RMP Energy Announces Intention of Share-Repurchase Program, Provides Elmworth Operations Update and Reports Third Quarter 2017 Results

November 14, 2017 3:35 PM

CALGARY, Alberta, Nov. 14, 2017 (GLOBE NEWSWIRE) — RMP Energy Inc. (the “Company”) (TSX:RMP) today announces its intention to commence a share-repurchase program, provides an Elmworth Montney operations update, and reports its financial and operating results for the third quarter of 2017. The Company is changing its corporate name to “Iron Bridge Resources Inc.“. The name change is expected to become effective later this month.The ticker symbol “IBR” has been reserved by the Toronto Stock Exchange (“TSX”) for the Company’s use following the name change becoming effective.

Share-Repurchase Program

The Company’s Board of Directors has authorized a share-repurchase program to be facilitated through a normal course issuer bid (the “NCIB”). The Company believes its share price does not always reflect the underlying intrinsic value of its Elmworth asset base and as such, the Company intends to apply to implement a NCIB through the facilities of the TSX and alternative Canadian trading platforms, pursuant to which the Company would have the ability to repurchase, from time-to-time, its outstanding shares for cancellation. This NCIB is expected to commence in due course following the acceptance of the Company’s notice of intention to commence a NCIB, and approval of such, by the TSX, and will terminate one year later or such earlier time as the NCIB is completed or terminated at the option of the Company. The Company will implement a restriction on the maximum aggregate value of shares to be purchased during the term of the NCIB of $7.5 million.

Elmworth Montney Update

For the month of October 2017, the Company produced approximately 2,100 boe/d on average from its Elmworth Montney asset, reflecting a 40% increase over the approximate 1,500 boe/d produced in the month of September 2017. Current production is approximately 2,100 boe/d (based on field estimates), with a light oil and NGLs weighting between 30% and 33%. The Company has recently commenced its winter drilling program at Elmworth. The first of five wells will spud this week. A total of five, 100% working interest wells are budgeted to be drilled this winter, encompassing: i) a brine disposal well; ii) two horizontal development wells; and, iii) two delineation, land-holding horizontal wells. The two development wells will be completed and tied into the Company’s Elmworth 2-23 Facility prior to ‘spring break-up’. Drilling of the two step-out delineation wells is scheduled for early-2018 and is expected to continue 41 sections of prospective acreage past its primary expiry date through to the year 2020. Completion operations on these two well bores is budgeted to be undertaken in the second half of the year.

The two development wells, to be drilled from the Company’s 2-23 Facility pad site, will each be approximately 2,400 meters (7,900 feet) in lateral length. The Company’s technical team plans to continue to optimize its completion technique and in this regard will be further decreasing the stage spacing and increasing the number of frac stages to approximately 80 on each of these two well bores. The Company anticipates an increase in well productivity from this completion change and potentially lower gas-to-oil ratios and reduced water-cuts. Completion operations on these two development wells are scheduled for January 2018.

The Company has significant financial flexibility and full funding capability to carry out its winter drilling capital expenditures budget of approximately $25 million and fund the aforementioned share-repurchase program. Exiting 2017, the Company is forecasting approximately $33 million of liquidity (positive working capital plus equity investment) and an undrawn credit facility of $5 million.

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. Asset development of the Montney formation will be focused on extended-reach horizontals with increased frac and proppant intensity. These technical enhancements, 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 Company’s Elmworth Montney asset.

Third Quarter 2017 Results Commentary

The Company’s reported third quarter 2017 results include operational and financial contribution from the recently divested Waskahigan, Grizzly, Kaybob, Gilby, Pine Creek fields, and other minor Alberta properties (the “Disposition Assets”). On September 1, 2017, the Company announced a definitive purchase and sale agreement for the disposition of these assets (the “Disposition”). Holders of common shares of the Company approved by overwhelming majority (over 99%) the Disposition at a special shareholders meeting held on October 13, 2017, in addition to approving a corporate name change to “Iron Bridge Resources Inc.”. The Disposition transaction closed on October 17, 2017. The Company recognizes the results of operations from the Disposition Assets up to the date of closing, when control transferred.

The Disposition, after closing, has resulted in the Company transforming to a geographically and geologically focused Montney producer at Elmworth in West Central Alberta. As such, the reported results for the three months ended September 30, 2017 are not indicative of the Company’s current nor go-forward operational and financial performance. The following commentary summarizes the Company’s third quarter 2017 results and provides certain forward-looking information relating to its Elmworth asset:

As a result of the strategic Disposition, the Company has bolstered its balance sheet with significant financial liquidity and the requisite capital resources with which to carry out the continued delineation and disciplined development of its core Elmworth Montney asset. The Company currently has approximately $33 million of cash on-deposit, a $9 million equity investment in shares of the purchaser of the Disposition Assets, and an undrawn $5 million credit facility.The Company estimates it will exit this current year with approximately $33 million of liquidity (positive working capital plus equity investment) and no bank debt outstanding.
Average daily production was 4,010 boe/d (weighted 31% crude oil and NGLs), which included approximately 2,600 boe/d of production from the Disposition Assets. The Company’s 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 (2.0 net) of the Company’s Elmworth drilled-wells produced concurrently during the third quarter due to gas compression capacity 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 three (3.0 net) of the Company’s Montney horizontal wells (3-22, 4-18 and 15-23). This oil battery 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 2,100 boe/d (based on field estimates).
Petroleum and natural gas (“P&NG”) revenue realization in the third quarter was impacted by significant weakness in AECO natural gas prices. AECO benchmark pricing was 41% lower than the preceding second quarter and 31% lower than the comparative third quarter of 2016. However, WTI oil prices were stable in comparison to the preceding second quarter and 7% higher than the comparative third quarter of 2016. Within this commodity price environment, the Company’s P&NG revenue amounted to $8.1 million in the third quarter (65% derived from crude oil and NGL sales). The Company’s realized crude oil sales price in the third quarter, from its Waskahigan, Grizzly and Elmworth oil sales, was $53.93/bbl, which reflects an oil quality discount to the Canadian-dollar converted WTI price of $6.47/bbl. At Elmworth, the Company’s realized oil sales price for its Montney light sweet crude product was approximately $56.78/bbl in the third quarter, reflecting an oil quality discount to the Canadian-dollar converted WTI price of $3.62/bbl.
P&NG royalties in the third quarter amounted to $799 thousand (10% of P&NG revenue excluding realized amounts on risk management contracts), as compared to royalties of $3.4 million (15% of P&NG revenue) for the comparative third quarter of 2016. At Elmworth, the Company’s field royalty rate was approximately 4% in the third quarter. For 2018, the Company is expecting a corporate royalty rate of between 7% and 8%, based on forecasted commodity prices and anticipated productivity of its Elmworth Montney wells. The Alberta Government’s Modernized Royalty Framework is expected to have a significant, positive impact on the well economics of the Company’s Elmworth Montney drilling inventory.
Field operating costs on an oil equivalent basis were $13.25/boe in the third quarter. A higher level of well workovers, pump replacement activity and compressor maintenance at Waskahigan and Kaybob, in addition to prior period third-party gas plant adjustments at Kaybob, resulted in higher per-unit operating costs in comparison to the preceding second quarter of 2017, wherein limited workover activity is conducted due to challenging ‘spring break-up’ surface conditions. Field operating costs at Elmworth were approximately $8.50/boe in the third quarter of 2017. Per-unit operating expenses at Elmworth for 2018 are expected to decrease and approximate $7.00/boe, reflecting the concentrated and operated nature of this asset, anticipated production growth and ongoing field optimization at Elmworth.
Per-unit transportation costs were $6.03/boe in the third quarter of 2017. On July 1, 2017, upon the completion and in-service of the Pembina Peace Pipeline Phase III expansion, the Company’s contracted firm service oil transportation volumes increased. The associated ‘take-or-pay’ charges resulted in higher per-unit transportation costs in the third quarter. However, in conjunction with the aforementioned Disposition, a significant portion of these commitments were permanently assigned to the purchaser at closing of the Disposition, thus mitigating the go-forward financial obligations for the Company. Per-unit transportation costs at Elmworth for 2018 is expected to approximate $5.00/boe, which primarily will relate to pipeline tolls on the Pembina Peace Pipeline and Alliance Pipeline Systems in addition to trucking charges of its NGLs to a sales terminal.
Third quarter 2017 general and administrative expenses (“G&A”) of $3.3 million include approximately $2.0 million of costs incurred in connection with the Company’s executive management restructuring undertaken on August 1, 2017, including related retiring allowances and financial advisory and legal fees associated with the restructuring. For 2018, the Company is estimating G&A expenses to average approximately $1.0 million per quarter, representing a 20% to 25% decrease from historical levels (adjusted for non-recurring G&A items as discussed), and reflecting cost optimization measures already undertaken or those expected to be undertaken in due course.
In the third quarter of 2017, the Company invested approximately $7.8 million in capital expenditures. Drilling and completion costs were $4.1 million, primarily relating to one (1.0 net) Elmworth Montney horizontal well drilled and completed in the quarter (the 15-23 well). Field facilities and well equipment costs were $2.8 million, primarily pertaining to residual construction costs of the Elmworth 2-23 Facility and additional expansion costs of such for increased compression and inlet separation, in addition to the tie-in of the Elmworth 15-23 well. The Company spent $0.8 million on Montney land investment in the third quarter at Elmworth.

Please refer to the Company’s interim condensed consolidated financial statements and the Management’s Discussion and Analysis for the three months ended September 30, 2017 for detailed financial and operational results. These documents are available on RMP’s website at www.rmpenergyinc.com within “Investors” under “Financials”. Additionally, these documents will be filed later today on the System for Electronic Document Analysis and Retrieval (“SEDAR”). After such filing, 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.

[expand title=”Advisories & Contact”]

For more information, please contact:
RMP ENERGY INC.

Rob Colcleugh
Chief Executive Officer
(403) 930-6333
rob.colcleugh@rmpenergyinc.com

Dean Bernhard
Vice President, Finance and Chief Financial Officer
(403) 930-6304
dean.bernhard@rmpenergyinc.com

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; drilling and completion plans, methodology, the timing thereof and the expectation to potentially lower gas-to-oil ratios and reduced water-cuts; future liquidity estimates and financial capacity; the anticipated impact of the Alberta government’s Modernized Royalty Framework and the resource potential of the Company’s Elmworth assets; the 2018 estimates for corporate G&A and its Elmworth field’s royalty rates, operating expenses and transportation costs; the Company’s anticipated winter drilling program; and the Company’s intention to apply to the Toronto Stock Exchange to implement a normal course issuer bid and the timing thereof.

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.

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.

[/expand]

RMP Energy Announces Intention of Share-Repurchase Program, Provides Elmworth Operations Update and Reports Third Quarter 2017 Results

Latest Headlines