CALGARY, ALBERTA–(Marketwired – Feb. 2, 2016) – Rock Energy Inc. (TSX:RE) (“Rock” or the “Company”) is pleased to report a corporate reserves update effective December 31, 2015. This is a reserves update to the report provided on December 14, 2015 that had an effective date of November 30, 2015. The new report incorporates production for the month of December, the drilling of three (3.0 net) wells at Laporte, and the GLJ Petroleum Consultants (“GLJ”) price forecast dated January 1, 2016. GLJ’s new price forecast has a 2016 WTI price of $44.00 US/bbl compared to the previous forecast of WTI = $50.00 US/bbl. The Company’s net asset value has not been materially impacted by this reduction in forecasted prices.
This reserves update was undertaken by Rock’s independent reserve evaluator, GLJ. The report on such reserves (the “GLJ Report”) was prepared in accordance with definition, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The information set forth below summarizes the oil, liquids and natural gas reserves and the net present value of future net revenues from those reserves using forecast prices and costs. Unless stated otherwise, all reserve volumes referred to in this document are “gross” reserves which are the Company’s interest share of reserves (operated and non-operated) before deduction of royalties and without including any royalty interests. In addition to the detailed information disclosed in this press release, more information will be included in Rock’s Annual Information Form for the year ended December 31, 2015, which will be filed on SEDAR at www.sedar.com on or before March 31, 2016.
The key results of the report can be summarized as follows:
Corporate Net Asset Value
Based on Rock’s updated reserve value, management estimates that the corporate net asset value of the Company is $3.67/share (basic) as detailed below:
Reserve Value (Total Proved plus Probable, BTAX NPV discounted at 10%) | $ | 218.6 million |
Undeveloped Land (105,830 acres at approximately $150/acre (management estimate)) | $ | 15.9 million |
Total assets | $ | 234.5 million |
Less Forecasted Net Debt (as of December 31, 2015) | $ | 60.0 million |
Total Net Assets | $ | 174.5 million |
Basic Shares outstanding (as of December 31, 2015) | 47.5 million | |
Net Asset Value per basic share | $ | 3.67 |
Reserves and Value by Property | ||||||||
Total Proved | Total Proved Plus Probable | |||||||
Reserves (MBOE) | NPV (BTAX 10%) | Reserves (MBOE) | NPV (BTAX 10%) | |||||
Laporte/Mantario | 5,629 | $ | 74.8M | (59%) | 7,837 | $ | 118.9M | (54%) |
Onward Light (Viking) | 4,077 | $ | 38.3M | (30%) | 6,520 | $ | 77.2M | (35%) |
Onward Heavy | 1,377 | $ | 13.6M | (10%) | 2,255 | $ | 21.2M | (10%) |
Other | 315 | $ | 0.7M | (1%) | 466 | $ | 1.3M | (1%) |
Total | 11,398 | $ | 127.4M | 17,078 | $ | 218.6M |
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 effect of aggregation.
Laporte/Mantario
In addition to the progress we reported in the December 14, 2015 press release we were able further increase the pool size at Laporte by the drilling of two (2.0 net) infill wells and one (1.0 net) step out well in December, further verifying the seismic interpretation. The pool now has a total of 44.1 million barrels of OOIP and GLJ has recognized a Total Proved plus Probable pool recovery factor of 25%. During 2015 Rock was able to add reserves at Laporte at a cost of $3.57/boe (FD&A including revisions) generating a recycle ratio of 5.5.
Onward Viking
During 2015 Rock was able to add reserves light oil reserves at Onward at a cost of $26.00/boe (FD&A including revisions) generating a recycle ratio of 1.5.
RESERVES DATA
More detailed information in respect of reserves and net present value which is contained in the GLJ Report is set forth below.
Disclosure of Reserves Data
The reserves data set forth below (the “Reserves Data“) is based upon an evaluation by GLJ with an effective date of December 31, 2015 contained in the GLJ Report. The Reserves Data summarizes the oil, liquids and natural gas reserves of the Corporation and the net present values of future net revenue for these reserves using forecast prices and costs. The GLJ Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101. The Company engaged GLJ to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves. All of Rock’s reserves are in Canada and, specifically, in the provinces of Alberta, British Columbia and Saskatchewan.
We have adopted the standard of 6 Mcf:1boe when converting natural gas to boes. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf per barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
All evaluations and reviews of future net cash flow are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the Corporation’s properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, natural gas liquids (“NGLs) and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGLs and natural gas reserves may be greater than or less than the estimates provided herein.
Reserves Data (Forecast Prices and Costs) | ||||||
SUMMARY OF WORKING INTEREST OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE As of December 31, 2015 |
||||||
FORECAST PRICES AND COSTS | ||||||
RESERVES | ||||||
LIGHT AND MEDIUM CRUDE OIL |
HEAVY CRUDE OIL |
CONVENTIONAL NATURAL GAS |
NATURAL GAS LIQUIDS |
TOTAL | ||
Gross | Gross | Gross | Gross | Gross | ||
RESERVES CATEGORY | (Mbbl) | (Mbbl) | (MMcf) | (Mbbl) | (Mboe) | |
PROVED | ||||||
Developed Producing | 768 | 5,558 | 932 | 20 | 6,501 | |
Developed Non-producing | 125 | 66 | 551 | 8 | 291 | |
Undeveloped | 3,224 | 1,382 | – | – | 4,606 | |
TOTAL PROVED | 4,117 | 7,006 | 1,484 | 28 | 11,398 | |
PROBABLE | 2,458 | 3,085 | 695 | 20 | 5,679 | |
TOTAL PROVED PLUS | ||||||
PROBABLE | 6,575 | 10,091 | 2,178 | 48 | 17,078 | |
NET PRESENT VALUES OF FUTURE NET REVENUE |
BEFORE INCOME TAXES DISCOUNTED AT (%/year) |
AFTER INCOME TAXES DISCOUNTED AT (%/year) |
UNIT VALUE BEFORE INCOME TAX DISCOUNTED AT 10%/YEAR |
|||||||||||
0 | 5 | 10 | 15 | 20 | 0 | 5 | 10 | 15 | 20 | ||||
RESERVES CATEGORY | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | ($/BOE) | ||
PROVED | |||||||||||||
Developed Producing | 137,139 | 112,318 | 94,982 | 82,299 | 72,693 | 137,139 | 112,318 | 94,982 | 82,299 | 72,693 | 15.44 | ||
Developed Non-Producing | 3,550 | 2,716 | 2,047 | 1,541 | 1,163 | 3,550 | 2,716 | 2,047 | 1,541 | 1,163 | 7.69 | ||
Undeveloped | 72,351 | 48,253 | 30,360 | 17,775 | 8,995 | 71,415 | 47,821 | 30,153 | 17,672 | 8,942 | 6.83 | ||
TOTAL PROVED | 213,039 | 163,287 | 127,389 | 101,615 | 82,851 | 212,103 | 162,854 | 127,181 | 101,512 | 82,798 | 11.73 | ||
PROBABLE | 216,899 | 136,428 | 91,166 | 64,024 | 46,782 | 158,268 | 102,257 | 70,112 | 50,445 | 37,688 | 17.54 | ||
TOTAL PROVED PLUS | |||||||||||||
PROBABLE | 429,939 | 299,715 | 218,555 | 165,639 | 129,633 | 370,371 | 265,111 | 197,294 | 151,957 | 120,486 | 13.61 | ||
TOTAL FUTURE NET REVENUE |
(UNDISCOUNTED) |
As of December 31, 2015 |
FORECAST PRICES AND COSTS |
RESERVES CATEGORY | REVENUE (M$) |
ROYALTIES (M$) |
OPERATING COSTS (M$) |
DEVELOPMENT COSTS (M$) |
WELL ABANDONMENT AND RECLAMATION COSTS (M$) |
FUTURE NET REVENUE BEFORE INCOME TAXES (M$) |
INCOME TAXES (M$) |
FUTURE NET REVENUE AFTER INCOME TAXES (M$) |
Total Proved Reserves | 727,833 | 46,141 | 326,476 | 115,153 | 27,024 | 213,039 | 936 | 212,103 |
Total Probable Reserves | 446,431 | 42,219 | 140,521 | 39,144 | 7,647 | 216,899 | 58,631 | 158,268 |
Total Proved Plus | ||||||||
Probable Reserves | 1,174,263 | 88,360 | 466,997 | 154,297 | 34,671 | 429,939 | 59,567 | 370,371 |
Notes to Reserves Data Tables: |
(1) | Columns may not add due to rounding. |
(2) | The crude oil, natural gas liquids and natural gas reserve estimates presented in the GLJ Report are based on the definitions and guidelines contained in the COGE Handbook. |
(3) | The revenue forecasts included in the GLJ Report include the estimated costs to abandon and reclaim the wells assigned reserves in the GLJ Report and to disconnect these wells from the gathering system. No costs have been included for the abandonment and reclamation of surface facilities or gathering systems. Also, no costs have been included in the GLJ Report for the abandonment and reclamation of any of Rock’s wells which have been assigned no reserves in the GLJ Report. |
(4) | The forecast price and cost assumptions assume the continuance of current laws and regulations. |
(5) | The extent and character of all factual data supplied to GLJ were accepted by GLJ as represented. No field inspection was conducted. |
Future Development Costs
The following table sets forth development costs deducted in the estimation of the corporation’s future net revenue attributable to the reserve categories noted below.
Future Development Costs | ||
(Undiscounted) | ||
Total Proved | ||
Total Proved | Plus Probable | |
Reserves | Reserves | |
Year | ($000) | ($000) |
2016 | 6,042 | 22,742 |
2017 | 60,782 | 62,618 |
2018 | 48,197 | 53,034 |
2019 | 133 | 15,626 |
2020 | – | 135 |
Thereafter | – | 141 |
Total | 115,153 | 154,297 |
Forecast Prices and Costs
The forecast cost and price assumptions assume increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil and natural gas benchmark reference pricing, as at January 1, 2016, inflation and exchange rates utilized by GLJ in the GLJ Report, which were GLJ’s then current forecasts at the date of the GLJ Report, were as follows:
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS |
As of January 1, 2016 |
FORECAST PRICES AND COSTS |
OIL | NATURAL GAS |
NATURAL GAS LIQUIDS | ||||||||||
Year | WTI Cushing Oklahoma ($US/Bbl) |
Edmonton Par Price 40° API ($Cdn/Bbl) |
Cromer Medium Crude 29° API ($Cdn/Bbl) |
Hardisty Heavy Crude 12° API ($Cdn/Bbl) |
AECO Gas Price ($Cdn/Mmbtu) |
Edmonton Pentanes Plus ($Cdn/Bbl) |
Edmonton Propane ($Cdn/Bbl) |
Edmonton Butane ($Cdn/Bbl) |
Spec Ethane($Cdn/Bbl) |
INFLATION (1) RATES %/Year |
EXCHANGE (2) RATE ($Cdn/$US) |
|
Forecast | ||||||||||||
2016 | 44.00 | 55.86 | 50.80 | 35.70 | 2.76 | 60.79 | 9.58 | 41.90 | 8.82 | 2.0 | 0.7250 | |
2017 | 52.00 | 64.00 | 59.52 | 45.02 | 3.27 | 68.48 | 16.00 | 48.00 | 10.55 | 2.0 | 0.7500 | |
2018 | 58.00 | 68.39 | 63.60 | 49.06 | 3.45 | 73.17 | 20.52 | 51.29 | 11.19 | 2.0 | 0.7750 | |
2019 | 64.00 | 73.75 | 68.59 | 54.42 | 3.63 | 78.91 | 25.81 | 55.31 | 11.81 | 2.0 | 0.8000 | |
2020 | 70.00 | 78.79 | 73.27 | 59.75 | 3.81 | 84.30 | 27.58 | 59.09 | 12.44 | 2.0 | 0.8250 | |
2021 | 75.00 | 82.35 | 76.59 | 63.56 | 3.90 | 88.12 | 28.82 | 61.76 | 12.74 | 2.0 | 0.8500 | |
2022 | 80.00 | 88.24 | 82.06 | 69.32 | 4.10 | 94.41 | 30.88 | 66.18 | 13.43 | 2.0 | 0.8500 | |
2023 | 85.00 | 94.12 | 87.53 | 74.62 | 4.30 | 100.71 | 32.94 | 70.59 | 14.12 | 2.0 | 0.8500 | |
2024 | 87.88 | 96.48 | 89.73 | 78.40 | 4.50 | 103.24 | 33.77 | 72.36 | 14.81 | 2.0 | 0.8500 | |
2025 | 89.63 | 98.41 | 91.52 | 79.99 | 4.60 | 105.30 | 34.44 | 73.81 | 15.15 | 2.0 | 0.8500 | |
Thereafter | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year | +2%/year |
Notes: |
(1) | Inflation rates for forecasting prices and costs. |
(2) | Exchange rates used to generate the benchmark reference prices in this table. |
Annual Report Three Year F&D, Recycle Ratio and Netback Summary (Accounting Month Working Interest) | |||||||||
Year ended
Dec. 31, 2015 |
Year ended
Dec. 31, 2014 |
Year ended
Dec. 31, 2013 |
3 Year Average 2013 through 2015 |
3 Year Average Recycle Ratio Calculation (see Note 4) |
|||||
Oil and Gas Operations: (Excluding Revisions) | |||||||||
Proved finding and development costs | |||||||||
Capital Expenditures ($000) | $ | 38,696 | $ | 117,054 | $ | 47,980 | $ | 203,730 | |
Future Capital Costs ($000) | $ | 57,584 | $ | (6,752) | $ | 37,539 | $ | 88,371 | |
Total Capital ($000) | $ | 96,280 | $ | 110,302 | $ | 85,519 | $ | 292,101 | |
Reserve Additions (see Note 2) (mboe) | 3,473 | 3,397 | 2,310 | 9,180 | |||||
Proved finding and development costs ($/boe) | $ | 27.73 | $ | 32.47 | $ | 37.02 | $ | 31.82 | 0.9 |
Proved + Probable finding and development costs | |||||||||
Capital Expenditures ($000) | $ | 38,696 | $ | 117,054 | $ | 47,980 | $ | 203,730 | |
Future Capital Costs ($000) | $ | 68,007 | $ | (14,867) | $ | 63,839 | $ | 116,979 | |
Total Capital ($000) | $ | 106,703 | $ | 102,187 | $ | 111,819 | $ | 320,709 | |
Reserve Additions (see Note 2) (mboe) | 4,967 | 4,790 | 3,757 | 13,514 | |||||
Proved plus probable finding and development costs ($/boe) | $ | 21.48 | $ | 21.34 | $ | 29.76 | $ | 23.73 | 1.2 |
Oil and Gas Operations: (Including Revisions) | |||||||||
Proved finding and development costs | |||||||||
Capital Expenditures ($000) | $ | 38,696 | $ | 117,054 | $ | 47,980 | $ | 203,730 | |
Future Capital Costs ($000) | $ | 57,584 | $ | (6,752) | $ | 37,539 | $ | 88,371 | |
Total Capital ($000) | $ | 96,280 | $ | 110,302 | $ | 85,519 | $ | 292,101 | |
Reserve Additions (see Note 3) (mboe) | 4,341 | 4,011 | 2,522 | 10,874 | |||||
Proved finding and development costs ($/boe) | $ | 22.18 | $ | 27.50 | $ | 33.91 | $ | 26.86 | 1.1 |
Proved + Probable finding and development costs | |||||||||
Capital Expenditures ($000) | $ | 38,696 | $ | 117,054 | $ | 47,980 | $ | 203,730 | |
Future Capital Costs ($000) | $ | 68,007 | $ | (14,867) | $ | 63,839 | $ | 116,979 | |
Total Capital ($000) | $ | 106,703 | $ | 102,187 | $ | 111,819 | $ | 320,709 | |
Reserve Additions (see Note 3) (mboe) | 6,273 | 4,230 | 3,568 | 14,071 | |||||
Proved plus probable finding and development costs ($/boe) | $ | 17.01 | $ | 24.16 | $ | 31.34 | $ | 22.79 | 1.3 |
Acquisitions/Dispositions: | |||||||||
Proved finding and development costs – Acquisitions/Dispositions | |||||||||
Capital Expenditures ($000) | $ | (891) | $ | 1,828 | $ | (1,254) | $ | (317) | |
Future Capital Costs ($000) | $ | (1,326) | $ | (1,532) | $ | (8,256) | $ | (11,114) | |
Total Capital ($000) | $ | (2,217) | $ | 296 | $ | (9,510) | $ | (11,431) | |
Reserve Additions (mboe) | (88) | (263) | (201) | (552) | |||||
Proved finding and development costs ($/boe) | $ | 25.11 | $ | (1.13) | $ | 47.34 | $ | 20.72 | 1.4 |
Proved + Probable finding and development costs – Acquisitions/Dispositions | |||||||||
Capital Expenditures ($000) | $ | (891) | $ | 1,828 | $ | (1,254) | $ | (317) | |
Future Capital Costs ($000) | $ | (1,326) | $ | (3,033) | $ | (7,270) | $ | (11,629) | |
Total Capital ($000) | $ | (2,217) | $ | (1,205) | $ | (8,524) | $ | (11,946) | |
Reserve Additions (mboe) | (141) | (734) | (281) | (1,156) | |||||
Proved plus probable finding and development costs ($/boe) | $ | 15.68 | $ | 1.64 | $ | 30.39 | $ | 10.33 | 2.9 |
Total Activities: (Including Revisions) | |||||||||
Proved finding and development costs | |||||||||
Capital Expenditures ($000) | $ | 37,805 | $ | 118,882 | $ | 46,726 | $ | 203,413 | |
Future Capital Costs ($000) | $ | 56,258 | $ | (8,284) | $ | 29,283 | $ | 77,257 | |
Total Capital ($000) | $ | 94,063 | $ | 110,598 | $ | 76,009 | $ | 280,670 | |
Reserve Additions (see Note 3) (mboe) | 4,253 | 3,749 | 2,321 | 10,322 | |||||
Proved finding and development costs ($/boe) | $ | 22.12 | $ | 29.50 | $ | 32.75 | $ | 27.19 | 1.1 |
Proved + Probable finding and development costs | |||||||||
Capital Expenditures ($000) | $ | 37,805 | $ | 118,882 | $ | 46,726 | $ | 203,413 | |
Future Capital Costs ($000) | $ | 66,681 | $ | (17,900) | $ | 56,569 | $ | 105,350 | |
Total Capital ($000) | $ | 104,486 | $ | 100,982 | $ | 103,295 | $ | 308,763 | |
Reserve Additions (see Note 3) (mboe) | 6,131 | 3,496 | 3,287 | 12,914 | |||||
Proved plus probable finding and development costs ($/boe) | $ | 17.04 | $ | 28.89 | $ | 31.42 | $ | 23.91 | 1.2 |
1) | Capital expenditures include capitalized G&A and administrative expenditures which has been allocated between oil and natural gas operations and acquisitions and exclude purchases of equipment still held in inventory. |
2) | Reserve additions exclude revisions. |
3) | Reserve additions include revisions. |
4) | 3 Year weighted average netback is $29.64/boe. |
Table Notes:
A) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
For further information please visit Rock’s website at www.rockenergy.ca.
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