RMP Energy Reports Third Quarter Financial Results

CALGARY, ALBERTA--(Marketwired - Nov. 12, 2015) - RMP Energy Inc. ("RMP" or the "Company") (TSX:RMP) is pleased to report for the three months ended September 30, 2015 funds from operations of $17.0 million ($0.14 per basic share) on realized revenue of $35.9 million and average daily production of 11,000 barrels of oil equivalent, weighted 47% light oil and NGLs. Third quarter and nine month results are as follows:

Third Quarter Financial and Operational Highlights

• RMP's average daily production was 11,000 boe/d (weighted 45% light oil and 2% NGLs). The Company's third quarter production was impacted by: i) a shutdown of the Alliance pipeline system on August 7, 2015, resulting in the shut-in of substantially all of RMP's production for approximately one week; ii) a mechanical disruption at the Company's Waskahigan oil battery for a seven day period in early-July; iii) and ongoing third-party gas transportation restrictions causing material, uneconomic gas pricing which resulted in RMP deliberately shutting-in its Kaybob Montney field for the better part of the third quarter. The Kaybob field is expected to resume production upon improved realized gas pricing resulting from increased pipeline capacity on the TCPL gas system. For fiscal 2015, the Company is maintaining its previously-announced, annual production guidance target of approximately 12,000 boe/d (weighted 45% oil and NGLs).
  
  
• Petroleum and natural gas revenue in the third quarter amounted to $35.9 million, including a realized natural gas hedging gain of $861 thousand. Lower commodity prices and restricted production levels contributed to a decrease in realized revenue as compared to the comparative third quarter of 2014 and previous quarters in 2015. RMP's crude oil wellhead discount to the Canadian-dollar converted WTI price averaged $7.83/bbl during the third quarter, as compared to $6.42/bbl in the preceding second quarter of 2015 and $12.21/bbl in the comparative third quarter of 2014. RMP's natural gas revenue is partially protected from gas price weakness through fixed swap hedges with 20,000 GJs/d fixed at an AECO price of $3.22/GJ ($3.40/Mcf) for the month of October 2015. For the months of November and December 2015, 10,000 GJs/d of natural gas are fixed at an AECO price of $3.70/GJ ($3.90/Mcf).
  
  
• Petroleum and natural gas royalties amounted to $5.7 million (16% of petroleum and natural gas sales, excluding a realized gain on risk management commodity contracts), as compared to $16.1 million (21% of petroleum and natural gas sales) in the comparative third quarter of 2014.
  
  
• Controllable cash costs (operating, G&A and bank interest) were $8.13/boe in the third quarter. Third quarter per-unit operating costs of $5.60/boe were equivalent to the operating costs realized for the comparative third quarter 2014 period. RMP's corporate overhead general and administrative expenses ("G&A") continue to be optimized. For the third quarter of 2015, G&A expenses were $1.6 million ($1.62/boe), as compared to $1.8 million ($1.46/boe) in the preceding second quarter of 2015. The Company's reported, non-controllable transportation costs increased to $4.85/boe in the third quarter, as compared to $3.43/boe in the preceding second quarter 2015. Ongoing third-party gas pipeline maintenance activities caused capacity restrictions which widened the gas price differential in the third quarter, resulting in higher gas transportation costs on a portion of RMP's Waskahigan and Ante Creek sales gas. These gas pipeline restrictions will be mitigated when the Company's new, three-year firm transportation receipt service on the Alliance pipeline system takes effect on December 1, 2015. Longer term, RMP has committed to expansion of takeaway capacity on the TCPL system commencing November 1, 2018.
  
  
• Third quarter funds from operations of $17.0 million ($0.14 per basic share) was lower than previous quarters in 2015 due to lower commodity prices, restricted production levels and previously-discussed higher transportation costs. Notwithstanding, the Company realized a relatively strong field operating netback of $19.34/boe in the third quarter of 2015.
  
  
• Incurred approximately $28.0 million of capital expenditures in the third quarter. The Company successfully drilled and completed six horizontal Montney wells: three (3.0 net) at Ante Creek and three (3.0 net) at Waskahigan. Additionally, at the end of September, the Company rig released a Waskahigan offset well (13-29-63-23W5), which was successfully completed with hybrid slick water at the end of October. The first two Waskahigan wells drilled in the third quarter (7-15 and 13-11-64-23W5) offset the previously-drilled 2-15-64-23W5 horizontal well and were fracture stimulated with hybrid slick water. Both of these wells were brought on-stream in early-October. The third Waskahigan horizontal well (4-7-64-23W5) drilled and completed in the third quarter was drilled to delineate RMP's north-west land holdings. This well was completed with hybrid slick water and was brought on-production in late-October 2015. The three Ante Creek wells drilled and completed in the third quarter were located in the north-west corner of the Company's legacy six section land block and were brought on-stream late-August to early-September 2015. Well production performance has been tracking RMP's expected oil rates from wells drilled into that areal part of the Ante Creek Montney reservoir. Third quarter 2015 drilling and completion costs for the aforementioned Ante Creek and Waskahigan horizontal wells averaged approximately $2.7 million and $4.1 million, respectively. These costs reflect a reduction in average per-well drilling and completion costs of approximately 30% year-over-year, reflecting both service cost reductions and improved efficiencies resulting in shorter drill times.
  
  
• In the third quarter, the Company accumulated an additional ten net sections of undeveloped land with Montney potential outside of RMP's main light oil fairway. As a result, a total of 46 net sections have now been acquired for an average cost of less than $300 per hectare.
  
  
• During the third quarter, engineering, design and simulation work continued on the Company's planned secondary recovery water flood project at Ante Creek. Reservoir simulation and associated modeling is now complete. Waterflood performance predictions for the Montney formation, based on the analysis of the simulation and modelling work, is quite favorable with significant improvement in ultimate oil recovery over primary recovery expected. RMP will drill a horizontal producer at Ante Creek by the end of this year with plans to convert the well into a pilot injector and commence waterflood injection by the end of the second quarter of 2016, pending requisite regulatory approval.
  
  
• RMP's balance sheet at September 30, 2015 continues to be strong with net debt of approximately $129.7 million. The Company currently has a revolving bank credit facility with a borrowing base of $175 million. As of November 11, 2015, RMP was drawn approximately $130 million on the bank facility. The next borrowing base review by the Company's banking syndicate is scheduled to be completed by early-December 2015.
  
  
• RMP recorded a net loss of $45.3 million in the third quarter of 2015, as compared to net income of $18.2 million in the comparative third quarter of 2014. The Company recorded an aggregate non-cash impairment charge to the carrying value of its property, plant and equipment assets of $51.5 million, which is directly attributable to significantly lower future commodity prices forecasted by RMP's external reserve evaluators. The impairment charges had no impact on the Company's cash flow.
  
  
• RMP's low-cost structure, infrastructure control, strong balance sheet, high-quality economic asset base and experienced Management team and Board of Directors, positions the Company favourably to sustain and navigate the prevailing uncertain commodity price environment and to take advantage of the opportunities the current environment creates.
  
  

RMP's interim condensed consolidated financial statements and associated Management's Discussion and Analysis for the three and nine months ended September 30, 2015 are available on RMP's website at www.rmpenergyinc.com within "Investors" under "Financials". Additionally, these documents were 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.

Abbreviations

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.

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: forecasted average daily production rate and oil and liquids weighting for fiscal 2015; the expected resumption of production from Kaybob; the timing of implementation of a pilot project for RMP's secondary recovery project at Ante Creek; the timing of another Ante Creek well and the planned conversion to a water injector; the expected increase in oil reserves recovery from the secondary recovery waterflood project; and the Company's firm transportation on Alliance as well as the contract for firm transportation service on the TCPL system. 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.

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.

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, 2014 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.