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Rock Energy Inc. (RE.TO) (“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:

  • Increased its Total Proven plus Probable reserves by 37% from 12.5 million boe at 2014 year-end to 17.1 million boe (98% heavy and light oil and natural gas liquids). This increase in reserves was accomplished due to the success of the Laporte/Mantario Polymer Flood project as well as the continued success of the Onward Viking resource play development;
  • Replaced over 400% of its production during the period on a Total Proved plus Probable basis;
  • Generated a corporate reserve value for the Total Proved plus Probable of $218.6 million (BTAX NPV discounted at 10%) despite the 41% reduction in the price forecast (2016 WTI was reduced from $75.00 US/bbl to $44.00 US/bbl);
  • Increased the Reserve Life Index (“RLI”) to 14.1 years on its Total Proven plus Probable reserves (assuming forecasted Q1/2016 average production of 3,320 boepd);
  • Focused the Company into three assets, two of which the Company has discovered and developed, representing 99% of the value of the Company; and
  • Generated corporate Finding, Development and Acquisition Costs including revisions of $17.04/boe for Total Proven plus Probable reserves.

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.