Rock Energy Reports Q2

Rock Energy Inc. Reports Q2 2015 Results and Positive Results at Its Mantario/Laporte EOR Project

CALGARY, ALBERTA–(Marketwired – Aug. 12, 2015) – Rock Energy Inc. (TSX:RE) (“Rock” or the “Company”) is pleased to report its financial and operating results for three and six months ended June 30, 2015.

Copies of Rock’s audited financial statements and related management’s discussion and analysis for the three and six months ended June 30, 2015 have been filed on the SEDAR website at www.sedar.com and may be obtained on Rock’s website at www.rockenergy.ca.

Rock is a Calgary-based crude oil exploration, development and production company.

CORPORATE SUMMARY

LETTER TO THE SHAREHOLDERS

The year 2015 is proving to be a very challenging year for our industry. The WTI price continues to seek an equilibrium level where supply and demand are balanced as the industry responds with cost cutting measures and disciplined capital allocation decisions. As we move into the second half of the year there appears to be an emerging view that WTI oil prices will be range bound in the $50.00 US/bbl level for some time as world economies stabilize before they begin to grow again. Until we see clear evidence that demand is growing faster than previously thought, or conversely that supply has been impacted by the significant cuts in capital spending, we need to plan our business based on the current price level.

The team at Rock has been focused on building an asset base with a low decline rate so that the assets could be maintained with minimal capital spending. During the second quarter we focused on the strategic objectives of establishing the EOR project at Mantario/Laporte, and confirming the extent of the Viking pool and the costs to drill those wells. We are not focused on increasing production in this price environment. At our current production level of about 4,200 boepd we are forecasting a corporate decline rate of approximately 15 – 20%. That means a WTI price of $50.00 US/bbl during 2016 will generate enough cash flow to hold our production flat while still testing a few exploration ideas.

For the remainder of 2015 we will limit our capital spending to less than cash flow, pay down our debt and continue to develop new growth prospects. This is a time for careful disciplined allocation of capital, not a race for production growth.

All of us here at Rock are shareholders like you, and we are focused on value creation.

Sincerely, and on behalf of the Board of Directors:

Allen J. Bey, President and Chief Executive Officer

REPORT TO SHAREHOLDERS

During the second quarter of 2015 Rock was able to achieve significant positive responses from the enhanced oil recovery (“EOR”) project at Mantario/Laporte and demonstrate a 15% – 20% capital cost reduction in the drilling of the Viking wells at Onward.

The quarter was highlighted by the following specific accomplishments:

• Drilled 8 (8.0 net) Viking horizontal oil wells with 100% casing success at Onward, Saskatchewan;
• Averaged 3,974 boe per day (95% crude oil and liquids);
• Completed the conversion of 12 injection wells at the EOR facility at Mantario/Laporte to begin the re-pressurization of the reservoir and establishment of the polymer flood;
• Divested of conventional heavy oil properties at Neilburg producing approximately 140 boepd for proceeds of $1.1 million, including 24 well bores;
• Total net capital expenditures during the quarter were $10.8 million; and
• Generated funds from operations for the quarter of $8.5 million ($0.19/ basic share).

Rock’s realized price in the second quarter of 2015 was $50.38 per boe compared to $37.65 per boe in the first quarter of 2015 and $82.45 for the same period a year ago. The increase in price realization is primarily attributed to an increase in WTI pricing (WTI increased from $48.63 US/bbl to $57.94 US/bbl) and a narrowing of the WTI – WCS differential.

Operating costs increased during the quarter to $18.63 per boe compared to $17.34 per boe in the first quarter of 2015 as the anticipated polymer injection and handling costs began to impact operations at Mantario/Laporte.

Rock generated an operating netback of $27.55 per boe in the second quarter of 2015 compared to $16.70 per boe in the first quarter of 2015, as field netbacks were positively impacted by improved product pricing.

Total net capital expenditures for the second quarter of 2015 were $10.8 million, including $4.9 million for the drilling program, $6.1 million for facilities, $0.9 million for land, seismic, and capitalized G&A, offset by $1.1 million of proceeds from the sale of heavy oil properties in Neilburg.

Rock’s daily production for the second quarter of 2015 averaged 3,974 boe per day (95% oil and liquids). The reduced production from the first quarter can be attributed to the sale of the properties at Neilburg (140 boepd effective May 1, 2015), the natural decline of the Viking wells, and the loss of production at Mantario/Laporte associated with the conversion of 12 producing wells to injectors. Currently the Company is producing approximately 4,100 – 4,300 boe/d as we bring on new Viking production at Onward and experience production responses from the EOR project at Mantario/Laporte.

Mantario/Laporte Saskatchewan

During the second quarter of 2015 Rock was focused on completing the conversions of 12 producing wells to injectors, optimizing the operation of the facilities, and establishing pressure maintenance and optimal sweep patterns through the reservoir. As anticipated, the conversion of the producing wells initially resulted in a decrease in production and at one point during the quarter pool production fell to approximately 2,200 boepd. Since that time we have experienced a significant production response from several wells, and production from the pool is currently averaging approximately 2,600 – 2,700 boepd as the polymer begins to re-pressurize the reservoir. Up to four morewells are planned to be converted to injectors during the life of the project in order to achieve a pool wide instantaneous voidage replacement ratio of greater than 1.0 (currently at 0.5 – 0.6). Once the pressure maintenance plan has been completed Rock will review the need to drill additional infill and step out locations to complete the drainage pattern and possibly extend the pool.

The Company continues to be encouraged with the progress achieved to date as the pool is responding very well to the EOR scheme, we have experienced positive responses in production and we are confident in our project plan and ultimate recovery factor. The Company continues to focus on completing the optimal implementation of the EOR flood which involves pressure maintenance and the establishment of the sweep patterns. Completion of this primary objective required approximately $2.0 million of additional capital costs beyond our original forecast. Consequently, we have elected to defer the drilling of 2 – 4 infill oil producers until commodity prices recover. Once the reservoir objectives have been achieved, and we have a clearer view of oil prices, we can move to increase the pool production levels. The Company is targeting production to ultimately stabilize in the 2,800 – 3,000 boepd range once the full injection pattern has been established and the appropriate amount of infill producers have been drilled.

Onward, Saskatchewan Viking

During the second quarter of 2015, the Company drilled an additional 8 (8.0 net) Viking horizontal oil wells at Onward. To date in the third quarter, Rock drilled an additional 5 (5.0 net) Viking wells to complete the delineation project for a total of 13 (13.0 net) wells. Rock is planning to complete 10 of the 13 wells which will be coming on production during the month of August. The remaining 3 wells are currently forecast to be completed during the fourth quarter.

Total production from the Viking during the second quarter averaged 850 bopd. Viking production is currently averaging over 1,000 bopd from 58 wells of the 65 wells drilled to date.

During the quarter the Company was able to achieve an average total cost to drill, case and complete a Viking well of $730k, equipping the well would add $120k – $140k for a total onstream cost of $850k – $875k (15% – 20% below last years costs). With this well cost and Rock’s light oil hedges, the drilling opportunities generate an IRR of approximately 30% and a payout of approximately 2.5 years. Though these projects meet reasonable economic hurdles we have elected to defer our drilling operations until we get a clearer view of pricing for 2016.

Outlook and 2015 Guidance

Given the current level of crude oil prices the Company has decided to maintain it’s capital program at $40 million and to limit capital spending for the remainder of the year, spending less than forecasted cash flow. The 2015 strategic objectives of implementing the EOR project at Mantario/Laporte and delineating the Viking play at Onward have been achieved and we are now focused on strengthening the balance sheet. Once we have confidence in an improved oil price environment we will look to expand the program to harvest the over 600 unbooked drilling locations we have assembled. With this limited capital program the Company is now forecasting average annual production of 4,300 – 4,500 boepd and to exit the year producing approximately 4,200 – 4,400 boepd during the fourth quarter.

Assuming WTI averages $50.00 US/bbl for the remainder of the year, the WTI – WCS differential averages $15.00 US/bbl, the exchange rate averages 1.30 CDN/US$ and including the benefits of our hedges, the Company forecasts funds from operations of approximately $32 million ($0.69/share) and year-end net debt of $62 million (1.7 times forecast fourth quarter funds from operations annualized).

Rock has positioned itself with a solid balance sheet, a stable production platform with a very low decline rate and a high net back production mix. Our assets will generate positive cash flow at WTI prices well below $40.00 US/bbl, providing a very resilient foundation to weather the storm. Strategically, Rock’s 2015 business plan has been directed at activities that have proven the feasibility of our EOR project, delineated the extent of the Viking play and confirmed the new cost structure, while preserving our existing inventory.

We are focused on building a strong foundation and inventory of growth prospects. This disciplined approach is targeted to maintain a financially flexible organization with a long term view to value creation. As prices improve, we are positioned with a solid inventory of opportunity to provide the next level of growth for our shareholders.

For further information please visit Rock’s website at www.rockenergy.ca.

Conversion Measures

Production volumes and reserves are commonly expressed on a barrel of oil equivalent (“boe”) basis. All conversions in this report are derived by converting natural gas to crude oil in the ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel (“bbl”) of crude oil. Certain financial values are presented on a boe basis and such measurements may not be consistent with those used by other companies. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Non-GAAP Measures

This document, including the accompanying financial statements also contain the terms “operating netback” and “total net capital expenditures” which do not have any standardized meaning prescribed by GAAP and may not be comparable with the calculation of similar measures for other entities and should not be considered an alternative to or more meaningful than the prescribed GAAP measure. Management believes these measures are helpful supplementary measures of financial performance and provide users with information that is commonly used by other oil and gas companies.

Operating netback has been calculated as oil and natural gas revenues, less royalties and production and operating expenses. Management believes this is a measure of operational profitability before administrative and other financing costs. Cash netbacks are calculated as operating netbacks less general and administrative expenses before share based compensation, and interest financing costs. Readers are cautioned that these measures should not be considered an alternative to, or more meaningful than, “net loss and comprehensive loss” as determined in accordance with GAAP as a measure of the Company’s performance.

Total net capital expenditures has been calculated to include the cash impacts of capital expenditures and property dispositions, as well as non-cash capital adjustments related to the Company’s decommissioning liability and share based compensation costs. Management believes that this provides supplemental information on the total capital spending for the period.

Additional-GAAP Measures

Funds from operations

This document, including the accompanying financial statements, contain the term “funds from operations” which does not have any standardized meaning prescribed by GAAP and should not be considered an alternative to, or more meaningful than, “cash flow from operating activities” as determined in accordance with GAAP as a measure of the Company’s performance. Funds from operations or funds from operations per share may not be comparable with the calculation of similar measures for other entities. Funds from operations as used in this report represent cash from operating activities before changes in non-cash working capital and decommissioning expenditures. See “Funds from operations” section for details of this calculation. Management believes that funds from operations represent both an indicator of the Company’s performance and a funding source for ongoing operations.

Other additional GAAP measures

This document, including the accompanying financial statements also contain the terms “adjusted working capital deficiency” and “net debt” which do not have any standardized meaning prescribed by GAAP and may not be comparable with the calculation of similar measures for other entities.

Working capital is defined as the difference between current assets and current liabilities. Working capital (deficiency) is the term used when the difference between current assets and current liabilities is a negative number which is quite common in the oil and gas industry. Adjusted working capital, and adjusted working capital deficiency have been calculated excluding the unrealized gains on commodity

price contracts from current assets and the unrealized losses on commodity price contracts and bank debt from current liabilities. Adjusted working capital and adjusted working capital (deficiency) represent operating liquidity available to the business and are included in the definition of the additional GAAP term “net debt”.

Net debt has been calculated as bank debt plus adjusted working capital or adjusted working capital (deficiency). Net debt is used to calculate the debt-to-annualized-funds from operations ratio. Management believes these measures are useful supplementary measures of the total amount of current and long-term debt. Total capitalization is calculated as net debt plus shareholders’ equity. Management believes this measure is a useful supplementary measure of the Company’s managed capital.

Advisory Regarding Forward-Looking Information and Statements

This press release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “expects”, “believe”, “plans”, “potential” and similar expressions are intended to identify forward-looking statements or information.

The forward-looking statements and information in this press release are based on certain key expectations and assumptions made by Rock, including the timing of regulatory approvals, prevailing commodity prices and exchange rates; applicable royalty rates and tax laws; future well production rates; reserve and resource volumes; the performance of existing wells; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; and the receipt, in a timely manner, of regulatory and other required approvals. Although Rock believes that the expectations and assumptions on which such forward-looking statements and information are based are reasonable, undue reliance should not be placed on the forward-looking statements and information because Rock can give no assurance that they will prove to be correct. There is no certainty that Rock will achieve commercially viable production from its undeveloped lands and prospects.

Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and natural gas industry in general, such as: operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; marketing and transportation of petroleum and natural gas and loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to realize the anticipated benefits of acquisitions; ability to access sufficient capital from internal and external sources; stock market volatility; and changes in legislation, including but not limited to tax laws, royalty rates and environmental regulations.

Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the operations or financial results of Rock are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). The forward-looking statements and information contained in this press release are made as of the date hereof and Rock undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

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 December 31, 2014 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.

Abbreviations