RMP Energy Announces Successful Elmworth Well and Provides Operations Update and Winter Drilling Capital Plans

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October 24, 2017

CALGARY, Alberta, Oct. 24, 2017 (GLOBE NEWSWIRE) -- RMP Energy Inc. (the “Company”) (TSX:RMP) is pleased to provide an operations update and announce its capital budget plans for this upcoming winter drilling season.  The Company is changing its corporate name to "Iron Bridge Resources Inc.". The name change is expected to become effective on or before November 17, 2017. The ticker symbol "IBR" has been reserved by the Toronto Stock Exchange for the Company's use following the name change becoming effective. 

Elmworth Drilling and Operations Update

The Company is pleased to announce that its Elmworth 15-23 Montney oil well achieved IP30 production of approximately 900 boe/d, which was constrained by gas compression for much of its initial first month of production. With those restrictions now eliminated, the 15-23 well is currently flowing at 1,180 boe/d (based on field estimates, consisting of 270 bbls/d of light sweet oil, 4.4 MMcf/d of natural gas sales, and 180 bbls/d of NGLs). This well has a significantly shorter lateral section than our other wells or our future planned wells. Normalizing for length and frac stages, this well is representative of the excellent economics that are being displayed in the Montney light oil window at Elmworth.

In the third quarter, the Company drilled and completed its fourth, 100% working interest Elmworth Montney horizontal well (15-23-68-3W6). Due to land restrictions, the lateral section of this horizontal well was drilled to 1,462 meters, which is approximately 750 meters shorter than the two previous wells at Elmworth and 1,000 meters shorter than our anticipated future drills. The Company changed the completion design on the 15-23 well relative to its first three wells at Elmworth.  Fracture stimulation intensity was increased by reducing the distance between stages to 50 meters and increasing the amount of sand per stage to 60 tonnes, meanwhile pump rate was reduced.  A total of 30 stages were completed with slickwater and the well was tied into the 2-23 Facility on September 13, 2017. During the first thirty producing days (“IP30”) the 15-23 well was mechanically choked-back due to the aforementioned gas compression capacity limitations. Notwithstanding this operational curtailment and a shorter lateral length, the 15-23 well produced on average an IP30 of approximately 900 boe/d, consisting of 210 bbls/d of light sweet oil, 3.6 MMcf/d of natural gas sales, and 90 bbls/d of NGLs. With additional compression now in-operation at the 2-23 Facility, the 15-23 well is currently producing above its IP30 rate, at approximately 1,180 boe/d. 

For the third quarter of 2017, the Company’s average daily production was approximately 4,000 boe/d, with light crude oil and NGLs volumes accounting for 31% of the third quarter production. The Company’s reported third quarter production level includes production contribution from the Waskahigan/Grizzly, Kabob, Gilby and Pine Creek areas of West Central Alberta, in addition to other minor Alberta properties, which were collectively sold on October 17, 2017, pursuant to the previously-announced strategic asset disposition (the “Transaction”).

The Company’s core Elmworth Montney property produced 1,410 boe/d on average for the third quarter, with a light oil and NGLs weighting of approximately 30%.  Only two of the Company’s Elmworth drilled-wells produced concurrently during the third quarter due to gas compression restrictions at its 2-23 Facility. In early-October 2017, however, additional compression was installed and as a result the Elmworth 2-23 Facility is presently handling the crude oil, emulsion and natural gas production from all three (3.0 net) of the Company’s Montney horizontal wells (3-22, 4-18 and 15-23) drilled at the same surface lease pad as the 2-23 Facility.

The Company’s 2-23 Facility now has capacity to handle 1,500 bbls/d of crude oil, approximately 16 MMcf/d of natural gas and 7,500 bbls/d of emulsion The Company’s current production at Elmworth is approximately 2,200 boe/d, weighted 35% light crude oil and NGLs (based on field estimates).

Winter Drilling Capital Budget

The Company’s Board of Directors has approved a capital expenditures program of approximately $25 million, to be invested at its Elmworth asset base for this upcoming winter drilling season (present through to April 30, 2018). 

The Company plans to drill a total of five (5.0 net) wells this winter season with two of the wells to be completed and tied into the 2-23 Facility prior to spring break-up and two to be drilled but not completed until later in 2018. The fifth well is a water injection well that is expected to spud in early-November. The two drilled and uncompleted wells will continue 41 sections of prospective acreage past its primary expiry date through to the year 2020. The two upcoming wells at the Company’s 2-23 Facility pad site will be drilled with approximately 2,400 meters of lateral length and will be completed with approximately 80 slickwater stages in January 2018.  Drill, complete and tie-in costs for these two wells is estimated to be approximately $5.7 million per well.       

With the closing of the previously announced Transaction, the Company has significant financial flexibility and full funding capability to carry out its winter drilling capital budget.  The Company estimates that exiting this year-end of 2017, it will have approximately $33 million of liquidity (positive working capital plus investments) and no bank debt outstanding. The Company will remain flexible as it monitors results and commodity prices over the coming months and, may adjust its planned winter capital expenditures.  The Company has flexibility to adjust the level of its capital investments as circumstances warrant. 

In addition to the Company’s operated delineation and development plans at Elmworth, Montney drilling and completion activities are being undertaken in close proximity to the Company’s acreage by other operators, which is expected to provide valuable geologic information and assist in de-risking this highly-prospective fairway.

At Elmworth, the Company holds a large undeveloped land base consisting of 84 (83.5 net) ‎sections (53,440 net acres) of operated acreage, with substantial resource potential. Future asset development of the Montney will be focused on extended reach horizontals with increased frac and proppant intensity. These technical improvements coupled with operational efficiencies in spud-to-on-stream cycle times, emulsion management and infrastructure optimization will provide the key to unlocking the vast potential of the Elmworth Montney fairway. 

For more information, please contact: 

RMP ENERGY INC. 

Rob Colcleugh    
Chief Executive Officer  
(403) 930-6333  
.(JavaScript must be enabled to view this email address) 

Dean Bernhard
Vice President, Finance and Chief Financial Officer
(403) 930-6304
.(JavaScript must be enabled to view this email address) 

Abbreviations

bbl or bbls barrel or barrels Mcf/d thousand cubic feet per day
Mbbl thousand barrels MMcf/d million cubic feet per day
bbls/d barrels per day MMcf Million cubic feet
boe barrels of oil equivalent Bcf billion cubic feet
Mboe thousand barrels of oil equivalent psi pounds per square inch
boe/d barrels of oil equivalent per day kPa kilopascals
NGLs natural gas liquids GJ Gigajoule
WTI West Texas Intermediate GJ/d Gigajoules per day

Reader Advisories

Within this news release, any references to test rates, IP30 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or ultimate recovery. IP30 is defined as an average production rate over thirty (30) producing cumulative days. Readers are cautioned not to place reliance on such rates in drawing conclusions on future corporate production or in calculating aggregate production for the Corporation. 

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 volume and product mix of the Company's oil and gas production; production estimates; the Company's planned capital expenditures program for the winter drilling season; the number of wells to be drilled, completed and tied in and the timing thereof; the methods of completion of the Company's wells; future liquidity and financial capacity; future results from operations; 2017 year-end forecasted liquidity and level of bank debt; and the resource potential of the Company's Elmworth assets.

With respect to forward-looking statements contained in this news release, RMP has made assumptions regarding, but not limited to: conditions in general economic and financial markets; effects of regulation by governmental agencies; current and future commodity prices and royalty regimes; future exchange rates; royalty rates; future operating costs; availability of skilled labor; availability of drilling and related equipment; timing and amount of capital expenditures; the impact of increasing competition; the price of crude oil and natural gas; that the Company will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Company's conduct and results of operations will be consistent with its expectations; available pipeline capacity; that the Company will have the ability to develop the Company's properties in the manner currently contemplated; that the Company will be able to drill, complete and tie-in wells in the manner and on the timing described herein; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated; and the estimates of the Company's production and reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects.

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; obtaining required approvals of regulatory authorities; unexpected drilling results; the Company is unable to achieve its objectives; that the anticipated resource potential in the Elmworth area is not achieved; changes in capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties, including hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; changes or fluctuations in production levels; delays in anticipated timing of drilling and completion of wells; lack of available capacity on pipelines; the lack of availability of qualified personnel; uncertainties associated with estimating oil and natural gas reserves; and ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties and additional risk factors are described in the Company's Annual Information Form which is available at www.sedar.com.

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.

The Company anticipates remaining disciplined but flexible with its winter drilling program and related capital expenditures as outlined herein as it monitors business conditions and commodity prices throughout the period.  Where deemed prudent, the Company may make adjustments to its planned capital program.  Actual spending may vary due to a variety of factors including, without limitation, drilling results, crude oil and natural gas prices, economic conditions, field services and equipment availability, and the impact of any strategic transactions.  The Company has flexibility to adjust the level of its planned capital expenditures as circumstances warrant. 

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.

This news release contains certain oil and gas metrics, including field operating netback (or operating netback) or net debt or funds from operations, which do not have standardized meanings or standard methods of calculation nor are recognized measures under International Financial Reporting Standards ("IFRS") and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. Field operating netback or operating netback refers to realized wellhead revenue less royalties, operating expenses and transportation costs per barrel of oil equivalent. The Company believes that this financial netback measure is useful supplemental information to analyze operating performance and provide an indication of the results generated by the Company's principal business activities. Investors should be cautioned that this measure should not be construed as an alternative to other measures of financial performance as determined in accordance with IFRS.  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. The Company's method of calculating net debt may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies.

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 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.  RMP believes this measure is widely used by shareholders and investors in the valuation, comparison and investment recommendations relating to RMP and its peer companies within the natural gas and crude oil exploration and production industry. As disclosed within this news release, funds from operations represents cash flow from operating activities before: 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.