Market Overview

Rock Energy Inc. Announces Year End 2015 Reserves Replacing Over 400% of Its Production During the Year, and Growing Total Proven Plus Probable Reserves by 37%

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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:



-- 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 Reserves
(MBOE) NPV (BTAX 10%) (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 HEAVY NATURAL
CRUDE CRUDE CONVENTIONAL GAS
OIL OIL 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)
--------------------------------------------------
0 5 10 15 20
RESERVES CATEGORY (M$) (M$) (M$) (M$) (M$)
----------------------------------------------------------------------------

PROVED
Developed Producing 137,139 112,318 94,982 82,299 72,693
Developed Non-Producing 3,550 2,716 2,047 1,541 1,163
Undeveloped 72,351 48,253 30,360 17,775 8,995
--------------------------------------------------
TOTAL PROVED 213,039 163,287 127,389 101,615 82,851

PROBABLE 216,899 136,428 91,166 64,024 46,782
--------------------------------------------------

TOTAL PROVED PLUS
PROBABLE 429,939 299,715 218,555 165,639 129,633
--------------------------------------------------









AFTER INCOME TAXES DISCOUNTED AT
(%/year)
--------------------------------------------------
0 5 10 15 20
RESERVES CATEGORY (M$) (M$) (M$) (M$) (M$)
----------------------------------------------------------------------------

PROVED
Developed Producing 137,139 112,318 94,982 82,299 72,693
Developed Non-Producing 3,550 2,716 2,047 1,541 1,163
Undeveloped 71,415 47,821 30,153 17,672 8,942
--------------------------------------------------
TOTAL PROVED 212,103 162,854 127,181 101,512 82,798

PROBABLE 158,268 102,257 70,112 50,445 37,688
--------------------------------------------------

TOTAL PROVED PLUS
PROBABLE 370,371 265,111 197,294 151,957 120,486
--------------------------------------------------




UNIT VALUE
BEFORE
INCOME TAX
DISCOUNTED AT
10%/YEAR
--------------------

RESERVES CATEGORY ($/BOE)
-------------------------- --------------------

PROVED
Developed Producing 15.44
Developed Non-Producing 7.69
Undeveloped 6.83
--------------------
TOTAL PROVED 11.73

PROBABLE 17.54
--------------------

TOTAL PROVED PLUS
PROBABLE 13.61
--------------------






TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
As of December 31, 2015
FORECAST PRICES AND COSTS





OPERATING DEVELOPMENT
REVENUE ROYALTIES COSTS COSTS
RESERVES CATEGORY (M$) (M$) (M$) (M$)
----------------------------------------------------------------------------

Total Proved Reserves 727,833 46,141 326,476 115,153
Total Probable Reserves 446,431 42,219 140,521 39,144
Total Proved Plus
Probable Reserves 1,174,263 88,360 466,997 154,297


FUTURE FUTURE
WELL NET NET
ABANDONMENT REVENUE REVENUE
AND BEFORE AFTER
RECLAMATION INCOME INCOME INCOME
COSTS TAXES TAXES TAXES
RESERVES CATEGORY (M$) (M$) (M$) (M$)
----------------------------------------------------------------------------

Total Proved Reserves 27,024 213,039 936 212,103
Total Probable Reserves 7,647 216,899 58,631 158,268
Total Proved Plus
Probable Reserves 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
---------------------------------------------------------------
Cromer Hardisty
WTI Edmonton Medium Heavy
Cushing Par Price Crude Crude
Oklahoma 40 degrees API 29 degrees API 12 degrees API
Year ($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/Bbl)
--------------------------------------------------------------------------
Forecast
2016 44.00 55.86 50.80 35.70
2017 52.00 64.00 59.52 45.02
2018 58.00 68.39 63.60 49.06
2019 64.00 73.75 68.59 54.42
2020 70.00 78.79 73.27 59.75
2021 75.00 82.35 76.59 63.56
2022 80.00 88.24 82.06 69.32
2023 85.00 94.12 87.53 74.62
2024 87.88 96.48 89.73 78.40
2025 89.63 98.41 91.52 79.99
Thereafter +2%/year +2%/year +2%/year +2%/year

NATURAL
GAS NATURAL GAS LIQUIDS
---------------------------------------------------------------

Edmonton Spec
AECO Gas Pentanes Edmonton Edmonton Ethane
Price Plus Propane Butane
Year ($Cdn/Mmbtu) ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/Bbl)
--------------------------------------------------------------------------
Forecast
2016 2.76 60.79 9.58 41.90 8.82
2017 3.27 68.48 16.00 48.00 10.55
2018 3.45 73.17 20.52 51.29 11.19
2019 3.63 78.91 25.81 55.31 11.81
2020 3.81 84.30 27.58 59.09 12.44
2021 3.90 88.12 28.82 61.76 12.74
2022 4.10 94.41 30.88 66.18 13.43
2023 4.30 100.71 32.94 70.59 14.12
2024 4.50 103.24 33.77 72.36 14.81
2025 4.60 105.30 34.44 73.81 15.15
Thereafter +2%/year +2%/year +2%/year +2%/year +2%/year




INFLATION EXCHANGE
(1) (2)
RATES RATE
Year %/Year ($Cdn/$US)
----------------------------------------------------------------------------
Forecast
2016 2.0 0.7250
2017 2.0 0.7500
2018 2.0 0.7750
2019 2.0 0.8000
2020 2.0 0.8250
2021 2.0 0.8500
2022 2.0 0.8500
2023 2.0 0.8500
2024 2.0 0.8500
2025 2.0 0.8500
Thereafter

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)


3 Year
3 Year Average
Year ended Year ended Year ended Average Recycle
2013 Ratio
Dec. 31, Dec. 31, Dec. 31, through Calculation
2015 2014 2013 2015 (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/Dis
positions:
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.

Forward-Looking Statements and Advisories

Certain statements contained in this document constitute forward-looking statements. These statements relate to future events or the Company's future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "budget", "plan", "continue", "estimate", "expect", "forecast", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. In particular, this document contains forward-looking statements pertaining to the following: management's assessment of Rock's plans and future operations, production, reserves, revenue, commodity prices, currency exchange rates, operating expenses, transportation, administrative expenditures, royalty rates, interest expense, future income taxes, drilling plans, acquisitions and dispositions, funds from operations, capital expenditure programs, debt levels, recovery factors and timing of project payout.

These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. These factors include, but are not limited to: the effect of general economic conditions, industry conditions, regulatory and taxation regimes, volatility of commodity prices, currency fluctuations, the availability of services, imprecision of reserve estimates, geological, technical, drilling and processing problems, environmental risks, weather, the lack of availability of qualified personnel or management, stock market volatility, the ability to access sufficient capital from internal and external sources and competition from other industry participants for, among other things, capital, services, acquisitions of reserves, undeveloped lands and skilled personnel, any of which may cause actual results or events to differ materially from those anticipated in such forward-looking statements.

Readers are cautioned that the foregoing lists of factors are not exhaustive. The Company believes that the expectations reflected in these forward looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this document should not be unduly relied upon. These statements speak only as of the date of this document, as the case may be. The Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable law.

Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future.

The forward-looking statements contained in this document are expressly qualified by this cautionary statement. The Company does not undertake any obligation to publicly update or revise any forward- looking statements except as required by securities laws or regulations.

This document may disclose drilling locations in four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; iii) unbooked locations; and, iv) an aggregate total of (i), (ii) and (iii). Proved undeveloped locations and probable undeveloped locations are booked and derived from Rock's most recent independent reserves evaluation as prepared by GLJ Petroleum Consultants Ltd. as of November 30, 2015 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on Rock's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by management as an estimation of the Rock's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Rock will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Rock will actually drill wells is ultimately dependent upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

This press release contains metrics commonly used in the oil and natural gas industry, such as "recycle ratio", "finding and development costs" or "F&D costs, "finding, development and acquisition costs" or "FD&A costs", "operating netbacks" or "netbacks", and "reserve life index" or "RLI". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

Both F&D costs and FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated future capital costs may not reflect total finding and development costs related to reserves additions for that year. F&D costs both including and excluding acquisitions and dispositions have been presented in this news release because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure. Recycle ratio is measured by dividing the operating netback by appropriate F&D costs or FD&A cost per boe for the year. Operating netback is calculated using production revenues including realized gains and losses on commodity hedging less royalties, transportation and operating expenditures calculated on a per boe equivalent basis. Reserve life index is calculate based on the amount for the relevant reserves category divided by the production forecast for the applicable year prepared by GLJ.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Rock's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.



Abbreviations

bbl barrel(s) mbbls thousand barrels
bbl/d barrel(s) per day mboe thousand barrels of oil
equivalent
bcf billion cubic feet mboed thousand barrels of oil
equivalent per day
boe barrels of oil equivalent mcf thousand cubic feet
boed barrels of oil equivalent per mmcf million cubic feet
day
bps basis points mmbbls million barrels
CDOR Certificate of Deposit Offered mmboe million barrels of oil
Rate equivalent
GJ gigajoule NGL natural gas liquids
hectare 1 hectare is equal to 2.47 WTI West Texas Intermediate
acres
km kilometer WCS Western Canadian Select



FOR FURTHER INFORMATION PLEASE CONTACT:
Rock Energy Inc.
Allen J. Bey
President and Chief Executive Officer
403.218.4380


Rock Energy Inc.
Todd Hirtle
Vice President Finance and Chief Financial Officer
403.218.4380

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