CALGARY, ALBERTA–(Marketwired – March 19, 2015) – Rock Energy Inc. (TSX:RE) (“Rock” or the “Company”) is pleased to report its financial and operating results for the year and three months ended December 31, 2014.
Rock has filed its Annual Information Form (AIF), which includes Rock’s reserves data and other oil and natural gas information for the year ended December 31, 2014. The AIF includes annual disclosure regarding reserves data and other oil and gas information as mandated by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators. Copies of Rock’s audited financial statements and related management’s discussion and analysis and AIF for the year ended December 31, 2014 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.
|Year Ended December 31,||2014||2013|
|Crude oil and natural gas revenue ($000)||$||132,314||$||81,717|
|Funds from operations ($000) (1)||$||66,064||$||30,571|
|Per share – basic||$||1.65||$||0.78|
|Net loss ($000)||$||(17,203||)||$||(1,806||)|
|Per share – basic||$||(0.43||)||$||(0.05||)|
|Total net capital expenditures ($000) (2)||$||118,873||$||46,726|
|As at December 31,||2014||2013|
|Net debt (1) ($000)||$||69,032||$||18,135|
|Common shares outstanding (000)||40,444,997||39,423,913|
|Options outstanding (000)||3,082,981||3,123,106|
|Year ended December 31,||2014||2013|
|Average daily production|
|Crude oil and natural gas liquids (bbls/d)||4,764||3,195|
|Natural gas (mcf/d)||1,363||2,183|
|Average product prices|
|Crude oil and natural gas liquids (Cdn$/bbl)||$||74.53||$||68.03|
|Natural gas (Cdn$/mcf)||$||4.98||$||3.45|
|Combined average (Cdn$/boe)||$||72.63||$||62.91|
|Operating netback (Cdn$/boe) (2)||$||38.95||$||27.37|
|(1) Funds from operations and net debt are considered additional-GAAP measures; Refer to the “Additional-GAAP Measures” section at the end of this release.|
|(2) Operating netback and total net capital expenditures are considered Non-GAAP measures; Refer to the “Non-GAAP Measures” section at the end of this release.|
LETTER TO THE SHAREHOLDERS
Hello, and welcome to this year’s Report to Shareholders from Rock Energy Inc.
We have much news to share and I trust you will find this report useful. At the outset, I would like to quickly say that your interest in our Company is greatly valued. From myself and the entire Rock team – thank you for your continued investment. We recognize that you have a wide variety of options when choosing to place your confidence, your capital, and your trust – and we appreciate having your support.
Last year was a remarkable year for our Company as we transitioned into a lighter oil, high net back producer, working to establish a solid foundation of low decline assets. This year has already presented a new challenge, that of a lower commodity price environment, which we are actively managing by driving cost efficiencies and reducing our capital spending.
Certainly, the facts and insight presented in this report will provide a much more fulsome picture of our operations than I can offer with these few words, but if nothing else, be confident that Rock is working to better your investment. Your interests are ours.
Sincerely, and on behalf of the Board of Directors:
Allen J. Bey, President and Chief Executive Officer
REPORT TO SHAREHOLDERS
The last year has been a year of significant accomplishment for Rock. Our total corporate production grew from an annual average of 3,559 boepd in 2013 to 4,991 boepd in 2014, an increase of 40%. During the fourth quarter Rock’s daily production averaged 5,328 boe/d, up 32% from the year before, and 12% from the third quarter of 2014. At the same time we were growing production, our funds from operations per share was also increasing. During 2014, Rock’s fully diluted funds from operations per share were $1.58 (up 108% from 2013) and in the fourth quarter were $0.35.
Rock spent $118.9 million in total net capital expenditures in 2014, to replace 183% of our production and grow our proven plus probable reserve base by 15%, despite the disposition of heritage heavy oil assets in the first quarter. Our all in finding, development and acquisition (“FD&A”) costs (including revisions, acquisitions and dispositions) were $28.89/boe for the year generating a recycle ratio of 1.4. In our core growth areas, the FD&A costs at Mantario/Laporte were $14.03/boe generating a recycle ratio of 3.1 and at Onward in the Viking play they were $35.25/boe which yields a recycle ratio of 1.7. During the year the Company was quite focused on our core growth assets of Mantario/Laporte and Onward while at the same time divesting of non-core assets in Lloydminster and West Central Alberta. The base decline rate of our asset base is now less than 20% and we estimate that we could maintain flat production at approximately 5,000 boepd by spending $35 – $40 million per year.
During 2014, our focus at Mantario/Laporte was to construct infrastructure in order to implement our Enhanced Oil Recovery (“EOR”) project to maximize the recovery factor, arrest declines and trigger the reduced royalty program offered by the Saskatchewan government. We were also able to consolidate our ownership in the asset through the acquisition of two offsetting competitors. The production from this asset was essentially flat for the year averaging approximately 3,380 boepd.
While we were focusing on the implementation of the EOR scheme at Mantario/Laporte, we were growing our production base at Onward. Production of light oil at Onward grew from 200 boepd at the beginning of the year to over 1,200 boepd by the end of the year. While this production growth is clearly significant, more importantly the Company was able to de-risk the Viking light oil play on 40 sections of our lands which validates numerous potential follow-up drilling locations.
The Company also discovered a new Mannville oil pool at Onward in late 2013 and began to delineate the size of the pool in 2014. By the end of the year, Rock had drilled 4 (4.0 net) wells into the pool, and shot a 30 section 3D seismic survey over the surrounding lands. This exploration activity is ongoing and is expected to yield a number of new drilling opportunities and exploration leads.
Rock continues to focus its asset base on those that have higher product prices and lower operating costs yielding higher netbacks. During 2014 we divested most of our heritage heavy oil assets with high operating cost generating low operating netbacks. Over the last 3 years, the Company has been able to reduce its cash costs per boe by over 10%, and we are forecasting another 30% reduction as we move into 2015.
Rock’s 2014 Operating Accomplishments
2014 Drilling Results
During the fourth quarter of 2014 the Company drilled a total of 27 (27.0 net) wells including 16 (16.0 net) Onward Viking Horizontal wells, 8 (8.0 net) Mantario/Laporte wells, 1 (1.0 net) standing exploration well and 2 (2.0 net) dry and abandoned wells for an average success rate of 93%.
For the full year of 2014 the Company drilled a total of 75 (75.0 net) wells including 39 (39.0 net) Onward Viking Horizontal wells, 21 (21.0 net) Mantario/Laporte wells, 7 (7.0 net) Mannville wells, 2 (2.0 net) standing exploration wells and 6 (6.0 net) dry and abandoned wells for an average success rate of 92%.
Rock spent $65.4 million at Mantario/Laporte in 2014 to drill 21 (21.0 net) oil wells, construct processing facilities and install the EOR water/chemical injection equipment. At year-end the proved plus probable reserve booking for the pool had increased by 32% from the prior year to 5.6 mmboe. The value of the asset using our independent reserves engineers (“GLJ Petroleum Consultants” or “GLJ”) January 2015 Price Forecast was estimated to be approximately $115 million, up 62% from last year. At this time GLJ is forecasting the pool (with an original oil in place (“OOIP”) of approximately 40 million boe) to achieve a total recovery factor of 20% with the EOR scheme, and to begin receiving the Saskatchewan EOR royalty relief in April 2015 until payout of the project at which time the average royalty rate for the project will move from 1% to approximately 10%.
Polymer injection for the pool began on March 11, 2015, the Company has received all the approvals from the Saskatchewan government for the EOR royalty treatment and we are scheduled to begin receiving the 1% royalty treatment effective April 1, 2015. The Company is forecasting production from the pool to remain relatively flat (3,000 – 3,200 boepd) for one – two years as the polymer flood is implemented and the typical production decline (in a pool of this type) is arrested.
During 2014, Rock spent $48.0 million at Onward on the Viking program to drill 39 (39.0 net) wells and construct a clean oil processing facility. This activity was strategic in defining the extent of the play to the northwest, de-risking the play on 28 sections of land (as per GLJ). Based on mapping of offset vertical wells and the production results achieved to date, Rock’s management believes the gas oil contact extends to the northwest and the play is present on 40 sections, which could yield up to 600 drilling locations (based on 16 wells per section). During the year Rock continued to add prospective Viking land in this area and we now have over 47 net sections of land.
The reserves booked for the Viking at year-end 2014, on a proved plus probable basis, have increased 139% from last year to 3.2 million boe. The value of this asset is now estimated by GLJ to be approximately $58 million. The engineering report only assumes that there are 55 locations to be drilled, most of which are deferred until 2016 and 2017 given our approved capital spending program, and current price forecasts. Recent completion techniques have resulted in initial production rates from the wells being 35% better than previously achieved. We anticipate this higher production rate will improve the net present value of these wells. Though the initial production rates were much better there was limited long term production data available at year-end, so no increase in the ultimate recoverable reserves (relative to the 2013 reserve report) from the wells was recognized.
Production from the Onward light oil Viking play has increased from approximately 200 boepd early in the year to over 1,200 boepd by the end of the year. Rock continues to produce over 1,200 boepd from the Viking today.
In addition to the Viking activity at Onward, in 2013 we discovered a new Mannville oil pool to the west of our two existing Mannville waterflood pools. This discovery was followed up with 4 (4.0 net) more oil wells in 2014 and a 30 section 3D seismic shoot. Presently we are producing approximately 500 boepd from these pools and completing the interpretation of the seismic data. Though we have no capital budgeted for exploration drilling at this time, a successful oil well in this play type will generate attractive economic returns at the current forward strip price and would likely be the focus of any additional capital spending beyond the approved budget should prices recover.
2014 Reserves Summary
Rock’s total proved plus probable reserves are 12.5 million boe (over 95% crude oil and natural gas liquids), up 15% compared to 10.9 million boe last year. Total proved reserves now make up 70% of the proved plus probable category (compared to 63% last year) as they have increased to 8.7 million boe from 6.8 million boe. All-in finding, development and acquisition costs (including changes in future development capital, revisions, acquisitions and divestitures) averaged $28.89 per proved plus probable boe generating a recycle ratio of 1.4 and $29.50 per total proved boe generating a recycle ratio of 1.3.
Though the price forecast for WTI adopted by GLJ has fallen by 36% in 2015, our proved plus probable reserve value still increased by 34% to $217 million. This increase is attributable to the increase in reserves, and the reduced royalties due to the EOR royalty program approval at Mantario/Laporte. Rock’s net asset value (BTAX 10%, proved plus probable) as of December 31, 2014 was $4.17 per basic share assuming an undeveloped land value of $21.0 million, and year-end net debt of $69.0 million. The proved plus probable reserve evaluation completed by GLJ only has 85 booked drilling locations and the future development capital has been limited to our currently approved capital program (2015 – $25.9 million, 2016 – $50.6 million, 2017 – $9.9 million).
Further information respecting Rock’s year-end reserves is contained in its AIF, which has been filed on the SEDAR website at www.sedar.com and may also be obtained on Rock’s website at www.rockenergy.ca.
Rock generated funds from operations of $66.1 million ($1.65 per basic share, $1.58 per fully diluted share) in 2014, compared to $30.6 million ($0.78 per basic share) in 2013, an increase of 108%. For the fourth quarter of 2014, the Company generated funds from operations of $14.8 million ($0.37 per basic share) compared to $16.7 million ($0.41 per basic share) in the third quarter of 2014. Realized prices averaged $60.09/boe during the fourth quarter, compared to $72.63/boe during the year and $75.56/boe in the third quarter of 2014.
Operating costs have trended downward as the Company focuses its attention toward Mantario/Laporte and Onward Viking. During 2014, operating costs averaged $15.81/boe compared to $19.33/boe the year before (an 18% reduction). As we move into 2015 operating costs are forecast to increase with the injection of polymer and increased fluid handling at Mantario/Laporte. The Company’s G&A costs in 2014 were $2.17/boe, which is a 31% reduction when compared to $3.16/boe in 2013.
Even though production and cash flow was up in 2014 (compared to the year before) Rock generated a net loss of $17.2 million ($0.43 per basic and fully diluted share) compared to a net loss of $1.8 million ($0.05 per basic share) in 2013. This loss was essentially generated by accelerated depletion and impairment on certain non-core natural gas properties in the fourth quarter, and the sale of the heritage heavy oil assets in the first quarter.
Rock incurred total net capital expenditures of $118.9 million in 2014 of which $65.4 million was focused on Mantario/Laporte, and $48.0 million was spent on the emerging Viking play at Onward. Year-end net debt was $69.0 million against available bank lines of $80.0 million resulting in a net debt to fourth quarter annualized funds from operations ratio of 1.2.
2015 Area Activity Update
To date in 2015, Rock has drilled 6 (6.0 net) oil wells with 100% casing success including 3 (3.0 net) Mantario/Laporte horizontal wells in the main pool, and 3 (3.0 net) horizontal Viking oil wells at Onward. These wells were all drilled prior to the Company’s decision to reduce its capital budget on January 26, 2015.
During the first quarter of 2015 Rock will spend $12.0 million at Mantario/Laporte to complete the drilling program and the construction of the EOR facilities. This program is largely complete, and polymer injection began on March 11, 2015. Production from the pool is currently averaging approximately 3,000 boepd. As the conversion of the remaining injectors is completed and the polymer begins to re-pressurize the reservoir, the Company expects production to stabilize in the 3,000 – 3,200 boepd range.
During the first quarter of 2015, the Company drilled an additional 3 (3.0 net) horizontal oil wells in to the Viking Formation at Onward. This has fulfilled all of our earning obligations and as such we have stopped the drilling of any additional wells. Production rates for these wells continue to improve as we refine the drilling and completion techniques. When compared to the results from the original wells, the most recent completions are generating production rates 35% higher on average. This is very encouraging as higher initial production rates significantly improve the net present value of these drilling opportunities.
Rock continues to add to our land position in this area and now has over 47 net sections. Our drilling activity in 2014 has demonstrated that the gas-oil contact is located further to the north-west, thus expanding the potential size of this pool to 40 sections.
Total production from the Viking net to Rock has increased considerably in the last year and is currently averaging over 1,200 bopd from 49 wells of the 52 wells drilled (3 wells have been drilled, but not yet completed).
During the fourth quarter of 2014, Rock completed a 3D seismic shoot on 30 sections of land in the Onward area to follow up on a Mannville discovery. At the present time this seismic data is being interpreted and is expected to generate economic exploration leads that could be pursued in the second half of 2015.
During the last six months crude oil prices have experienced a very significant decline as global supply/demand forecasts illustrated a potential imbalance. Industry capital spending response around the world has been swift as oil producers moved to cut capital spending programs, and production growth. There has been a significant reduction in active drilling rigs, and this will eventually lead to a reduction in production. It is believed that once the supply response is evident, the supply/demand balance will be restored, and the oil prices will move up from their current levels as many oil drilling opportunities are not viable at these price levels. The forward strip price is supporting this assumption.
Despite the effect of falling crude oil prices we are benefiting from a lower Canadian to US dollar exchange rate. For every $0.01 change in exchange rate, the Company’s funds from operation changes by approximately $0.8 million annually. For 2015, Rock is assuming that WTI averages $55.00 US/bbl, WTI – WCS differential averages $15.00 US/bbl, and the exchange rate averages $1.25 CDN/US.
Outlook and 2015 Guidance
Given the current level of crude oil prices, Rock reduced its capital budget in 2015 to $25 million on January 26, 2015.
On March 4, 2015, Rock closed a bought deal financing for total gross proceeds of $15.1 million, issuing a total of 6.44 million common shares at a price of $2.35 per share. This financing, combined with the reduction in our capital program has placed Rock on a solid foundation financially.
Strategically, Rock’s 2015 business plan is directed at activities that confirm proof of concept, capture new opportunities and preserve our existing inventory. This disciplined approach is targeted to maintain a financially flexible organization with a long term view to value creation.
Rock is focused on spending the minimum amount of capital to complete the essential projects related to the Mantario/Laporte EOR scheme so that reservoir pressure can be maintained and the polymer injection can begin. This will ensure the maximum recovery factor, lowest decline rate, and the receipt of the EOR royalty incentive. Polymer injection began on March 11, 2015 and we are scheduled to begin incurring the 1% royalty rate on April 1, 2015.
As per its previously announced guidance, the Company is planning to spend $17 – $18 million in the first half of the year, and up to $25 million for the whole year. This capital spending plan will generate average production for the year of 4,600 – 5,000 boepd. Assuming WTI averages $55.00 US/bbl for the year ($50.00 WTI US$/bbl for Q1 and Q2, and $60.00 WTI US$/bbl for Q3 and Q4), the WTI – WCS differential averages $15.00 US/bbl, and the exchange rate averages 1.25 CDN/US$ the Company would generate funds from operations of approximately $35 million ($0.77/share) and have yearend net debt of $44 million (1.0 times Q4 funds from operations annualized).
2015 is proving to be a challenging year for our industry as we manage a significant reduction in commodity prices. Rock has been proactive in guarding its balance sheet by reducing the capital program and raising equity. We are focused on reducing costs at all levels, have developed a sustainable asset base with low decline rates and we will be conservative and prudent with our capital spending as we remain flexible to react to changing oil prices.
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.
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.
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.
|bcf||billion cubic feet||mboe||thousand barrels of oil equivalent|
|boe||barrels of oil equivalent||mboe/day||thousand barrels of oil equivalent per day|
|bps||basis points||mcf||thousand cubic feet|
|CDOR||Certificate of Deposit Offered Rate||mmcf||million cubic feet|
|hectare||1 hectare is equal to 2.47 acres|
|mmboe||million barrels of oil equivalent|
|km||kilometre||NGL||natural gas liquids|
|WTI||West Texas Intermediate|
|WCS||Western Canadian Select|
Rock Energy Inc.
Allen J. Bey
President and Chief Executive Officer
Rock Energy Inc.
Vice President Finance and Chief Financial Officer