CALGARY, ALBERTA–(Marketwired – March 21, 2017) – RMP Energy Inc. (“RMP” or the “Company“) (TSX:RMP) is pleased to provide an update on its first quarter 2017 field operations and to announce its year-end independent reserves evaluation in addition to its financial results for the fourth quarter and fiscal year ended December 31, 2016.
Waskahigan Montney, West Central Alberta
At Waskahigan in the first quarter of 2017, RMP successfully drilled and completed a 100% working interest Montney ‘step-out’ horizontal oil well (13- 30 -63-23W5), located on the western flank of the Company’s acreage position. The flow test result from the recently completed hybrid slick-water operation was strong. Production flow testing was for a 200-hour period (approximately 8 days). Over the last 72 hours of the production test, the 13-30 well tested at an average rate of approximately 760 bbls/d of 40-degree API crude oil and 1.5 MMcf/d of associated sweet solution gas for an oil-equivalent rate of approximately 1,000 boe/d. RMP expects to have the 13-30 well tied into company-owned infrastructure and placed on-production later this week. The Company expects to book and assign proved developed reserves to this well and recognize proved undeveloped and probable undeveloped reserves for future locations offsetting the 13-30 well, none of which were booked or assigned in the year-end 2016 independent reserves report.
At Waskahigan, the Company’s hybrid slick-water completions have resulted in improved well productivity, and corresponding improvement in well project economics. In addition to the 13-30 well, the Company is budgeted to drill three more (3.0 net) Montney horizontal wells at Waskahigan this year. In the first quarter of 2017, the Company increased its acreage position by five (5.0 net) sections (3,200 gross acres), and its land base at Waskahigan now consists of 78.5 (77.6 net) sections (50,240 gross acres) of operated acreage. RMP estimates its future Waskahigan drilling inventory to consist of approximately 200 potential unbooked and undeveloped drilling locations (of which only 47 locations have assigned proved and/or probable reserves in the Company’s year-end 2016 independent reserves report).
Elmworth (Gold Creek) Montney, West Central Alberta
At Elmworth (formerly known as Gold Creek) during the first quarter of 2017, the Company commenced the strategic delineation of the areal extent of the hydrocarbon-bearing Middle Montney reservoir oil window.
As follow-up to last year’s successful exploration well (3-22-68-3W6), RMP drilled two more wells at Elmworth. A 100% working interest, exploration well (8-25-68-4W6) was drilled and completed with hybrid slick-water, approximately one township to the west of the Company’s 3-22 well. The 8-25 well production test results were successful, with flow-back results indicating the discovery of a new oil pool and demonstrating the Middle Montney reservoir to be oil bearing and gas charged. The 8-25 well was drilled to a total measured depth of 4,523 metres, with 2,208 metres of horizontal section. The production flow test was for a 173-hour period (approximately seven days). Over the last 72 hours of the production test, the 8-25 well tested at an average rate of approximately 220 bbls/d of 45-degree API crude oil and approximately 1.0 MMcf/d of natural gas, resulting in an oil-equivalent rate of approximately 390 boe/d. Please refer to Reader Advisories at the end of this news release.
The Company also successfully drilled and completed its third, 100% working interest well in the Middle Montney oil window at Elmworth (4-18-68-2W6). Drilled from the same surface lease pad as the 3-22 well, the 4-18 well is a ‘step-out’ to the southeast. The 4-18 delineation well, drilled to a total measured depth of 4,935 metres with 2,518 metres of horizontal length, was fracture stimulated with hybrid slick-water. The production flow test was for a 165-hour period (approximately seven days). Over the last 72 hours of the production test, the 4-18 well tested at an average rate of approximately 200 bbls/d of 45-degree API crude oil and 2.3 MMcf/d of natural gas, resulting in an oil-equivalent rate of approximately 600 boe/d. Please refer to Reader Advisories at the end of this news release.
In addition to delineation drilling of its Montney acreage, RMP also secured strategic infrastructure in the Elmworth area for hydrocarbon egress. As previously disclosed, the Company has entered into gathering, processing and transportation agreements with a regional mid-stream service provider to handle RMP’s Elmworth crude oil and natural gas production. The agreements encompass an area dedication and are not subject to take-or-pay commitments. The mid-stream company is in the process of installing a gathering system in order to connect their existing infrastructure to RMP’s oil battery facility located at 2-23-68-3W6, which is presently undergoing construction. The Company’s Elmworth natural gas will be processed at the mid-stream company’s Patterson Creek Gas Plant, which will undergo expansion later this year with an expected capacity level of 150 MMcf/d. This gas plant will provide pipeline connections for sales gas into both the TransCanada and Alliance gas systems. Oil volumes will be transported downstream of the gas plant with connectivity to a Pembina crude oil sales terminal. Barring any unforeseen delays, the gathering pipeline and oil battery facility is scheduled to be commissioned and operational in May 2017.
At Elmworth, RMP has now successfully drilled and completed three (3.0 net) Middle Montney horizontal wells. The Company has a large undeveloped land base consisting of 79 (78.5 net) sections (50,560 gross acres) of operated acreage. RMP estimates that it has potentially in excess of 300 unbooked and undeveloped drilling locations at Elmworth (of which only six locations have assigned proved and/or probable reserves in the Company’s year-end 2016 independent reserves report). With drilling and completion results to-date, and continued exploration and development activity, Elmworth has the potential to be a long-term production and reserves growth asset for RMP.
Updated Market Guidance and 2017 Capital Budget
For 2017, the Company is budgeting to incur $49 million in exploration and development capital expenditures. In addition to key infrastructure investment at Elmworth, the 2017 capital plan includes the drilling of three (3.0 net) Middle Montney horizontal wells at Elmworth, of which two have been drilled already, and four (4.0 net) Montney horizontal wells at Waskahigan, of which one has been drilled to-date. The focus of the capital budget for the first half of this year is to maintain corporate base production levels through a pared-back level of drilling operations at Waskahigan while de-risking and delineating its large Elmworth resource potential with the strategic objective of establishing additional inventory and scale for the Company. Infrastructure commissioning at Elmworth is expected to bolster RMP’s base production levels thereafter, providing production momentum for the second half of this year and into fiscal 2018. For the second half of this year, the Company is forecasting production to average approximately 4,500 boe/d (weighted 42% light crude oil and NGLs).
YEAR-END 2016 RESERVES
The following provides information on RMP’s crude oil, natural gas and NGLs reserves as of December 31, 2016, as evaluated by the Company’s independent qualified reserves evaluators, InSite Petroleum Consultants Ltd. (“InSite“). The evaluation of RMP’s reserves was prepared in accordance with the definitions, standards and procedures prescribed in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101“) and the Canadian Oil and Gas Evaluation Handbook. Unless stated otherwise, all reserves referred to in this news release are stated on a company gross basis (working interest before deduction of royalties and without including any royalty interests). The reported reserves at December 31, 2016 exclude reserves that were disposed of in connection with the sale of the Company’s Ante Creek asset (the “Ante Creek Disposition“), which closed on November 15, 2016. The Company’s year-end 2016 reserves highlights include the following:
- Total proved plus probable reserves at December 31, 2016 were 27.7 million boe. The Ante Creek Disposition (9.8 million boe), fiscal 2016 production (2.9 million boe) and a minor Pine Creek divestiture (1.2 million boe), partially offset by positive additions (net of revisions) of 3.1 million boe, resulted in lower reserves reported at year-end 2016 as compared to 38.5 million boe of proved plus probable reserves at December 31, 2015. Adjusting for production and the reserves disposed with the Ante Creek Disposition, total proved plus probable reserves increased year-over-year.
- Total proved reserves at December 31, 2016 were 16.4 million boe. The Ante Creek Disposition (6.6 million boe), fiscal 2016 production (2.9 million boe) and a minor Pine Creek divestiture (0.7 million boe), partially offset by positive additions (net of revisions) of 1.2 million boe, resulted in lower reserves reported at year-end 2016 as compared to 25.3 million boe of proved reserves at December 31, 2015. Adjusting for production and the reserves disposed with the Ante Creek Disposition, total proved reserves increased year-over-year.
- Total proved developed producing reserves at December 31, 2016 were 6.8 million boe, as compared to 15.1 million boe at December 31, 2015. The Ante Creek Disposition (6.2 million boe), a minor Pine Creek divestiture (0.1 million boe) and fiscal 2016 production (2.9 million boe) were partially offset by positive additions (net revisions) of approximately 1.0 million boe. Adjusting for production and the reserves disposed with the Ante Creek Disposition, total proved developed producing reserves increased year-over-year.
- RMP’s net asset value at December 31, 2016 is estimated at $2.19 per share (discounted at 10%). Refer to the detailed calculation under the Net Asset Value heading hereafter.
- Booked and assigned initial reserves at Elmworth (formerly Gold Creek) at December 31, 2016, of 4.7 million boe proved plus probable and 1.5 million boe proved.
- Achieved finding and development (“F&D“) costs of $18.45 per proved plus probable boe, including changes in future development capital (“FDC“). Refer to the detailed calculation under the Capital Expenditures Efficiency heading hereafter.
Corporate Reserves Information
|December 31, 2016 Reserves Summary (1) (company gross reserves)|
|Natural Gas (2)||Oil (3)||NGLs||Oil Equivalent|
|(Columns may not add due to rounding)||(Bcf)||(Mbbls)||(Mbbls)||(Mboe) (6:1)|
|Proved developed producing||28.438||1,590.7||474.3||6,804.6|
|Proved developed non-producing||3.298||202.1||47.6||799.3|
|Total Proved plus Probable||107.705||8,326.9||1,423.8||27,701.4|
|(1) Estimated using InSite’s forecast prices and costs as of December 31, 2016.|
|(2) Includes conventional natural gas and shale gas.|
|(3) Substantially all tight oil.|
|December 31, 2016 Net Present Value Summary (1) (company gross reserves)|
|(Columns may not add due to rounding)|
|Proved developed producing||$ 110,932||$ 90,689||$ 77,226||$ 67,625||$ 60,452|
|Total Proved plus Probable||$ 420,729||$ 286,513||$ 204,684||$ 151,085||$ 114,172|
|(1) Net present values reported are before taxes based on InSite’s forecast prices and costs as of December 31, 2016. No provision for bank debt interest and general and administrative expenses have been made within the net present values.|
A summary of InSite’s escalated price forecast assumptions as of December 31, 2016 are as follows:
|Edm Par Price|
|YEAR||WTI @ Cushing||40 API||AECO-C||Propane||Butane||Condensate||Exchange Rate||Inflation Rate|
Net Asset Value
The Company’s net asset value details, as of December 31, 2016, are as follows:
|(columns may not add due to rounding)||NPV 10%||NPV 15%|
|(per share figures based on basic outstanding shares)||($000s)||$/share||($000s)||$/share|
|Proved plus probable reserves NPV (1,2)||$ 204,684||$ 1.36||$ 151,085||$ 1.00|
|Undeveloped acreage (3)||126,634||0.84||126,634||0.84|
|Net debt (4)||(885)||(0.01)||(885)||(0.01)|
|Net Asset Value||$ 330,433||$ 2.19||$ 276,835||$ 1.83|
|(1) Evaluated by InSite as at December 31, 2016. Net present values do not represent fair market value of the reserves.|
|(2) Net present values (“NPV“) reported are before taxes based on InSite’s forecast prices and costs as of December 31, 2016. No provision for bank debt interest and general and administrative expenses have been made within the net present values.|
|(3) Independently-evaluated with average acreage value of $890 per net acre. Reflects an independent third-party estimate of the fair market value of RMP’s undeveloped acreage based on past Crown land sale activity, adjusted for tenure and other considerations.|
|(4) Working capital deficit net of deferred charge asset at December 31, 2016 (unaudited).|
|(5) Shares outstanding at December 31, 2016 total 150.97 million.|
Capital Expenditures Efficiency
The following table provides an overview of RMP’s finding and development (“F&D“) costs for fiscal 2016. Generally the calculation of both F&D costs and finding, development and acquisition (“FD&A“) costs includes incorporating changes in future development capital (“FDC“) required to bring the proved undeveloped and probable undeveloped reserves on-production. Changes in forecasted FDC occur annually due to capital development activities, acquisition and/or disposition activities, undeveloped reserve revisions and capital cost estimates that reflect the independent reserves evaluators best estimate of what it will cost to bring the proved undeveloped and probable undeveloped reserves on-production. For fiscal 2016, the Company cannot calculate its FD&A costs, including changes in FDC, as the impact of the Ante Creek Disposition and the change in FDC more than offsets 2016 exploration and development expenditures. The Company, however, has calculated its F&D costs for its exploration and development capital expenditures, exclusive of its net acquisition/disposition activities.
|(amounts in $000s except reserve units and unit costs)||Proved||Proved + Probable|
|Exploration and development expenditures (1,2,3)||30,229||30,229|
|Acquisitions / (dispositions), net (1,2)||(89,426)||(89,426)|
|Total capital expenditures||(59,197)||(59,197)|
|Change in future development capital (“FDC”): (1)|
|Exploration and development||12,588||23,432|
|Acquisitions / (dispositions), net||(19,352)||(30,595)|
|Aggregate F&D, including change in FDC (4)||42,817||53,661|
|Aggregate FD&A, including change in FDC (4)||(65,961)||(66,360)|
|Reserve additions (Mboe):|
|Exploration and development||1,091||2,909|
|Acquisitions / (dispositions), net||(7,108)||(10,854)|
|F&D Costs ($/boe)(4)||$ 39.25||$ 18.45|
|FD&A Costs ($/boe) (4,5)||N/A||N/A|
|(1) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total F&D costs related to reserves additions for that year.|
|(2) Capital incurred during 2016 at Ante Creek before the disposition ($10.5 million) has been included in “Acquisitions / (dispositions), net”.|
|(3) Fiscal 2016 capital expenditures are unaudited and exclude non-cash capitalized share-based compensation expense of $1.5 million.|
|(4) Calculation includes changes in FDC.|
|(5) Due to the impact on reserves and FDC related to the Ante Creek Disposition, FD&A costs are deemed non-applicable (“N/A”).|
The following outlines F&D costs for the prior year of 2015, in addition to the average over the three-year period of 2014 to 2016, inclusive.
|Fiscal 2015||Three Year Average|
|(amounts in $000s except reserve units and unit costs)||Proved||Proved + Probable||Proved||Proved + Probable|
|Total exploration and development expenditures (1,4)||97,003||97,003||314,337||314,337|
|Future development capital – ending period (2)||158,290||286,124||151,526||278,961|
|Less: Future development capital – beginning period (2)||(177,625)||(359,675)||(141,488)||(264,269)|
|Aggregate F&D, including change in FDC (4)||77,668||23,452||324,374||329,029|
|Total reserve additions (Mboe)||4,047.5||952.2||15,291.4||15,985.9|
|F&D Costs ($/boe)(3)||$ 19.19||$ 24.63||$ 21.21||$ 20.58|
|(1) Excludes non-cash capitalized share-based compensation expense.|
|(2) FDC expenditures required to convert proved non-producing reserves and probable reserves to proved producing.|
|(3) Calculation includes changes in FDC.|
|(4) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total F&D costs related to reserves additions for that year.|
Future Development Capital
The following table outlines the FDC required to bring proved undeveloped and probable undeveloped reserves on-production. The FDC has been deducted in the estimation of future net revenue attributable to total proved reserves and total proved plus probable reserves (using forecast prices and costs).
|Future Development Capital (1)|
|(amounts in $000s)||Total Proved||Total Proved + Probable|
|2017||$ 46,640||$ 63,490|
|Total undiscounted FDC||$ 151,525||$ 278,961|
|Total discounted FDC at 10% per year||$ 126,365||$ 226,418|
|(1) FDC as per InSite’s independent reserves evaluation as of December 31, 2016 and based on InSite’s forecast pricing as at December 31, 2016.|
The Company expects to fund its FDC requirements from internally-generated cash flow from operations and, as appropriate, from its existing committed bank credit facility, equity or debt financing. It is anticipated that the costs of funding the FDC will not impact development of RMP’s properties or the Company’s reserves or future net revenue.
For the year ended December 31, 2016, RMP reported funds from operations of $29.6 million ($0.20 per fully-diluted share) on revenue of $77.3 million and average daily production of 7,895 barrels of oil equivalent (42% light oil and NGLs weighted). Detailed results are as follows:
|Financial Results||Three Months Ended||Twelve Months Ended|
|(thousands except share and per boe data) (6:1 oil equivalent conversion)||Dec. 31, 2016||Dec. 31, 2015||% change||Year 2016||Year 2015||% change|
|P&NG revenue (1)||13,371||34,178||(61)||77,322||161,633||(52)|
|Funds from operations (2)||3,373||18,725||(82)||29,584||92,452||(68)|
|Per share – basic / diluted||0.02||0.15||(87)||0.20||0.75||(73)|
|Per share – basic / diluted||(0.43)||(0.26)||65||(0.59)||(0.69)||(14)|
|Total capital expenditures||(103,076)||12,008||–||(59,197)||97,003||–|
|Net debt (3) – period end||885||117,956||(99)||885||117,956||(99)|
|Weighted average basic shares||150,970,068||124,790,535||21||145,415,191||123,220,485||18|
|Weighted average diluted shares||150,970,068||124,790,535||21||145,415,191||123,220,485||18|
|Issued and outstanding shares (4)||150,970,068||126,475,068||19||150,970,068||126,475,068||19|
|Average daily production:|
|Natural gas (Mcf/d)||17,110||36,352||(53)||27,599||38,606||(29)|
|Crude oil (bbls/d)||1,500||4,952||(70)||2,983||5,318||(44)|
|Oil equivalent (boe/d)||4,652||11,257||(59)||7,895||12,026||(34)|
|Average sales price (1):|
|Natural gas ($/Mcf)||2.79||3.26||(14)||2.22||3.32||(33)|
|Crude oil ($/bbl)||58.75||50.13||17||47.80||57.86||(17)|
|Oil equivalent ($/boe)||31.24||33.00||(5)||26.76||36.82||(27)|
|Operating expenses ($/boe)||9.67||4.61||110||5.92||4.90||21|
|Operating netback (5) ($/boe)||13.88||20.95||(34)||13.71||23.65||(42)|
|Wells drilled: gross (net)||–||2 (2.0)||–||8 (8.0)||15 (15.0)||(47)|
|(1)||Petroleum and natural gas (“P&NG“) revenue and pricing includes realized gains or losses from risk management commodity contract settlements.|
|(2)||Funds from operations does not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS“). Please refer to the Reader Advisories at the end of the news release.|
|(3)||Net debt is not a recognized measure under IFRS. Please refer to the Reader Advisories at the end of the news release.|
|(4)||As of March 20, 2017, 151.0 million common shares were outstanding.|
|(5)||Operating netback is not a recognized measure under IFRS. Please refer to the Reader Advisories at the end of the news release.|
Fourth Quarter 2016 Highlights
- In connection with the Company’s strategic initiatives review undertaken last year, RMP completed the transformational disposition of its crude oil and natural gas interests in the Ante Creek area of West Central Alberta for net cash proceeds of $109.2 million, after normal and customary closing adjustments (the “Ante Creek Disposition“). The assets sold in the Ante Creek Disposition, which closed mid-fourth quarter on November 15, 2016, included reserves, land acreage, infrastructure facility and pipeline interests. Net disposition proceeds were used to eliminate the Company’s outstanding bank indebtedness. The Ante Creek Disposition resulted in the recognition of a gain on disposition of $35.5 million.
- Fourth quarter 2016 production averaged 4,652 boe/d (weighted 39% light oil and NGLs), lower from the preceding third quarter production due to the intra-quarter Ante Creek Disposition on November 15, 2016 and the Pembina and Alliance sales pipeline service outages in early-October 2016 (as previously disclosed). RMP’s fiscal 2016 average daily production was 7,895 boe/d, comprised of crude oil and NGLs production of 3,295 bbls/d and natural gas output of 27.6 MMcf/d
- Fourth quarter petroleum and natural gas revenue amounted to $13.4 million (including a realized hedging loss of $1.1 million). Approximately 67% of the Company’s revenue was derived from crude oil and NGLs sales. Petroleum and natural gas revenue for fiscal 2016 amounted to approximately $77.3 million (including a realized hedging loss of $1.2 million).
- Fourth quarter petroleum and natural gas royalties amounted to $1.7 million (12% of petroleum and natural gas sales excluding realized hedging results), as compared to $3.4 million (15% of petroleum and natural gas sales) in the third quarter of 2016.
- Fourth quarter field operating costs on an oil-equivalent per unit basis were $9.67/boe, as compared to the preceding third quarter 2016 per-unit expense of $5.58/boe. In the fourth quarter, battery facility ‘turnaround’ maintenance activity conducted during the aforementioned sales pipelines service outages affected per-unit costs by approximately $1/boe. Additionally, the Ante Creek Disposition resulted in the Company’s reported per-unit operating costs to increase, since the Ante Creek field had a lower per-unit operating cost profile than RMP’s other producing assets as a whole. RMP continues to be highly-focused on delivering meaningful operating cost reductions and efficiency gains across its field operations.
- Fourth quarter transportation costs were $3.64/boe on an oil-equivalent basis, which reflects oil sales pipeline tariffs, gas sales pipeline firm service tolls, and pipeline fuel surcharges. This compares to the $3.51/boe of reported per-unit transportation cost for the preceding third quarter of 2016.
- Fourth quarter general and administrative (“G&A“) expenses amounted to $2.2 million, as compared to $1.6 million in the preceding third quarter of 2016. As a result of year-end G&A activities associated with the independent reserves report and the fiscal financial statement audit, fourth quarter 2016 gross G&A costs were $835 thousand higher than the preceding third quarter. Personnel retention costs in connection with the corporate strategic review process undertaken in 2016 also contributed to the quarter-over-quarter increase. RMP continues to maintain an efficient organizational structure and presently employs 19 head office personnel and engages the services of two consultants on a part-time basis. For 2017 the Company’s personnel have taken a 10% salary decrease, in addition to the 10% compensation reduction put in-place last year.
- In fiscal 2016, the Company incurred approximately $40 million on its 2016 exploration and development program. RMP undertook a light oil-focused exploration and development capital program in 2016, albeit to a lesser scale due to a pared-back capital expenditures budget reduced in response to lower commodity prices. In 2016, a total of eight (8.0 net) Montney horizontal crude oil wells were drilled, as compared to a drilling program in fiscal 2015 of 15 (15.0 net) horizontal wells. RMP’s 2016 drilling program encompassed four (4.0 net) wells at Waskahigan, three (3.0 net) wells at Ante Creek and one (1.0 net) exploration well in Elmworth (formerly known as Gold Creek). The Company also completed an asset acquisition at Elmworth in June 2016 for $10 million.
- At year-end 2016, RMP was not drawn on its bank credit facility. The Company is presently drawn approximately $7 million on its bank line of credit, with a current debt-servicing rate of 3.4% (per annum). The Company’s bank credit facility has a maximum borrowing base limit of $40.0 million and the lender’s annual borrowing base re-determination is scheduled to occur in June 2017. RMP’s working capital deficit at December 31, 2016 was $885 thousand.
- Fourth quarter funds from operations was $3.4 million ($0.02 per basic share). Funds from operations for fiscal 2016 was approximately $30 million ($0.20 per basic share). The Company’s fourth quarter 2016 operating netback was $13.88/boe. For fiscal 2016, RMP’s realized operating netback was $13.71/boe.
- For the year ended December 31, 2016, RMP reported a net loss of $86.0 million, as compared to a net loss of $84.8 million in fiscal 2015. The Company’s earnings in fiscal 2016 was impacted by the non-cash impairment charge on the carrying value of its property, plant and equipment of approximately $80 million, net of the gain on the Ante Creek Disposition. The non-cash impairment charge primarily related to RMP’s Greater Waskahigan Cash Generating Unit (“CGU“), which prior to the Ante Creek Disposition included the Waskahigan, Ante Creek and Grizzly Montney fields. As a result of the transformational Ante Creek Disposition, the Ante Creek field was removed from this CGU, which resulted in the CGU to be assessed for indicators of impairment and subsequent recognition of such.
The Company’s audited consolidated financial statements and associated Management’s Discussion and Analysis for the year ended December 31, 2016 is available on RMP’s website at www.rmpenergyinc.com within “Investors” under “Financials”. Additionally, these documents have been filed today on the System for Electronic Document Analysis and Retrieval (“SEDAR“). These documents can be retrieved electronically from the SEDAR system by accessing RMP’s public filings under “Search for Public Company Documents” within the “Search Database” module at www.sedar.com.
ANNUAL SHAREHOLDERS MEETING
RMP’s annual meeting of shareholders is scheduled for 3:00 p.m. on Tuesday, June 6, 2017 in the McMurray Room of the Calgary Petroleum Club, located at 319 – 5th Avenue S.W., Calgary, Alberta.