Press release from Marketwire
RMP Energy Provides Year-End Reserves Information
Tuesday, March 06, 2012
CALGARY, ALBERTA--(Marketwire - March 6, 2012) - RMP Energy Inc. ("RMP" or the "Company") (TSX:RMP) today provided information on its crude oil and natural gas reserves as of December 31, 2011, as evaluated by the Company's independent qualified reserves evaluators, InSite Petroleum Consultants Ltd. ("InSite"). The evaluation of RMP's reserves was prepared in accordance with the definitions, standards and procedures prescribed in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook. Highlights include:
- Total proved plus probable oil and gas reserves increased to 22.68 million boe, a 36% increase over the 16.68 million boe at December 31, 2010, after revisions to natural gas reserves discussed below.
- Total crude oil reserves increased by 814% to 9.41 million bbls from 1.03 million bbls (proved plus probable), as a result of the continued successful delineation and development of RMP's Montney light oil pool at Waskahigan and exploration success at Ante Creek. The Company's crude oil and NGLs weighting of its reserves base has increased to 46% of total proved plus probable (41% of total proved).
- Increased the Waskahigan area Montney reserves by 731% to 11.96 million boe, as compared to 1.44 million boe at December 31, 2010 (proved plus probable). Waskahigan finding and development costs in 2011 were $25.12 per proved plus probable boe, which includes approximately $18.5 million of capital incurred for the installation of the Waskahigan oil battery and the associated gathering lines, resulting in a recyle ratio of 2.2 times based on field operating netbacks of $55.33 per boe, post-start-up of RMP's oil battery facility.
- Corporate finding and development ("F&D") costs in 2011, prior to downward natural gas reserves revisions, were $23.34 per proved plus probable boe and $28.81 per proved boe. Total F&D costs include the change in undiscounted future development costs and approximately $18.5 million of Waskahigan oil battery-related capital. Excluding the Waskahigan infrastructure capital, the Company's proved plus probable 2011 F&D costs, prior to downward natural gas reserves revisions, were $21.76 per boe and $26.04 per proved boe. As a result of RMP's extensive multi-year inventory of crude oil drilling locations and in the midst of low natural gas prices, the Company could not reasonably foresee allocating any substantial capital to natural gas development in the near term. Consequently, the Company revised downward its proved undeveloped and probable undeveloped natural gas projects reserves of 22.2 Bcf (4.48 million boe including associated NGLs).
- Replaced 573% of 2011 annual production on a proved plus probable basis and 405% on a proved basis, net of revisions.
- Year-end net asset value of $3.93 per share (discounted 8%) and $3.47 per share (discounted 10%) (fully-diluted).
Fiscal 2011 Operating Results
In 2011, RMP successfully drilled twelve horizontal Montney oil wells (12.0 net) at Wakahigan and one exploration Montney oil well (1.0 net) at Ante Creek. The Company also participated in the drilling of five (2.0 net) non-operated Pine Creek Wilrich wells.
RMP's average daily production for the fourth quarter of 2011 grew 39% from the preceding third quarter to 4,719 boe/d, weighted 68% natural gas and 32% light oil and NGLs. At the end of October 2011, the Company commissioned and started-up its 100%-owned Waskahigan oil battery and compression facility. Average daily production for fiscal 2011 was 3,472 boe/d, weighted 75% natural gas and 25% light oil and NGLs.
The Company incurred finding and development capital expenditures of $101.0 million in fiscal 2011, including $18.5 million for the construction of the Waskahigan infrastructure and installation of the associated gathering pipelines and less $5.2 million of net undeveloped land dispositions. RMP also constructed and/or expanded eight multi-well surface pad sites in 2011 providing for the drilling of up to six horizontal wells per pad, thus strategically positioning the Waskahigan field with an extensive inventory of "drill ready" locations which aggregate to approximately 40 locations.
Corporate Reserves Information
|December 31, 2011 Reserves Summary (1) (Company interest before royalties)|
|Natural Gas||Light Crude Oil||NGLs||Oil Equivalent|
|(Columns may not add due to rounding)||(Bcf)||(Mbbls)||(Mbbls)||(Mboe) (6:1)|
|Proved developed producing||29.295||1,596.7||532.1||7,011.3|
|Proved developed non-producing||0.561||207.4||1.5||302.5|
|Total Proved plus Probable||73.156||9,406.5||1,077.7||22,676.9|
|Note (1) Estimated using InSite's forecast prices and costs as of December 31, 2011.|
|December 31, 2011 Net Present Value Summary (Company interest before royalties)|
|(Columns may not add due to rounding)|
|Proved developed producing||$||214,478||$||150,980||$||141,124||$||122,094||$||108,423|
|Proved developed non-producing||12,534||7,876||7,191||5,908||5,021|
|Total Proved plus Probable||$||763,345||$||362,877||$||313,405||$||226,910||$||171,991|
|Note (1) Estimated using InSite's forecast prices and costs as of December 31, 2011.|
A summary of InSite's escalated price forecast assumptions as of December 31, 2011 are as follows.
|Year||WTI Cushing Oklahoma (US$/bbl)||Edmonton Par Price 40 API (C$/bbl)||Natural Gas AECO-C Price (C$/mmbtu)||NGLs Edmonton Propanes
|NGLs Edmonton Butanes
|NGLs Edmonton Condensate
|Thereafter||Escalation rate of 2.0%|
Finding and Development Costs
In 2011, the Company invested a substantial amount of strategic, up-front capital in 100%-owned field infrastructure at Waskahigan in order to accommodate the company-operated handling and processing of production under a large-scale oil development program. Going forward, with RMP's focused development of reserves at Waskahigan and Ante Creek, the Company anticipates finding and development costs for its high-netback Montney oil projects to approximate $20 to $25 per boe, assuming current capital costs.
The following highlights the Company's finding and development ("F&D") costs in 2011.
|F&D Costs||Fiscal 2011|
|(amounts in $000s except reserve units and unit costs)||Proved||Proved + Probable|
|Exploration and development expenditures||$||86,596||$||86,596|
|Waskahigan oil battery and gathering lines infrastructure||18,531||18,531|
|Net land dispositions (1)||(5,163||)||(5,163||)|
|Capitalized general and administrative and office costs||1,037||1,037|
|Total finding and development expenditures (2)||$||101,001||$||101,001|
|Future development cost - ending period (3)||149,734||239,855|
|Less: Future development cost - beginning period (3)||(81,953||)||(97,573||)|
|All-in total, including change in future development cost (4)||$||168,782||$||243,283|
|Reserve additions - excluding acquisitions / dispositions and natural gas technical revisions (5) (Mboe)||6,683.9||11,737.6|
|Natural gas technical revisions - (Mboe)||(1,523.5||)||(4,483.0||)|
|Net reserve additions - including revisions (5) (Mboe)||5,160.4||7,254.6|
|F&D Costs - excluding natural gas technical revisions ($/boe)||$||28.81||$||23.34|
|F&D Costs - including natural gas technical revisions ($/boe)||$||32.71||$||33.53|
|(1) Reflects fiscal 2011 Crown land purchases of $5.51 million less Kaybob deep rights land disposition of $10.67 million.|
|(2) Total capital expenditures for fiscal 2011 are unaudited and exclude non-cash capitalized stock-based compensation expense of $2.6 million.|
|(3) Future development capital expenditures required to convert proved non-producing reserves and probable reserves to proved producing reserves.|
|(4) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.|
|(5) Excludes any acquired and/or disposed reserves. Future development costs associated with natural gas technical revisions from unbooked proved undeveloped and probable undeveloped locations equal $23.81 million for proved undeveloped reserves and $30.69 million for probable undeveloped reserves.|
The following are summaries of InSite estimated future development capital ("FDC") required to bring total proved and probable reserves on production.
|Future Development Capital Costs (1)|
|(amounts in $000s)||Total Proved||Total Proved + Probable|
|2015 and subsequent||17,842||18,690|
|Total undiscounted FDC||$||149,734||$||239,855|
|Total discounted FDC at 10% per year||$||130,132||$||204,971|
|Note (1) FDC as per InSite's independent reserves evaluation as of December 31, 2011 and based on InSite's forecast pricing as at December 31, 2011.|
|Future Development Capital Costs by Area (1)|
|Total Proved + Probable
|Gross Locations||Net Locations|
|Note (1) Total proved plus probable FDC as per InSite's independent reserves evaluation as of December 31, 2011 and based on InSite's forecast pricing as at December 31, 2011.|
Pursuant to the requirements of NI 51-101 relating to issuer disclosure of finding and development costs, the following outlines finding and development costs in 2010, in addition to the average over the three-year period of 2009 to 2011.
|F&D Costs||2010||Three Year Average|
|(amounts in $000s except reserve units and unit costs)||Proved||Proved + Probable||Proved||Proved + Probable|
|Total finding and development expenditures (1)||$||17,277||$||17,277||$||163,915||$||163,915|
|Future development cost - ending period (2)||81,953||97,573||149,733||239,855|
|Less: Future development cost - beginning period (2)||(71,502||)||(111,820||)||(41,746||)||(72,925||)|
|All-in total, including change in future development cost (3)||$||27,728||$||3,030||$||271,902||$||330,845|
|Reserve additions - including revisions (4) (Mboe)||1,320.6||(440.1||)||9,703.1||12,549.9|
|Total F&D Costs - including reserves revisions ($/boe)||$||21.00||$||( 6.89||)||$||28.02||$||26.36|
|(1) Net of undeveloped land dispositions and includes capitalized general and administrative and office costs. Excludes non-cash capitalized stock-based compensation expense.|
|(2) Future development capital expenditures required to convert proved non-producing and probable reserves to proved producing.|
|(3) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.|
|(4) Excludes any acquired and/or disposed reserves.|
Waskahigan Montney Reserves Information
2011 marked a significant year in the development and advancement of RMP's largest light oil asset, the Waskahigan Montney formation in West Central Alberta. Based on the InSite's independent reserves evaluation, 11.96 million boe of proved plus probable reserves (6.37 million boe proved) have been assigned to the Company's Montney asset base at Waskahigan as at December 31, 2011, a 733% increase from the year-end 2010 reserves booking (1,118% increase on a proved basis). Of the Company's 43 gross (43.0 net) sections of land held as at December 31, 2011, reserves were assigned to 17 sections, consisting of 16 proved producing wells, 23 proved undeveloped locations and 18 probable undeveloped locations. Future development capital (undiscounted) associated with these proved plus probable reserves aggregate to $190.2 million ($105.2 million for proved undeveloped reserves). The Company has identified a drilling inventory in excess of 140 locations at Waskahigan, providing for a significant, multi-year inventory targeting light oil. A summary of the reserves assigned at Waskahigan as of December 31, 2011 is as follows.
(Company interest before royalties)
|Net Present Value (1)|
|December 31, 2011||Solution Gas||Light Crude Oil||Oil Equivalent||PV5%||PV10%|
|(Columns may not add due to rounding)||(Bcf)||(Mbbls)||(Mboe)(6:1)||($000s)||($000s)|
|Proved developed producing||4.148||1,583.4||2,274.9||$||95,635||$||80,145|
|Total Proved plus Probable||19.949||8,638.8||11,964.2||$||314,834||$||202,777|
|Note (1) Net Present Value equals net present value of future net revenue before taxes based on InSite's forecast prices and costs as of December 31, 2011.|
The following highlights Waskahigan field F&D costs and recycle ratio for 2011:
|Waskahigan F&D Costs and Recycle Ratio||Fiscal 2011|
|(amounts in $000s except reserve units and unit costs)||Proved||Proved + Probable|
|Drilling, completions, equipping, tie-in expenditures||$||74,642||$||74,642|
|Waskahigan oil battery and gathering lines infrastructure||18,531||18,531|
|Undeveloped land purchases||5,090||5,090|
|Total finding and development expenditures (1)||$||98,820||$||98,820|
|Future development cost - ending period (2)||105,187||190,237|
|Less: Future development cost - beginning period (2)||(8,000||)||(16,000||)|
|All-in total, including change in future development cost (3)||$||196,007||273,057|
|Total reserve additions (Mboe)||6,190.3||10,868.0|
|F&D Costs - excluding Waskahigan Oil Battery ($/boe)||$||28.67||$||23.42|
|F&D Costs - including Waskahigan Oil Battery ($/boe)||$||31.66||$||25.12|
|November and December 2011 field operating netback (4)||$||55.33||$||55.33|
|Recyle ratio - excluding Waskahigan oil battery||1.9||2.4|
|Recyle ratio - including Waskahigan oil battery||1.7||2.2|
|(1) Total finding and development expenditures for fiscal 2011 are unaudited.|
|(2) Future development capital expenditures required to convert proved non-producing reserves and probable reserves to proved producing reserves.|
|(3) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.|
|(4) Field operating netbacks are equal to revenue less royalties, operating expenses and transportation costs. Waskahigan oil battery facility commissioned with start-up end of October 2011. As such, Waskahigan field operating netbacks for the months of November and December 2011 reflect full operational months with new company-owned and operated infrastructure. Fiscal 2011 Waskahigan field operating netbacks were $49.92 per boe.|
Waskahigan First Quarter Operations Update
To-date in the first quarter of 2012, RMP has successfully drilled four (4.0 net) Waskahigan Montney light oil infill horizontal oil wells and is presently drilling its fifth down-space well (the Company's twenty-first horizontal well since pool discovery). The wells are in various stages of completion and tie-in connection to Company-owned infrastructure.
Additionally, the Company drilled a water disposal well at its oil battery facility in order to facilitate the efficient handling and disposal of produced Montney formation water. Field oil production at Waskahigan presently has a water cut of approximately 20% with the produced water trucked to a third party-operated disposal facility. Commission and commencement of the disposal well will occur upon approval by the Energy Resources Conservation Board, anticipated by spring break-up. RMP expects cost savings of approximately $1.25 per boe through elimination of trucking costs and third-party disposal fees.
The Company continued the expansion of its Waskahigan area light oil resource-play through an agreement to acquire a 70% working interest in 7,840 contiguous acres of undeveloped land (5,488 net acres), including the Montney mineral rights but excluding the deep rights, from an arm's-length party for $8.5 million. The acquisition is subject to certain customary conditions. The land is located to the south east of RMP's existing Waskahigan asset base in West Central Alberta. The purchase is scheduled to close on or about April 2, 2012. With existing well control on and surrounding the acreage to be acquired, RMP has identified up to 40 Montney light oil drilling locations. Following the closing of the purchase, the Company will hold a significant position in the Triassic Montney oil fairway, encompassing a total of 39,200 acres (36,848 net acres) of prospective acreage at Waskahigan and Ante Creek.
Ante Creek Montney Reserves Information
In the fourth quarter of 2011, RMP evaluated and confirmed an oil-bearing Montney formation at Ante Creek in West Central Alberta through the successful drilling of its 100%-owned exploration well located at 4-35-66-24W5 (test rate information previously disclosed on January 12, 2012). As a result, based on the independent reserves evaluation by InSite, 0.84 million boe of proved plus probable reserves weighted 88% light oil (0.47 million boe proved) have been assigned at Ante Creek. Reserves booking consist of one proved developed non-producing well, one proved undeveloped location and one offset probable undeveloped location.
At Ante creek, the Company holds a contiguous six section acreage position (100% working interest) and intends follow-up the 4-35 oil discovery with a second location in the third quarter of this year. Based on down-spacing to four wells per section, there are a potential 23 additional horizontal locations on the RMP's lands. Commercial production is anticipated to commence as early as the fourth quarter of this year.
Kaybob Montney Reserves Information
As a result of RMP directing capital to the development and delineation of its light oil Montney projects at Waskahigan and Ante Creek, and in the midst of continued weak natural gas prices which have the effect of muting gas-weighted project economics, the Company's "legacy" natural gas Montney asset at Kaybob is not expected to be developed on a large scale within the next few years. As such, at year-end 2011, the Company elected to remove 11 (9.6 net) natural gas weighted future proved undeveloped and probable undeveloped drilling locations at Kaybob with a resulting downward revision of 4.77 million boe of proved plus probable reserves (2.41 million boe proved).
Net Asset Value
The Company's intrinsic value, as measured by its net asset value, is as follows:
|December 31, 2011||NPV 8%||NPV 10%|
|(per share figures based on fully-diluted shares)||($000s)||$/share||($000s)||$/share|
|Proved plus probable reserves NPV (1,2)||$||362,877||$||3.37||$||313,405||$||2.91|
|Undeveloped acreage (3)||85,690||0.80||85,690||0.80|
|Net debt (4)||(49,087||)||(0.46||)||(49,087||)||(0.46||)|
|Proceeds from stock options and warrants (5)||23,527||0.22||23,527||0.22|
|Net Asset Value (fully-diluted)||$||423,007||$||3.93||$||373,535||$||3.47|
|(1) Evaluated by InSite as at December 31, 2011. Net present value of future net revenue does not represent fair market value of the reserves.|
|(2) Net present values ("NPV") equals net present value of future net revenue before taxes based on InSite's forecast prices and costs as of December 31, 2011.|
|(3) Internally-evaluated with average acreage value of $505 per acre.|
|(4) Net debt as at December 31, 2011, including working capital deficit (unaudited).|
|(5) Fully-diluted shares at December 31, 2011 total 107,752,660: including outstanding common shares of 96,647,655 and 11,105,005 stock options and warrants.|
RMP anticipates releasing its audited annual consolidated financial statements for the year ended December 31, 2011 on March 21, 2012.
|Crude Oil and Natural Gas Liquids||Natural Gas and Natural Gas Liquids|
|bbl or bbls||barrel or barrels||Mcf/d||thousand cubic feet per day|
|Mbbl||thousand barrels||NGLs||natural gas liquids|
|bbls/d||barrels per day||MMcf/d||million cubic feet per day|
|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|
Unless otherwise specified, all reserve volumes set forth above (and all information derived therefrom) are based on company gross reserves (working interest before deduction of royalties) unless noted otherwise and are based upon an independent reserves assessment and evaluation prepared by InSite Petroleum Consultants with an effective date of December 31, 2011 (the "InSite Report"). This news release summarizes the Company's crude oil, natural gas liquids and natural gas reserves and the net present values before income tax of future net revenue for the Company's reserves using forecast prices and costs based on the InSite Report. The InSite Report has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook and the reserve definitions contained in National Instrument 51-101.
RMP's oil and gas reserves statement for the year-ended December 31, 2011, which will include complete disclosure of the Company's oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within its Annual Information Form which will be available on our SEDAR profile at www.sedar.com on or before March 31, 2012. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.
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. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. 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 new release contains forward-looking information relating to: Montney crude oil projects F&D costs, identified additional drilling locations, the timing of a water disposal well at Waskahigan and cost savings from such disposal well and the timing of the release by RMP of its year end 2011 financial statements and well tie-in timing. 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.
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.
Certain financial and operating information included in this news release for the quarter and year ended December 31, 2011, such as finding and development costs and net asset value, are based on estimated unaudited financial results for the year then ended, and are subject to the same limitations as discussed in the aforementioned "forward-looking statements" paragraph. These estimated amounts may change upon the completion of audited consolidated financial statements for the year ended December 31, 2011.
All evaluations and reviews of future net cash flows are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimates of future net revenues presented in the tables above represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of our crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
In relation to the disclosure of net asset value ("NAV"), the NAV table shows what is normally referred to as a "produce-out" NAV calculation under which the current value of the Company's reserves would be produced at forecast future prices and costs and do not necessarily represent a "going concern" value of the Company. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the future net revenues estimated by InSite represent the fair market value of the reserves, nor should it be assumed that RMP's internally-estimated value of its undeveloped land holdings represent the fair market value of the lands.
FOR FURTHER INFORMATION PLEASE CONTACT:
Craig Stewart RMP ENERGY INC. Executive Chairman (403) 930-6302 firstname.lastname@example.org
John Ferguson RMP ENERGY INC. President and Chief Executive Officer (403) 930-6303 email@example.com
Dean Bernhard RMP ENERGY INC. Vice President, Finance and Chief Financial Officer (403) 930-6304 firstname.lastname@example.org