CALGARY, ALBERTA -- (Marketwired) -- 08/13/15 -- RMP Energy Inc. ("RMP" or the "Company") (TSX: RMP) is pleased to report for the three months ended June 30, 2015 funds from operations of $31.1 million ($0.25 per basic share) on realized revenue of $49.3 million, cash costs (5) of $9.83/boe and record average daily production of 13,625 barrels of oil equivalent, weighted 45% light oil and NGLs. Detailed second quarter results are as follows:
Financial Highlights Three Months Ended June 30, ----------------------------------- (thousands except share and per boe % data) (6:1 oil equivalent conversion) 2015 2014 Change ------------ ------------ ------- Petroleum and natural gas revenue (1) 49,268 77,552 (36) Funds from operations (2) 31,115 48,368 (36) Per share - basic 0.25 0.40 (38) - diluted 0.25 0.38 (34) Net income / (loss) (1,755) 18,339 (110) Per share - basic (0.01) 0.15 (107) - diluted (0.01) 0.14 (107) Total capital expenditures 9,982 14,625 (32) Net debt (2) - period end 123,427 94,848 30 Weighted average basic shares 122,229,473 120,827,137 1 Weighted average diluted shares 122,229,473 126,813,214 (4) Issued and outstanding shares (3) 122,229,473 122,092,590 - Operating Highlights Average daily production: Natural gas (Mcf/d) 44,765 32,023 40 Crude oil (bbls/d) 5,888 6,914 (15) NGLs (bbls/d) 275 186 48 Oil equivalent (boe/d) 13,625 12,437 10 % Liquids (Oil and NGLs) 45% 57% (21) Average sales price(1) : Natural gas ($/Mcf) 3.40 5.04 (33) Crude oil ($/bbl) 64.64 98.14 (34) NGLs ($/bbl) 31.53 66.07 (52) Oil equivalent ($/boe) 39.74 68.53 (42) Operating expenses ($/boe) 3.89 5.26 (26) Operating netback (4) ($/boe) 27.61 45.36 (39) Wells drilled: gross (net) 1 (1.0) 4 (4.0) (75) Financial Highlights Six Months Ended June 30, ---------------------------------- (thousands except share and per boe % data) (6:1 oil equivalent conversion) 2015 2014 Change ------------ ----------- ------- Petroleum and natural gas revenue (1) 91,603 134,057 (32) Funds from operations (2) 56,726 83,902 (32) Per share - basic 0.46 0.70 (34) - diluted 0.46 0.67 (31) Net income / (loss) (7,108) 28,235 (125) Per share - basic (0.06) 0.24 (125) - diluted (0.06) 0.23 (126) Total capital expenditures 56,920 70,889 (20) Net debt (2) - period end 123,427 94,848 30 Weighted average basic shares 122,209,291 119,857,069 2 Weighted average diluted shares 122,209,291 125,441,115 (3) Issued and outstanding shares (3) 122,229,473 122,092,590 - Operating Highlights Average daily production: Natural gas (Mcf/d) 41,763 27,082 54 Crude oil (bbls/d) 5,689 6,116 (7) NGLs (bbls/d) 289 212 36 Oil equivalent (boe/d) 12,939 10,842 19 % Liquids (Oil and NGLs) 46% 58% (21) Average sales price(1) : Natural gas ($/Mcf) 3.29 5.30 (38) Crude oil ($/bbl) 63.23 95.30 (34) NGLs ($/bbl) 31.38 66.96 (53) Oil equivalent ($/boe) 39.12 68.31 (43) Operating expenses ($/boe) 4.73 5.89 (20) Operating netback (4) ($/boe) 26.71 45.81 (42) Wells drilled: gross (net) 6 (6.0) 10 (10.0) (40) Notes: (1) Petroleum and natural gas ("P&NG") revenue and pricing includes realized gains or losses from risk management contract settlements. Six months 2015 reported average sales price for crude oil includes realized oil hedge termination proceeds of $6.6 million. Excluding the realized oil hedge termination proceeds, the six months 2015 crude oil average sales price is $56.82/bbl. (2) Funds from operations and net debt 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) As of August 12, 2015, 123.8 million common shares were outstanding. (4) Operating netback is not a recognized measure under IFRS. Please refer to the Reader Advisories at the end of the news release. (5) 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.
Second Quarter 2015 Highlights
-- Record quarterly production of 13,625 boe/d (weighted 45% light oil and NGLs), representing a 11% increase over the preceding first quarter 2015 production of 12,245 boe/d. Intermittent production from the Company's Kaybob field impacted second quarter production levels by approximately 900 boe/d. The curtailed production was a result of third-party gas transportation restrictions causing uneconomic pricing on a regional sales pipeline, which prompted the Company's deliberate shut-in of its Kaybob field during a portion of the second quarter. RMP's Kaybob Montney field produced only 450 boe/d on average in the second quarter, as compared to 1,370 boe/d produced by this field in the first quarter of 2015. The Kaybob field is presently off-line due to low gas prices as a result of the prolonged transportation restriction issue. The Company is anticipating the resumption of full production from the Kaybob field in the fourth quarter of this year. On April 2, 2015, the Company commissioned its second Ante Creek gas handling and battery facility, enabling concurrent production from all of RMP's wells. Approximately half of the wells are on artificial lift with the balance still 'free flowing' on primary recovery. Prior to the Alliance mainline shut-in announced on August 7, 2015, production from Ante Creek based on field estimates, was approximately 8,500 boe/d (weighted 45% light oil and NGLs). Three recently-drilled Ante Creek Montney wells are at various stages of completion and well tie-in. Please refer to Outlook and Guidance section hereafter within this news release. -- Petroleum and natural gas revenue in the second quarter amounted to $49.3 million, including a realized natural gas hedging gain of $1.3 million, of which 72% was derived from crude oil and NGLs. The Company's crude oil discount to the Canadian-dollar converted WTI price averaged $6.42/bbl during the second quarter, as compared to the $10.71/bbl in the preceding first quarter of 2015. -- Petroleum and natural gas royalties amounted to $6.0 million (12% of petroleum and natural gas sales, excluding a realized gain on risk management commodity contracts), as compared to $18.1 million (23% of petroleum and natural gas sales) in the comparative second quarter of 2014. -- The second quarter per-unit operating cost of $3.89/boe represents a 26% decrease from the $5.26/boe realized for the comparative second quarter 2014 period and 31% lower than the $5.67/boe realized in the first quarter of 2015. General and administrative expenses for the second quarter decreased 10% to $1.46/boe, when compared to the $1.62/boe realized for the comparative second quarter of 2014, and was 3% lower than the $1.51/boe realized in the first quarter of 2015. -- Generated funds from operations of $31.1 million ($0.25 per share) for the three months ended June 30, 2015, with a realized second quarter 2015 field operating netback of $27.61/boe. -- Approximately $10.0 million was incurred on capital expenditures in the second quarter. In spite of favourable 'spring break-up' field conditions in the quarter, with weak and uncertain commodity prices, the Company's drilling operations were muted in the second quarter. Only one (1.0 net) horizontal well was drilled and completed in the second quarter at Ante Creek, as compared to four (4.0 net) wells drilled in the same quarter of last year. Capital expenditures incurred in the second quarter of this year also included the initial drilling costs of a Waskahigan horizontal well offsetting a successful hybrid slick-water well, undeveloped land acquisitions and the remaining costs to complete construction of the Company's second Ante Creek gas handling and battery facility. In response to lower crude oil prices, RMP is currently operating only one drilling rig at Waskahigan, targeting the Montney formation. The Company will also be undertaking back-to-back hybrid slick-water completions on two Waskahigan wells (7-15-64-23W5 and 13-11- 64-23W5), with expected production tie-in on or about October 1, 2015. Please refer to Outlook and Guidance section hereafter for details on Waskahigan hybrid slick-water results. With its recent capital expenditures activities, RMP has realized a reduction in average per- well drilling and completion costs of approximately 30%, reflecting both service cost reductions and improved efficiencies. -- RMP continues to be well-capitalized with net debt of approximately $123.4 million at June 30, 2015, representing only 1.0 times annualized second quarter 2015 funds from operations. On June 5, 2015, the Company's bank syndicate group reaffirmed the existing $175 million conforming borrowing base under RMP's revolving credit facility. As at August 12, 2015, RMP was drawn approximately $125 million on the bank facility. Under its bank credit facility, there is one prescribed financial covenant, an interest-coverage ratio requirement of at least 3.5 times. At June 30, 2015, the Company's ratio was significantly above this threshold, with interest coverage of 34.4 times (ten-fold the minimum requirement). Please refer to RMP's MD&A for details on this covenant calculation. Subsequent to the end of the second quarter, the Company closed a $4.8 million, non-brokered flow-through share private placement, providing RMP with additional financial flexibility. -- 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) through to October 31, 2015.
Outlook and Guidance
As outlined in RMP's May 14, 2015 news release within the Strategic Update section, the Company continues to advance the engineering, design and implementation of a secondary recovery project at Ante Creek. In collaboration with a third-party engineering firm, the geological model for the secondary recovery simulation has been completed. The next step involves the design and simulation phase, wherein different configurations will be simulated to determine the optimal place for water and/or gas injection and the potential oil recovery associated with the project. Additionally, relative permeability work on the Montney reservoir core has been undertaken. The results of this work exhibit very encouraging oil recoveries in the water displacement tests, including the lower permeability rock. Implementation of secondary recovery is expected to significantly increase the ultimate recovery of RMP's large oil-in-place reservoir at Ante Creek from the primary recovery factor of 8.2% utilized in the light oil reserves booking at year-end 2014. A pilot project is anticipated to be implemented in the first quarter of 2016, pending requisite regulatory approval.
At Waskahigan, the Company's hybrid slick-water well completion production performance continues to outperform Montney wells in the area, significantly improving well economics and profitability even in a low crude oil price environment. Three of the wells are producing at rates substantially above the Company's expected oil rates for its wells in the area. Two notable Montney delineation wells (2-15-64-23W5 and 12-29-63-23W5), prior to the Alliance mainline shut-in, were producing at rates of 280 bbls/d and 225 bbls/d, respectively, after five months of run-time. Both of these wells have each produced in excess of 50,000 barrels of light oil. The third well (12-9-64-23W5), a down-space well, was producing at 80 bbls/d after eight months of on-stream time and has cumulative production of approximately 36,000 barrels of oil in this producing timeframe. RMP has a substantial inventory of approximately 200 locations with which this completion technique can be applied (inventory includes just 18 proved undeveloped locations and 44 probable undeveloped locations booked in the year-end 2014 reserves report). In support of its long-term Montney resource development and to diversify its gas market access, in June 2015 the Company contracted for 20 MMcf/d of firm transportation receipt service on the NGTL system. The contract is for a term of eight years and commences on November 1, 2018, subject to NGTL system expansion.
In addition to the Company's value-enhancing initiatives at Ante Creek and Waskahigan, RMP continues to accumulate Montney-prospective undeveloped land outside of its main light oil fairway, with anticipation of drilling its first well on this acreage in early 2016. A total of 46 sections, with a 100% working interest, have been acquired providing the Company with an emerging core area with which to apply its extensive geologic and engineering acumen.
Given the current crude oil price weakness, the Company is now budgeting for a fiscal 2015 capital expenditures program of approximately $90 million, which reflects drilling three (3.0 net) fewer wells than previously intended. RMP remains committed to prudently manage its level of capital expenditures in order to maintain its strong financial position. The Company will remain disciplined and flexible with its capital expenditures as it monitors commodity prices, cost of services, and business conditions over the near-term. The Company has flexibility to adjust the level of its capital investments, either upwards or downwards, as circumstances warrant.
Starting today, August 13, 2015, the Company has resumed gas sales injection into the Alliance pipeline system. Prior to the Alliance sales gas mainline shut-in, current corporate production based on field estimates, was approximately 11,500 boe/d (weighted 46% light oil and NGLs), without any production contribution from the Kaybob field. Additionally, five recently-drilled Montney horizontal wells (three at Ante Creek and two at Waskahigan), at various stages of completion and field tie-in, will augment the Company's production levels. The recent Alliance mainline pipeline outage, a mechanical disruption at its Waskahigan oil battery for a seven day period in early-July, the Kaybob shut-in, reduced second half capital spending and muted drilling activities in the second quarter have collectively impacted RMP's production estimate for fiscal 2015 and the third quarter of 2015. Estimated production for the third quarter of 2015 will be lower than the Company's updated annual production average estimate as a result of the aforementioned operational disruptions, normal field declines and minimal new production additions during the third quarter. The Company is still forecasting modest annual production growth by spending approximately 50% less than the capital expenditures incurred in fiscal 2014. RMP expects to maintain its production level from year-end 2014 by spending internally-generated cash flow. For fiscal 2015, RMP is forecasting average daily production of approximately 12,000 boe/d (weighted 45% oil and NGLs).
For fiscal 2015, the Company is forecasting funds from operations of approximately $90 million, which assumes second half 2015 commodity price averages of US$46.00/bbl for WTI oil, C$2.80/GJ for AECO gas and an exchange rate of $0.7640 (US$/C$). As a result of a 'cash flow-based' exploration and development expenditures program for 2015, the Company's year-end 2015 net debt position is anticipated to approximate $119 million, slightly lower than year-end 2014 net debt.
In summary, 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 six months ended June 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.
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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: the amount of the Company's capital expenditure program for 2015; forecasted average daily production rate and liquids weighting for fiscal 2015 and the third quarter of 2015 and the forecasted annual increase over fiscal 2014 average daily production; forecasted funds from operations for 2015; key assumptions within the forecasted 2015 financial and production guidance including; WTI oil and AECO gas pricing and foreign exchange rate; year-end 2015 estimated net debt; the timing of completion operations at Waskahigan; the timing of implementation of a pilot project for RMP's secondary recovery project at Ante Creek and an expected increase in reserves recovery from the secondary recovery project; the Company's contract for firm transportation service on the NGTL system; and the timing of drilling on lands accumulated outside of its main Ante Creek/Waskahigan light oil fairway.
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 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.
RMP Energy Inc.
President and Chief Executive Officer
RMP Energy Inc.
Vice President, Finance and Chief Financial Officer