the Arrangement, the common shareholders of Pinecrest Energy Inc. ("Pinecrest") became the shareholders of the Company and approximately 90% of Pinecrest's oil and gas assets, and substantially all of the other assets and liabilities were transferred to the Company. The common shares of Pinecrest were then sold to Cardinal Energy Ltd. for cash proceeds of $23.5 million, of which $1.0 million was placed into escrow to satisfy certain closing adjustments.
As a result of the Arrangement, Virginia Hills owns substantially the same assets owned by Pinecrest immediately prior to the Arrangement. The Arrangement has been accounted for on a continuity of interest basis as Virginia Hills had always carried on the business formerly carried on by Pinecrest. Unless otherwise indicated, all information presented for the pre-Arrangement period in this press release is that of Pinecrest.
Increased proved ("1P") reserves by 43% year over year to 5.3 million barrels of oil equivalent ("Mboe") with a net present value, discounted at 10% ("NPV10") of $71.9 million and reserve life index ("RLI")1 of
9.7 years;
Increased proved plus probable ("2P") reserves by 20% year over year to 7.9 Mboe replacing annual production of 553,000 boes by 338%2 with an NPV10 of $116.6 million and an RLI of 14.3 years;
2P Reserves were weighted 97% to light oil at year end 2015;
Finding and Development Costs ("F&D"):
The 1P F&D costs were $5.99 per boe resulting in a recycle ratio3 of 4.4 times;
The 2P F&D costs were $12.70 per boe resulting in a recycle ratio of 2.1 times;
1 RLI is calculated by dividing the reserves in each category by the average annual production for that period. For example 2015 Total Proven = (5,341,100) / (1,515*.365) = 9.7 years.
2 The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that
year. For example: 2015 Total Proven = (5,341,1000-3,743,000+553,000)/553,000= 388%.
3 Recycle ratio is calculated by dividing the operating netback per boe by the FD&A costs for that period. For example: 2015 Total Proven = (26.61/5.99) = 4.4. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate
the investment success unless the replacement reserves are of equivalent quality as the produced reserves.
Finding, Development and Acquisition Costs ("FD&A")4:
The 1P FD&A costs were $18.73 per boe resulting in a recycle ratio of 1.4 times;
The 2P FD&A costs were $17.34 per boe resulting in a recycle ratio of 1.5 times;
Increased 2P reserves associated with the Company's water flood project areas by 33% year over year to
2.3 Mboe with NPV10 of $46.2 million;
Production rates from year end 2015 proved developed producing reserves are forecast to decline in 2016 at a rate of 6.5% from 2015 average levels of 1,515 boe/d prior to the addition of capital, representing a significant improvement from average 2014 and 2015 annual decline rates of 41% and 23%, respectively;
Achieved fourth quarter and annual 2015 production of 1,464 boe per day and 1,515 boe per day (97% light oil and NGLs), respectively; and
Achieved operating netbacks for the fourth quarter and year to date of $32.45 per boe and $26.61 per boe respectively.
The detailed reserves data set forth below is based upon the Sproule Report, which was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The following presentation summarizes the Company's crude oil, natural gas liquids and natural gas reserves, and the net present values before income tax of future net revenue for the Company's reserves using forecast prices and costs based on the Sproule Report. The reserves evaluation was based on Sproule forecast escalated pricing and foreign exchange rates at December 31, 2015, as outlined in the attached table entitled "Price forecast". Additional information is included in the Company's 51-101F1 which has been filed on SEDAR.
As at December 31, 2015 | |||
Reserves Category | Oil(3) | Conventional Natural Gas | Total (4) |
(Forecast Prices and Costs) | (Mbbl) | (Mmcf) | (Mboe) |
Proved | |||
Producing | 3,235 | 382 | 3,382 |
Non-producing | 59 | 0 | 59 |
Undeveloped | 1,870 | 77 | 1,899 |
Total proved | 5,165 | 459 | 5,341 |
Total probable | 2,521 | 118 | 2,567 |
Total proved plus probable | 7,686 | 577 | 7,908 |
(1) Reserves are presented on a gross basis, which is defined as Virginia Hills' working interest share (operated and non-operated properties) before deduction of royalties and without including any royalty interest in the Company.
(2) Based on Sproule's December 31, 2015 escalated price forecast.
(3) "Oil" values include all light crude oil and medium crude oil and natural gas liquids volumes.
(4) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. See "BOE Advisory".
(5) Columns may not add due to rounding.
(6) Pursuant to section 5.4.3 "Levels of Certainty for Reported Reserves" of the COGE Handbook, reported reserves should target at least a 90
percent probability that the quantities actually recovered will be equal to or exceed the estimated proved reserves and that at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.
4 FD&A costs are used as a measure of capital efficiency. The calculation includes all capital costs for that period plus the change in future development costs ("FDC") for that period. This total capital including the change in the FDC is then divided by the change in reserves for that period incorporating all revisions and production for that same period. For example: 2015 Total Proven = (5,341,100-434,800+553,000- 3,743,000) / ($78,390,000-$45,993,000) = $ 18.83 per boe.
Corporate Reserve Values (1)(2)(3)The estimated before-tax net present value ("NPV") of future net revenues associated with Virginia Hills' reserves, effective December 31, 2015 and based on the Sproule Report and the published Sproule price deck for December 31, 2015, is summarized in the table below.
As at December 31, 2015 | |||||
Annual Discount Rate, before taxes $000 (Forecast Prices and Costs) | 0% | 5% | 10% | 15% | 20% |
Proved | $79,671 | $67,746 | $58,051 | $50,464 | $44,508 |
Producing | |||||
Non-producing | $1,531 | $671 | $437 | $330 | $261 |
Undeveloped | $36,609 | $22,520 | $13,397 | $7,397 | $3,340 |
Total proved | $117,810 | $90,938 | $71,885 | $58,191 | $48,110 |
Probable | $93,286 | $63,039 | $44,673 | $33,011 | $25,258 |
Total proved plus probable | $211,096 | $153,977 | $116,558 | $91,202 | $73,368 |
(1) Future net revenue is after deduction of estimated costs of abandonment and reclamation of existing and future wells to which Sproule assigned reserves and does not include costs of abandonment and reclamation related to Virginia Hills' facilities and pipelines.
(2) It should not be assumed that the present worth of estimated future net revenue presented in the tables above represents the fair market
value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of Virginia Hills' crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
(3) All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis
(4) Numbers are subject to rounding.
The Sproule December 31, 2015 price forecast is summarized in the table below:
Year | Exchange Rate | WTI @ Cushing | Canadian Light Sweet | Natural Gas Aeco-C Spot |
$US/$Cdn | (US$/bbl) | (Cdn$/bbl) | (Cdn$/Mmbtu) | |
2016 | $0.75 | $45.00 | $55.20 | $2.25 |
2017 | $0.80 | $60.00 | $69.00 | $2.95 |
2018 | $0.83 | $70.00 | $78.43 | $3.42 |
2019 | $0.85 | $80.00 | $89.41 | $3.91 |
2020 | $0.85 | $81.20 | $91.71 | $4.20 |
2021 | $0.85 | $82.42 | $93.08 | $4.28 |
2022 | $0.85 | $83.65 | $94.48 | $4.35 |
2023 | $0.85 | $84.91 | $95.90 | $4.43 |
2024 | $0.85 | $86.18 | $97.34 | $4.51 |
2025 | $0.85 | $87.48 | $98.80 | $4.59 |
2026 | $0.85 | $88.79 | $100.28 | $4.67 |
After 2027+ | - | +1.5%/yr | +1.5%/yr | +1.5%/yr |
In 2015, Virginia Hills and its predecessor (Pinecrest) spent $10.3 million on its Red Earth Slavepoint light oil assets, which was focused on improving the economics of its undeveloped horizontal type curve, optimizing its water flood project areas and reducing its operating cost structure. The Company was successful in addressing these items and has positioned its asset base for successful development in the future within a potentially weak commodity price environment.
Proved reserves increased year over year by 43% to 5.3 Mboe from 3.7 Mboe at year end 2014 (as reported by Pinecrest in their year end 2014 corporate reserves evaluation prepared by Sproule with an effective date of December 31, 2014 and a preparation date of January 7, 2015 (the "Pinecrest Report")) with a NPV10 of $71.9 million. The Company's proved reserves were weighted 97% to light oil as at December 31, 2015. The RLI of the Company's proved reserves based on 2015 annual production increased by 86% from 2014 levels (as reported in the Pinecrest Report) to 9.7 years using annualized production of 1,515 boe per day in 2015.
Proved plus probable reserves increased 20%, year over year, to 7.9 Mboe with an NPV10 of $116.6 million. The Company's proved plus probable reserves are weighted 97% to light oil. The RLI of the Company's 2P reserves was
years at December 31, 2015 representing an increase of 61% when compared to the 2P reserves reported in the Pinecrest Report.
The Company's focus on optimizing and enhancing the value of its asset base has resulted in a marked improvement on its corporate base production decline and sustainability. The Sproule Report has forecasted that Virginia Hills' proved developed producing assets, before capital investment, will decline by 6.5% in 2016 from 2015 average production levels. This is substantially lower than annual decline rates experienced by Pinecrest in 2014 and by the Company in 2015 of 41% and 23%, respectively.
Proved plus probable reserves associated with Virginia Hills' water flood projects increased year over year on a per boe basis by 23% to 4.4 Mboe with NPV10 of $46.2 million. In 2015, the Company invested approximately $3.6 million on its water flood optimization projects in the greater Red Earth area and increased 2P reserves by approximately 725 Mboe representing F&D costs of $4.96 per boe. The Company continues to successfully optimize its water flood project areas with average annual gross production rates in 2014 and 2015 of 670 boe/d and 644 boe/d, respectively and current average rates over the first two months of 2016 of approximately 726 boe/d. Production from wells within the water flood project areas represented 43% and 40% of the Company's average production and NPV10, respectively, in 2015. Virginia Hills' water flood project areas at year end 2015 represent just 14% of the Company's current developed footprint in the greater Red Earth area with a total of 37 gross (28.5 net) sections of land producing economically from the Slavepoint formation under primary production and 4.5 gross (4.0 net) sections producing under secondary recovery.
Following completion of the Arrangement, the Company focused its capital on optimizing its Otter water flood areas by investing $3.3 million on 1.8 gross (1.6 net) sections located in the area. Average gross production from this project area in 2014 and 2015 was 216 boe/d and 282 boe/d, respectively with current average gross production rates for the first two months of 2016 of approximately 430 boe/d. The Company believes its performance on the Otter water flood project will become the point forward analog metrics industry wide for Slavepoint light oil water flood projects in the greater Red Earth area.
In 2015, Virginia Hills drilled 2.0 gross (2.0 net) horizontal Slavepoint light oil wells and was successful in reducing the future capital associated with each undeveloped location by 35% to $2.2 million per well compared to $3.3 million at year end 2014 (as reported by Pinecrest), while maintaining production and reserve expectations on a per well basis. This decrease in expected future cost per location was directly attributable to the significant decline in industry service costs and the introduction of both acid fracturing and slim hole mono-bore technology to the Red Earth Slavepoint light oil play. As per the Sproule Report, the Company's new Slavepoint light oil horizontal type curve has the following average attributes:
IP30 - 145 bbls/d of light oil;
2P Reserves - 96 Mbbls of light oil;
Capital - $2.2 million;
NPV10 per well - $1.2 million (Sproule December 31, 2015 price deck); and
Rate of Return5 - 55%.
At year end 2015 Virginia Hills had 37.0 gross (34.8 net) Slavepoint light oil horizontal undeveloped locations booked on a 2P reserve basis in the greater Red Earth area compared to 14.0 gross (14.0 net) at year end 2014 (as reported in the Pinecrest Report). The increase in undeveloped 2P locations booked year over year was directly attributable to the Company's purchase of Dolomite Energy Inc. ("Dolomite") in the second quarter of 2015. The Dolomite assets were comprised of 11.0 gross (11.0 net) sections of Slavepoint mineral rights directly adjacent to the Company's Evi/Otter field.
5 Rate of return is defined as the average NPV10 per well divided by the average capital forecast to be expended per well
Virginia Hills Oil Corp. issued this content on 30 March 2016 and is solely responsible for the information contained herein. Distributed by Public, unedited and unaltered, on 30 March 2016 22:25:14 UTC
Original Document: http://virginiahillsoil.com/sites/default/files/news/VHO Press Release - March 30, 2016 Final.pdf
