Third Quarter 2015 Production
For the third quarter of 2015, RMP’s average daily production was approximately 11,000 boe/d (weighted 47% light oil and NGLs). As previously disclosed, 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 prices resulting from increased pipeline capacity on the TCPL gas system. The Company is reaffirming its previously-announced fiscal 2015 production guidance, with expectations to produce on average for the year, approximately 12,000 boe/d (weighted 45% oil and NGLs).
Third Quarter 2015 Drilling Results
In the third quarter, the Company successfully drilled and completed six horizontal Montney wells: three (3.0 net) at Ante Creek (section 34-66-24W5) and three (3.0 net) at Waskahigan. The first two Waskahigan wells (7-15-64-23W5 and 13-11-64-23W5) were drilled offsetting the previously-drilled 2-15-64-23W5 horizontal well and were fracture stimulated with hybrid slick water. The 2-15 well was one of RMP’s initial hybrid slick water fractured wells and has produced approximately 75,000 barrels of light oil in six months of production time. Both the 7-15 and 13-11 wells were recently wellsite equipped and brought on-stream in early-October, with recent production rates of approximately 600 bbls/d of light oil per well (based on field estimates). 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 is expected to be tied-in and brought on-production in early-November 2015. Additionally, at the end of September, the Company rig released a Waskahigan offset well (13-29-63-23W5), which will be completed later this week with hybrid slick water.
Production from three of the Company’s initial Waskahigan hybrid slick water completed wells, including the 2-15 well, continues to significantly trend above the production performance from wells which were previously-stimulated with oil-based completion designs in the Waskahigan area. Thereby significantly increasing the estimated ultimate recoverable reserves and improving well economics. RMP has a substantial inventory of approximately 200 locations with which this completion design can be applied (inventory includes just 18 proved undeveloped locations and 44 probable undeveloped locations booked in the year-end 2014 reserves report).
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. Initial well production performance has been quite favorable, with output tracking RMP’s expected oil rates from wells drilled into that areal part of the 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.
Ante Creek Secondary Recovery Update
At Ante Creek, engineering, design and simulation work continues on the Company’s planned secondary recovery water flood project. Completed core work analysis and initial simulation modeling indicate that the reservoir is very amenable to a water flood. Implementation of the secondary recovery project is modeled 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 evaluation at year-end 2014. A pilot project is anticipated to be implemented in the summer of 2016, pending requisite regulatory approval.
New Core Area
Outside of RMP’s main light oil fairway, the Company accumulated an additional ten net sections of undeveloped land with Montney potential during the third quarter. As a result, a total of 46 net sections have now been acquired for an average cost of less than $300 per hectare. RMP anticipates drilling a horizontal well in 2016 to evaluate the hydrocarbon potential of this significant acreage position. This land position provides the Company with an exploration area with which to apply its extensive geologic and engineering understanding and forms the basis for a new core area augmenting the Company’s current portfolio of Montney assets.
Financial Position Update
RMP’s balance sheet remains strong in the current low crude oil price environment. The Company is presently drawn approximately $129 million on its bank credit facility, which has a borrowing limit of $175 million. RMP’s year-end 2015 net debt position is presently estimated to approximate $119 million, slightly lower than its year-end 2014 net debt, representing approximately 1.3 times forecasted fiscal 2015 funds from operations.
RMP’s interim condensed consolidated financial statements and associated Management’s Discussion and Analysis for the three and nine months ended September 30, 2015 is scheduled to be released at the end of business on Thursday, November 12, 2015.
|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|
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 Company’s third quarter 2015 average daily production level and oil and NGL weighting of such; recent well production rates for the Waskahigan 7-15 and 13-11 wells; timing of the tie-in and on-production date of the Waskahigan 4-7 well; timing of the hybrid slick water completion for the Waskahigan 13-29 well; the inventory of Waskahigan drilling locations; third quarter 2015 drilling and completion costs for the Ante Creek and Waskahigan wells; 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 timing of drilling on lands accumulated outside of its main Ante Creek/Waskahigan light oil fairway; and, year-end 2015 estimated net debt and net debt-to-forecasted fiscal 2015 funds from operations. 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.
RMP Energy Inc.
President and Chief Executive Officer
RMP Energy Inc.
Vice President, Finance and Chief Financial Officer