CALGARY, ALBERTA -- (Marketwired) -- 08/04/16 -- RMP Energy Inc. ("RMP" or the "Company") (TSX: RMP) today provides an update on its bank credit facility re-determination and its second quarter field operations. The Company also announces that it has closed the previously-announced purchase of assets in the Gold Creek area and that it has initiated a process to review strategic options with a view to maximizing the value of the Company's large Montney resource base.
Strategic Discussion and Retention of Financial Advisors
The current macroeconomic commodity price environment continues to beleaguer the North American oil and gas sector. The downturn in commodity prices over the last two years has challenged the ability of growth-oriented oil and gas producers such as RMP to finance exploration and development capital investment. RMP has established an extensive portfolio of Montney opportunities at Waskahigan, Ante Creek and Kaybob, as well as a highly prospective land position at Gold Creek, however, the capital requirements necessary to fully exploit these opportunities exceed the Company's current capital structure. As a result, RMP has engaged financial advisors to assist the Company to evaluate, develop and recommend one or more strategic initiatives necessary to maximize shareholder value and 'unlock' the intrinsic value of RMP's assets. The Company's value proposition is underpinned by its high-quality assets, which are highlighted as follows.
At Ante Creek, through successful development with horizontal infill drilling and multi-stage completion fracturing, the Company's Montney reservoir across its original six section land block has achieved cumulative production of approximately 4.5 million barrels of light oil and 20.33 Bcf of associated solution sales gas (as of June 30, 2016). As a result of the unique geological characteristics of this solution-gas driven Montney oil pool, initial well productivity was robust, with many of the Company's wells being amongst the most prolific oil wells drilled in the Alberta basin. This oil pool is now transitioning to a secondary recovery, water flood development phase. Full, successful water flood implementation across the Company's legacy six section land block, in addition to moderating reservoir declines, has the potential to extend the economic life of the pool and significantly increase the expected proved plus probable oil reserves recovery factor. Expansion of the water flood at Ante Creek may also qualify for the Alberta Government's recently-announced Enhanced Hydrocarbon Recovery Program ("EHRP"), which would, if it qualifies, significantly improve the economics of this water flood program. By optimizing the oil reserves recovery through water flood, RMP's Ante Creek asset is expected to provide a commensurate platform for free cash flow generation, which could be re-invested into the Company's other Montney opportunities. In addition to the value-upside potential of secondary recovery, the Company's overall acreage position at Ante Creek encompasses 35.5 gross sections (35.2 net) of focused lands, providing for a future potential light oil drilling inventory of approximately 42 step-out and delineation locations (of which only seven locations have been assigned reserves in the Company's year-end 2015 independent reserves report).
At Waskahigan, the Company's hybrid slick water ("HSW") fracture completion technique has resulted in improved well productivity, which is expected to significantly improve the Waskahigan well project economics. The Company's Waskahigan type-well used in its forecasting, which is determined by RMP's internal, qualified reserves evaluator from the average well production profile of its nine producing HSW wells, assumes an estimated first year average production rate of 230 boe/d (150 bbls/d of light oil) and a pre-tax net present value (discounted at 10%) of $4.2 million per location and a rate of return of 97% (based on RMP's independent reserves evaluators' June 30, 2016 price forecast and including the estimated benefit of the Alberta Government's new Modernized Royalty Framework ("MRF"). The Company views its Waskahigan area as a growth asset with a substantial future inventory of approximately 200 potential undeveloped drilling locations to which the HSW completion technique can be applied (of which only 52 locations have been assigned reserves in the Company's year-end 2015 independent reserves report). An active, full development drilling program at Waskahigan has the potential to offset field declines and deliver profitable production and reserves growth for the Company.
At Gold Creek, the Company's large undeveloped land base of 78 (77.5 net) sections (49,920 gross acres) of operated acreage, accumulated through Crown land sale activity and the previously-announced strategic asset purchase, provides RMP with an extensive prospect inventory and a field infrastructure presence. RMP intends to delineate the areal extent of the hydrocarbon-bearing Middle Montney Formation trend in Gold Creek with additional exploration and step-out drilling in 2017, as follow-up to its successful, 100% working interest exploration well drilled and completed earlier this year. Preliminary analysis of the financial impact on RMP's Gold Creek well economics, as a result of the Alberta Government's new MRF, suggests a significant, positive impact on the Company's estimated type-well net present value and the overall value of the Company's Montney light oil drilling inventory. The Gold Creek area may also qualify for the recently-announced Alberta Government's Emerging Resources Program ("ERP"), which would be expected to further enhance the play economics. The Company estimates that it has potentially in excess of 100 un-booked locations at Gold Creek to drill, which are not included in the reserves assigned in the Company's year-end 2015 independent reserves report. With an established, significant acreage 'footprint' in the Gold Creek area, continued exploration and step-out drilling success at Gold Creek has the potential to be a long-term growth asset for the Company.
The Company's updated net asset value is estimated at approximately $2.70 per share, as at June 30, 2016. Details of RMP's estimated net asset value are set out at the end of this news release.
RMP has initiated a process to review strategic alternatives with a view to maximizing the value of the Company's large Montney resource base. This may include, among other alternatives, the addition of capital to further develop the potential of the assets, the sale of the Company or a portion of the Company's assets, a merger, farm-in or joint venture, or other such options as may be determined by the Company's Board of Directors to be in the best interests of the Company and its shareholders. RMP has engaged FirstEnergy Capital Corp. ("FirstEnergy") and Scotia Waterous Inc. as co-advisors to assist in this process. FirstEnergy will coordinate and lead the process. The Company has not set a definitive schedule to complete its evaluation and no decision on any particular alternative has been reached at this time. RMP does not intend to disclose developments with respect to this process unless and until the Board has approved a definitive transaction or other course of action or otherwise deems disclosure of developments is appropriate or otherwise required by law. There are no guarantees that the process will result in a transaction of any form or, if a transaction is entered into, as to its terms or timing.
Bank Credit Facility Update
The Company announces that its two-bank syndicate group (the "Lenders") has completed its borrowing base re-determination review of RMP's revolving bank credit facility (the "Credit Facility"). As a result of the Lender's review, the Company's borrowing base has been re-determined with a total conforming commitment amount of $120 million with a scheduled step-down to $100 million at October 31, 2016, being the date of the next scheduled borrowing base re-determination. The step-down may occur earlier on the occurrence of certain events that generate additional liquidity. RMP is presently drawn approximately $109 million on its Credit Facility and estimates net debt at June 30, 2016 of approximately $105 million and year-end 2016 net debt of approximately $95 million, which is a 19% reduction from RMP's year-end 2015 net debt. The Company continues to maintain a reasonable level of balance sheet leverage and expects to have sufficient liquidity to support its activities and expects to fund its 2016 planned capital expenditures with the March 2016 equity financing and forecasted funds from operations (refer to the updated 2016 guidance provided later in this press release). The Credit Facility continues to include one financial covenant: an interest-coverage ratio of 3.5 times (350%) for the current and three immediately preceding quarters thereto. The Company's estimated interest coverage ratio for the four trailing quarters ended June 30, 2016 is approximately 15 times, well in excess of the required minimum 3.5 times.
Operations, Production and Market Guidance Update
In the second quarter, the Company drilled three (3.0 net) Montney horizontal oil wells, one at Ante Creek (5-27-66-24W5) and two at Waskahigan from the same surface lease pad (02/16-10-64-23W5 and 13-9-64-23W5). RMP also drilled another Waskahigan well (5-34-63-23W5) in July. Frac oil-based completion operations were undertaken on the Ante Creek well in the second quarter, which was recently brought on-production. A hybrid slick water ("HSW") fracture stimulation on the first Waskahigan well was completed and the well is presently undergoing clean-up and flow-testing. The second Waskahigan well completion is scheduled to occur following the end of the flow-test of the first well. The Company expects to bring both of these Waskahigan wells on-production in late-August. HSW completion operations are anticipated to occur on the third Waskahigan well in mid-August. RMP's drilling program in the second quarter benefitted from field service cost reduction and drill time efficiencies, wherein the drilling costs for the Ante Creek and Waskahigan horizontal wells averaged approximately $1.5 million and $1.4 million, respectively (based on field cost estimates), which has decreased from average 2015 drilling costs of $1.9 million at Ante Creek and $2.1 million at Waskahigan. For the second quarter, the Company invested an estimated total of $17.5 million in capital expenditures, including successful Gold Creek Crown land purchases and the Gold Creek asset acquisition (outlined below).
At Ante Creek, in addition to drilling a horizontal oil well in the second quarter and commencement of its secondary recovery water flood initiative, RMP has converted a producing horizontal oil well into a pilot water flood injector (8-26-66-24W5) with water injection underway. Full, successful water flood implementation across the Company's legacy six section land block, in addition to moderating reservoir declines, has the potential to extend the economic life of the pool and significantly increase the expected proved plus probable oil reserves recovery factor of RMP's large oil-in-place reservoir at Ante Creek.
On June 27, 2016, the Company closed the previously-announced strategic purchase of assets in the Gold Creek area of West Central Alberta for total cash consideration of approximately $10 million. The purchase price was funded from RMP's available bank credit facility. The Gold Creek acquisition has been included within the Company's previously-announced fiscal 2016 capital budget of $50 million. The material attributes of the acquired assets include 20 sections (12,800 acres) of 100% working interest acreage prospective for Montney light oil with significant exploration and development potential, which are primarily contiguous to RMP's existing Gold Creek lands. The Company has now accumulated a large undeveloped land base of 78 (77.5 net) sections (49,920 gross acres) of operated acreage at Gold Creek. As part of this purchase transaction, the Company also acquired an 87.4% working interest in a multi-well battery facility and compressor station in close proximity to the surface lease for RMP's successfully-drilled 3-22 exploration well in the Gold Creek area, in addition to assorted gathering lines. The cost incurred to drill and complete this well was approximately $4.3 million. RMP is very encouraged with the flow-test results from this well, with production tie-in scheduled for early-2017 through the acquired infrastructure
For the second quarter of 2016, RMP's average daily production was 8,425 boe/d (weighted 43% light oil and NGLs). In addition to pared-back drilling activity over the last six months and natural field declines, second quarter production was impacted by an unscheduled outage of a mid-stream-operated gas plant in the Kaybob area due to a mechanical failure of its sulphur-handling infrastructure. As a result, on May 25, 2016 the Company's Kaybob Montney gas field was shut-in through to June 29, 2016, which impacted and reduced the Company's second quarter production levels by approximately 425 boe/d for the quarter. At the time of shut-in, Kaybob production was approximately 1,100 boe/d. Had this mid-stream outage not occurred, RMP estimates second quarter 2016 corporate production would have approximated 8,850 boe/d. RMP estimates its overall field operating netback to average $12.75/boe in the second quarter of 2016.
In addition to the aforementioned mid-stream gas plant outage at Kaybob, RMP's Montney oil operations at Waskahigan and Ante Creek are expected to experience temporary production curtailments later this year due to third-party outages on both the Pembina and Alliance sales pipeline systems. The Company has been notified of an eight day outage on the regional Pembina pipeline system commencing on or about October 12, 2016. Additionally, commencing on or about the same date in October, there will be no transportation services permitted on the Alliance sales gas system due to a mainline pipeline upgrade resulting in a complete system outage. Collectively, the mid-stream gas plant outage at Kaybob and the sales pipeline system disruptions will impact the Company's fiscal 2016 market guidance production forecast. As a result, fiscal 2016 production is projected to average approximately 8,500 boe/d (weighted 42% light crude oil and NGLs), which is approximately 7% lower than its previously-guided fiscal 2016 production. The Company's forecasted fiscal 2016 funds from operations is estimated at approximately $40 million, based on US$43.00/bbl for WTI oil, C$2.00/GJ for AECO gas and an exchange rate of $0.7525 (US$/C$) for fiscal 2016. The Company re-affirms its fiscal 2016 capital expenditures budget of approximately $50 million, of which approximately 40% or $20 million has already been invested in the emerging new core area of Gold Creek, including the recently-closed asset acquisition, drilling, completion and testing of the Company's 3-22 exploration well and undeveloped Montney Crown land purchases year-to-date.
Second Quarter 2016 Financial Reporting
RMP's interim condensed consolidated financial statements and associated Management's Discussion and Analysis for the three and six months ended June 30, 2016 is scheduled to be released on August 15, 2016.
Abbreviations
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bbl or bbls barrel or barrels Mcf/d thousand cubic feet per
day
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Mbbl thousand barrels MMcf/d million cubic feet per day
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bbls/d barrels per day MMcf Million cubic feet
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boe barrels of oil equivalent Bcf billion cubic feet
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Mboe thousand barrels of oil psi pounds per square inch
equivalent
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boe/d barrels of oil equivalent kPa kilopascals
per day
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NGLs natural gas liquids GJ Gigajoule
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WTI West Texas Intermediate GJ/d Gigajoules per day
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NI 51-101 National Instrument 51-101 - Standards of Disclosure for Oil
and Gas Activities
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COGE Handbook Canadian Oil and Gas Evaluation Handbook
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Estimated Net Asset Value - June 30, 2016
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The Company's estimated net asset value details, as
of June 30, 2016, are as follows:
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(per share figures based on basic common shares
outstanding) ($000s) $/share
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Proved plus probable reserves NPV (1,3) $ 312,572 $ 2.07
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Proved plus probable reserves NPV - Gold Creek (2,3) 35,582 0.23
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Undeveloped acreage (4) 153,418 1.02
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2016 acquired undeveloped acreage (5) 9,315 0.06
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Net debt (6) (104,520) (0.69)
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Net Asset Value (basic shares) (7) $ 406,367 $ 2.69
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(1) Reflects the before tax net present value of future net revenue for the
Company's year-end 2015 independently-evaluated proved plus probable
reserves using its independent reserves evaluators' June 30, 2016 price
forecast as set forth in the table below and adjusted for forecasted
production for the period between January 1, 2016 and June 30, 2016 and the
future development capital associated with wells drilled during that
aforementioned period which were assigned reserves at year-end 2015,
discounted at 10% per year and prepared in accordance with NI 51-101 and
the COGE Handbook. Net present values ("NPV") do not represent fair market
value of the reserves.
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(2) Reflects the estimated before tax NPV of future net revenue of the
internally-assigned and evaluated proved plus probable reserves for the
Company's Gold Creek property prepared by RMP's internal, qualified
reserves evaluator, effective June 30, 2016, using its independent reserves
evaluators' June 30, 2016 price forecast as set forth in the table below,
discounted at 10% per year and prepared in accordance with NI 51-101 and
the COGE Handbook. These internally-assigned and evaluated Gold Creek
proved plus probable reserves were not included in the Company's year-end
2015 independently-evaluated proved plus probable reserves report.
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(3) No provision for bank debt interest and general and administrative
expenses have been made within the net present values.
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(4) Independently-evaluated as of December 31, 2015 with average acreage
value of $734 per acre.
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(5) Reflects acquired Gold Creek land acreage cost during the first six
months of 2016, including Crown land sales and PN&G rights per the Gold
Creek asset acquisition.
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(6) Estimated net debt as at June 30, 2016 (unaudited), per the Company's
definition of this non-IFRS figure.
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(7) Basic common shares outstanding at June 30, 2016 are 151.0 million.
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Forecast Prices - June 30, 2016
A summary of InSite Petroleum Consultant's escalated price forecast assumptions as of June 30, 2016 are as follows:
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WTI Price - Edmonton Price AECO-C
Oil - Oil Price - Gas Exchange Rate
Year ($US/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($Cdn/$US)
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2016 (Jul-Dec) 50.00 58.60 2.50 0.78
2017 55.00 65.51 3.00 0.78
2018 60.00 71.82 3.33 0.78
2019 65.00 75.04 3.78 0.81
2020 70.00 79.03 3.95 0.83
2021 75.00 82.82 4.12 0.85
2022 80.00 88.60 4.39 0.85
2023 85.00 94.37 4.48 0.85
2024 86.70 96.26 4.57 0.85
2025 88.43 98.18 4.66 0.85
2026 90.20 100.15 4.76 0.85
2027 92.01 102.15 4.85 0.85
2028 93.85 104.19 4.95 0.85
2029 95.72 106.28 5.05 0.85
2030 97.64 108.40 5.15 0.85
2031 99.59 110.57 5.25 0.85
2032 101.58 112.78 5.36 0.85
2033 103.61 115.04 5.46 0.85
Escalation rate of 2% per year thereafter
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Reader Advisories
Any references in this news release to initial and/or final raw test or production rates and/or "flush" production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter. These test results are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company.
Statements relating to "reserves" are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. In this news release, any estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and net revenue for all properties due to the effects of aggregation. Estimates of reserves have been made assuming that development of each property, in respect of which estimates have been made, will occur without regard to the availability of funding required for that development.
The information in this news release contains certain forward-looking statements. These statements relate to future events or our 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", "approximate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe", "would" and similar expressions. More particularly and without limitation, this news release contains forward-looking information relating to: the estimated volume and product mix of the Company's oil and gas production; estimates of net debt; future oil and natural gas prices; future liquidity and financial capacity to fund 2016 planned capital expenditures; future results from operations and operating metrics; the anticipated impact of the MRF; expectations as to whether the Gold Creek area will qualify for the ERP and its effect on play economics; future exploration and development activities and related capital expenditures and the timing thereof; the number of wells to be drilled, completed and tied-in and the timing thereof; estimated future drilling inventory and growth potential associated with the Company's Gold Creek area of operations; the Company's drilling and other operational plans at Gold Creek; the number of estimated potential drilling locations at Waskahigan and the anticipated benefits of enhanced completion techniques; anticipated effect of an active, full development drilling program at Waskahigan on declines, production and reserves growth; the potential impact of water flood implementation at the Company's Ante Creek area of operations and potential for increased recoveries, moderating reservoir declines and extending the economic life of the pool;
expectations as to whether future water flood projects at Ante Creek will qualify for the EHRP and its effect on economics; estimated field operating netbacks and expectations regarding free cash flow generation from the Ante Creek asset; expectations regarding production curtailments later in fiscal 2016; forecasted average 2016 production, funds from operations, net debt and second quarter 2016 and fiscal 2016 capital expenditures levels; completion of the Company's strategic options review process, including timing and disclosure of developments related thereto and potential transactions the Company may pursue as a result of the strategic options process. These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond the Company's control, including: the impact of general economic conditions; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; and obtaining required approvals of regulatory authorities. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that the Company will derive from them. The Company's forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statements.
This news release 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 the Corporation's most recent independent reserves evaluation as prepared by InSite Petroleum Consultants Ltd. as of December 31, 2015 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Corporation'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 Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company 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 Company 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.
In this news release RMP has adopted a standard for converting thousands of cubic feet ("mcf") of natural gas to barrels of oil equivalent ("boe") of 6 mcf:1 boe. Use of boes may be misleading, particularly if used in isolation. The boe rate is based on an energy equivalent 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.
As an indicator of the Company's performance, the term funds from operations contained within this news release should not be considered as an alternative to, or more meaningful than, cash flow from operating, financing or investing activities, as determined in accordance with International Financial Reporting Standards ("IFRS"). This term is not a recognized measure, does not have a standardized meaning nor is it a financial measure under IFRS. Funds from operations is widely accepted as a financial indicator of an exploration and production company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by shareholders and investors in the valuation, comparison and investment recommendations of companies within the natural gas and crude oil exploration and production industry. Funds from operations, as disclosed within this news release, represents cash flow from operating activities before: expensed corporate acquisition-related costs, decommissioning obligation cash expenditures, changes in non-cash working capital from operating activities and non-cash changes in deferred charge. The Company presents funds from operations per share whereby per share amounts are calculated consistent with the calculation of earnings per share.
Net debt refers to outstanding bank debt less deferred charge plus working capital deficiency (or minus working capital surplus), excluding unrealized amounts pertaining to risk management contracts. Net debt is not a recognized measure under IFRS and does not have a standardized meaning.
Field operating netback or operating netback refers to realized wellhead revenue less royalties, operating expenses and transportation costs per barrel of oil equivalent. Field operating netback or operating netback is not a recognized measure under IFRS and does not have a standardized meaning. Cash costs is not a recognized measure under IFRS; it is an aggregate of per-unit boe of operating, transportation, general and administrative expenses and bank interest.
EBITDA refers to earnings before interest, deferred taxes, depreciation, depletion, accretion, amortization, share-based compensation, impairment, unrealized gains or losses on risk management contracts and gains or losses from the disposition of assets. EBITDA is not a recognized measure under IFRS and may not have a standardized meaning.
Contacts:
RMP Energy Inc.
John Ferguson
President and Chief Executive Officer
(403) 930-6303
john.ferguson@rmpenergyinc.com
RMP Energy Inc.
Dean Bernhard
Vice President, Finance and Chief Financial Officer
(403) 930-6304
dean.bernhard@rmpenergyinc.com
