RMP Energy Inc.
TSX : RMP

RMP Energy Inc.

August 15, 2016 17:30 ET

RMP Energy Reports Second Quarter 2016 Financial Results

CALGARY, ALBERTA--(Marketwired - Aug. 15, 2016) - RMP Energy Inc. ("RMP" or the "Company") (TSX:RMP) today announces for the three months ended June 30, 2016 funds from operations of $7.4 million ($0.05 per basic share) on revenue of $20.3 million and average daily production of 8,425 barrels of oil equivalent. Detailed financial and operating results are as follows:

Financial Highlights Three Months Ended June 30, Six Months Ended June 30,
(thousands except share and per boe data) (6:1 oil equivalent conversion) 2016 2015 % Change 2016 2015 % Change
Petroleum and natural gas revenue (1) 20,325 49,268 (59 ) 41,936 91,603 (54 )
Funds from operations (2) 7,429 31,115 (76 ) 16,921 56,726 (70 )
Per share - basic and diluted 0.05 0.25 (80 ) 0.12 0.46 (74 )
Net loss (7,779 ) (1,755 ) 343 (16,042 ) (7,108 ) 126
Per share - basic and diluted (0.05 ) (0.01 ) 400 (0.11 ) (0.06 ) 83
Total capital expenditures 17,525 9,982 76 35,776 56,920 (37 )
Net debt (3) - period end 104,519 123,427 (15 ) 104,519 123,427 (15 )
Weighted average basic shares 150,970,068 122,229,473 24 139,799,271 122,209,291 14
Weighted average diluted shares 150,970,068 122,229,473 24 139,799,271 122,209,291 14
Issued and outstanding shares (4) 150,970,068 122,229,473 24 150,970,068 122,229,473 24
Operating Highlights
Average daily production:
Natural gas (Mcf/d) 28,779 44,765 (36 ) 32,111 41,763 (23 )
Crude oil (bbls/d) 3,307 5,888 (44 ) 3,764 5,689 (34 )
NGLs (bbls/d) 321 275 17 306 289 6
Oil equivalent (boe/d) 8,425 13,625 (38 ) 9,421 12,939 (27 )
% Liquids (Oil and NGLs) 43 % 45 % (4 ) 43 % 46 % (7 )
Average sales price (1) :
Natural gas ($/Mcf) 1.60 3.40 (53 ) 1.87 3.29 (43 )
Crude oil ($/bbl) 51.44 64.64 (20 ) 43.61 63.23 (31 )
NGLs ($/bbl) 22.44 31.53 (29 ) 20.50 31.38 (35 )
Oil equivalent ($/boe) 26.51 39.74 (33 ) 24.46 39.12 (37 )
Operating expenses ($/boe) 5.27 3.89 35 5.14 4.73 9
Operating netback (5) ($/boe) 12.78 27.61 (54 ) 12.71 26.71 (52 )
Wells drilled: gross (net) 3 (3.0 ) 1 (1.0 ) 200 7 (7.0 ) 6 (6.0 ) 17
(1) Petroleum and natural gas revenue and pricing includes realized gains or losses from risk management commodity contracts.
(2) Funds from operations does not have any standardized meaning prescribed by International Financial Reporting Standards ("IFRS"). Please refer to the Reader Advisories hereinafter.
(3) Net debt is not a recognized measure under IFRS. Please refer to the Reader Advisories hereinafter.
(4) As of August 15, 2016, there were 150,970,068 million common shares outstanding.
(5) Operating netback is not a recognized measure under IFRS. Please refer to the Reader Advisories hereinafter.

Second Quarter 2016 Highlights

  • Second quarter production was 8,425 boe/d (as previously-announced), with a relatively balanced oil-gas production profile 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 an infrastructure mechanical issue. 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.

  • Second quarter petroleum and natural gas revenue amounted to $20.3 million (79% from crude oil and NGL sales), as compared to $49.3 million (72% of crude oil and NGL sales) in the second quarter of 2015 and $21.6 million (70% of crude oil and NGL sales) in the preceding first quarter of 2016.

  • Second quarter petroleum and natural gas royalties amounted to $3.7 million (18% of petroleum and natural gas revenue, excluding realized amounts on risk management commodity contracts), as compared to $6.0 million (12% of petroleum and natural gas sales) in the second quarter of 2015 and $2.3 million (11% of petroleum and natural gas sales) in the preceding first quarter of 2016. A non-recurring Crown royalty adjustment charge of $940 thousand, resulting from the annual recalculation of the Crown's gas cost allowance, increased the Company's effective royalty rate for the second quarter. This royalty charge increased RMP's second quarter 2016 royalty rate by 4.6%. On January 29, 2016, the Government of Alberta introduced a new royalty framework for the province's oil and gas industry, the Modernized Royalty Framework ("MRF"), which will take effect on January 1, 2017. Preliminary analysis of the financial impact on the Company's Montney light oil drilling inventory, as a result of the new MRF, indicates a significant, positive impact on RMP's well economics.

  • Second quarter field operating expenses on a per-unit basis were $5.27/boe, reflecting the Company's ongoing optimization and cost discipline of its operating cost structure in addition to industry cost deflation resulting from prolonged low commodity prices. RMP realizes cost savings resulting from ownership and operatorship of extensive field infrastructure and also provides the Company with the future opportunity to realize operating cost recoveries through third-party utilization. The second quarter transportation cost of $3.58/boe was in-line with the $3.43/boe recognized for the comparative second quarter of 2015, however, the transportation cost was higher than the preceding first quarter 2016 cost of $2.66/boe due to lower gas production volumes covering the fixed component of its firm service gas transportation charges. Second quarter general and administrative expenses ("G&A") of $1.4 million decreased 21% when compared to the $1.8 million for the second quarter of 2015 and decreased 13% from the $1.6 million G&A expense in the preceding first quarter 2016.

  • Second quarter funds from operations amounted to $7.4 million ($0.05 per basic share). The Company's field operating netback was $12.78/boe for the second quarter (as previously-announced). Low controllable cash costs (operating expenses, G&A expenses and bank interest) of $8.36/boe for the second quarter, continues to foster RMP's cash flow generating capabilities.

  • In the second quarter, RMP incurred $17.5 million in property, plant and equipment and exploration and evaluation capital expenditures (as previously-announced), including $10.0 million invested in the Gold Creek asset purchase. In the quarter, drilling and completions operations consisted of the drilling of three (3.0 net) Montney horizontal oil wells, one located at Ante Creek and two at Waskahigan. Frac oil-based completion operations were undertaken on the Ante Creek well in the second quarter of 2016, which was brought on-production in July 2016. A hybrid slick water fracture stimulation on the first Waskahigan well was completed in the second quarter. The Company also invested $2.4 million in Crown undeveloped land purchases at Gold Creek in the quarter. On June 27, 2016, the Company closed the purchase of assets in the Gold Creek area of West Central Alberta. The purchase price was funded from RMP's available bank credit facility. The Gold Creek acquisition was included within the Company's fiscal 2016 capital budget of approximately $50 million.

  • As at June 30, 2016, the Company's net debt amounted to $104.5 million (as previously-announced), an 11% decrease from the year-end 2015 net debt of $118.0 million. Bank interest expense in the second quarter was $939 thousand or $1.22/boe. On August 3, 2016, the borrowing base re-determination of RMP's bank credit facility (the "Credit Facility") was completed. The maximum conforming borrowing limit under the Credit Facility has been set at $120.0 million and is available to October 31, 2016, with a scheduled step-down to $100.0 million thereafter on a fully revolving basis until July 22, 2017, at which time the Company could request approval by the banking syndicate for an extension for an additional 364 day period. The scheduled step-down may occur earlier on the occurrence of certain events that generate additional liquidity. Under the Credit Facility, there is one financial covenant: an interest-coverage ratio requirement of at least 3.5 times. At June 30, 2016, the Company's ratio was significantly above this threshold, with interest coverage of approximately 15 times. Please refer to RMP's second quarter 2016 MD&A for details on the calculation of this covenant. RMP continues to maintain a reasonable level of balance sheet leverage and expects to have sufficient liquidity to support and fund its operations and planned capital expenditures for the balance of this year.

Strategic Discussion

On August 4, 2016 RMP announced that it has initiated a process to review strategic alternatives with a view to maximizing the value of the Company's large Montney resource base. 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.

RMP has engaged FirstEnergy Capital Corp. ("FirstEnergy") and Scotia Waterous Inc. as co-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. 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 (the "Board") to be in the best interests of the Company and its shareholders. 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.

RMP's interim condensed consolidated financial statements and Management's Discussion and Analysis for the three and six months ended June 30, 2016 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.

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

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: estimated second quarter production levels without the Kaybob field shut-in; future liquidity and financial capacity to fund on-going operations and remaining 2016 planned capital expenditures; the anticipated impact of the MRF and its effect on well economics; and, the 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 effective 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.

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