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%

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 (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.

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 day	mmcf	million cubic feet
bps	basis points	mmbbls	million barrels
CDOR	Certificate of Deposit Offered Rate	mmboe	million barrels of oil equivalent
GJ	gigajoule	NGL	natural gas liquids
hectare	1 hectare is equal to 2.47 acres	WTI	West Texas Intermediate
km	kilometer	WCS	Western Canadian Select