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RMP Energy Reports Fourth Quarter and Fiscal 2014 Results and Year-End Reserves and Provides Updated Market Guidance

CALGARY, ALBERTA–(Marketwired – Mar 18, 2015) – RMP Energy Inc. (“RMP” or the “Company“) (RMP.TO) is pleased to report for the year ended December 31, 2014 record financial and operating results including funds from operations of $164.1 million ($1.36 per basic share) on revenue of $265.9 million and average daily production of 11,782 barrels of oil equivalent. Detailed fourth quarter and annual results are as follows:

Financial Results Three Months Ended Twelve Months Ended
(thousands except share and per boe data) (6:1 oil equivalent conversion) Dec. 31, 2014 Dec. 31, 2013 % change Year 2014 Year 2013 % change
P&NG revenue (1) 56,239 34,074 65 265,892 136,078 95
Funds from operations(2) 32,152 19,408 66 164,092 78,553 109
Per share – basic 0.26 0.17 53 1.36 0.72 89
Per share – diluted 0.25 0.16 56 1.30 0.68 91
Net income 1,411 2,452 (42 ) 47,846 10,449 358
Per share – basic 0.01 0.02 (50 ) 0.40 0.10 300
Per share – diluted 0.01 0.01 0.38 0.09 322
E&D capital expenditures 62,226 54,671 14 186,231 131,638 41
Total capital expenditures 61,933 93,091 (33 ) 179,746 187,411 (4 )
Net debt (3) – period end 123,450 116,157 6 123,450 116,157 6
Weighted average basic shares 122,126,405 115,074,028 6 120,994,545 109,009,511 11
Weighted average diluted shares 126,709,422 122,403,243 4 126,461,424 115,244,968 10
Issued and outstanding shares(4) 122,126,840 118,096,756 3 122,126,840 118,096,756 3
Operating Results
Average daily production:
Natural gas (Mcf/d) 36,563 19,718 85 31,341 19,316 62
Crude oil (bbls/d) 5,896 3,880 52 6,308 3,417 85
NGLs (bbls/d) 352 99 256 251 236 6
Oil equivalent (boe/d) 12,342 7,266 70 11,782 6,872 71
Average sales price (1):
Natural gas ($/Mcf) 3.90 3.97 (2 ) 4.71 3.60 31
Crude oil ($/bbl) 76.32 73.28 4 89.59 84.40 6
NGLs ($/bbl) 52.99 77.55 (32 ) 62.04 63.69 (3 )
Oil equivalent ($/boe) 49.53 50.98 (3 ) 61.83 54.25 14
Operating expenses ($/boe) 5.91 7.00 (16 ) 5.81 7.22 (20 )
Operating netback (5)($/boe) 31.47 33.76 (7 ) 40.89 35.12 16
Wells drilled: gross (net) 7 (7.0 ) 5 (5.0 ) 40 26 (26.0 ) 18 (18.0 ) 44

Table Notes:

  1. Petroleum and natural gas (“P&NG“) revenue and pricing includes realized gains or losses from risk management commodity contract settlements.
  2. Funds from operations 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. Net debt is not a recognized measure under IFRS. Please refer to the Reader Advisories at the end of the news release.
  4. As of March 18, 2015, 122.2 million common shares were outstanding.
  5. Operating netback is not a recognized measure under IFRS. Please refer to the Reader Advisories at the end of the news release.

Fourth Quarter 2014 and Fiscal 2014 Highlights

  • Fiscal 2014 production increased 71% year-over-year to average 11,782 boe/d (weighted 56% light oil and NGLs), which exceeded the Company’s originally-guided 2014 production target of 10,000 boe/d and its subsequently upward revised guidance of 11,500 boe/d. Fourth quarter 2014 production averaged 12,342 boe/d, weighted 51% light oil and NGLs, reflecting a 70% increase over the comparable fourth quarter 2013 production of 7,266 boe/d. Recorded fourth quarter production was below corporate capability due to continued solution gas handling limitations at Ante Creek and the delayed tie-in of two, third quarter-drilled Kaybob Montney gas wells resulting from later-than-normal winter freeze-up of surface field conditions. Please refer to Fiscal 2015 Market Guidance Update section hereafter within this news release.
  • Petroleum and natural gas revenue for the fourth quarter amounted to $56.2 million, of which 77% was derived from crude oil and NGLs (including a realized commodity hedging gain of $2.7 million). The Company’s crude oil discount to the Canadian-dollar converted WTI price averaged $9.59/bbl during the fourth quarter, as compared to the $12.21/bbl in the preceding third quarter of 2014. The Company is currently forecasting an oil price differential of $9.00/bbl for fiscal 2015, based on current forward strip indications. Petroleum and natural gas revenue for fiscal 2014 amounted to approximately $265.9 million (net of a realized commodity hedging loss of $3.7 million), reflecting an increase of 95% over the $136.1 million in fiscal 2013.
  • Fourth quarter petroleum and natural gas royalties amounted to $11.6 million (22% 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 third quarter of 2014 and $5.5 million (15% of petroleum and natural gas sales) in the comparative fourth quarter of 2013. The effective royalty rate for the Ante Creek field in the fourth quarter was 28%, as compared to 25% in the preceding third quarter.
  • Fourth quarter corporate operating costs of $5.91/boe decreased 16% on a per boe basis, when compared to the $7.00/boe operating costs for the fourth quarter of 2013. Fiscal 2014 operating costs of $5.81/boe decreased 20% on a per boe basis, when compared to operating costs for the previous year of $7.22/boe.
  • Quarterly funds from operations of $32.2 million ($0.26 per basic share) for the three months ended December 31, 2014. Funds from operations for fiscal 2014 were $164.1 million, a significant increase of 109% (89% per basic share) over fiscal 2013.
  • Fiscal 2014 realized operating netback of $40.89/boe, representing a 16% increase over the $35.12/boe netback realized in fiscal 2013. Fourth quarter 2014 operating netback of $31.47/boe.
  • Reported net income for the year ended December 31, 2014 of $47.8 million, as compared to net earnings in fiscal 2013 of $10.4 million. Fourth quarter 2014 earnings were impacted by a non-cash impairment on property, plant and equipment in the aggregate amount of $12.8 million, which related to the Company’s gas-weighted assets at Kaybob and Gilby resulting primarily from the deterioration in forward commodity gas prices.
  • In fiscal 2014, the Company incurred $179.7 million on property, plant and equipment and exploration and evaluation activities, including approximately $15 million related to the Ante Creek-to-Waskahigan pipeline interconnect and battery expansion in early-2014 and approximately $16 million of upfront capital related to the Company’s ongoing construction of its second Ante Creek gas handling and battery facility. Please refer to First Quarter 2015 Operations Update section hereafter for further details. In 2014, RMP drilled 24 (24.0 net) horizontal wells and two water disposal wells. The Company’s 2014 capital program resulted in an all-in finding, development and acquisition cost of $22.69/boe (per proved plus probable), resulting in a recycle ratio of 1.8 times. Please refer to the Year-End Reserves Informationdisclosure hereafter.
  • RMP continues to be well-capitalized with net debt of approximately $123.5 million at year-end 2014, representing less than one times annualized fourth quarter 2014 cash flow from operations. The Company is currently drawn approximately $130 million on its bank credit facility with a current debt servicing rate of 3.0% (per annum). The current borrowing limit on the bank credit facility is $175 million and the lenders annual borrowing base re-determination is scheduled to occur before May 31, 2015.

RMP’s audited consolidated financial statements and associated Management’s Discussion and Analysis, in addition to its Annual Information Form, for the year ended December 31, 2014 is 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.

Fiscal 2015 Market Guidance Update

In mid-December 2014, the Company announced a 2015 capital expenditures budget of $150 million. However, as a result of a precipitous decrease in crude oil prices, and current commodity prices substantially below the Company’s originally-budgeted pricing assumptions, RMP is reducing its budgeted capital expenditures and now plans to spend between $95 million to $100 million in 2015. The Company is committed to capital investment discipline in a slumping crude oil and natural gas price environment and intends to preserve its strong financial position during this commodity down-cycle. Recently, RMP has begun to realize capital cost savings from its service providers and suppliers and within its revised 2015 capital budget has assumed an approximate 20% reduction in costs related to its remaining drilling and completion activities for this year. The Company’s 2015 drilling focus will involve the continued evaluation and delineation of its extensive Montney acreage in West Central Alberta. At Ante Creek, RMP expects to further evaluate its land position to the south-west of its legacy six section block in conjunction with development infill drilling of its high rate-of-return locations. At Waskahigan and Grizzly, the Company intends to high-grade its drilling efforts in response to the very encouraging, initial results achieved with its slickwater hybrid fracturing techniques.

Notwithstanding a reduction in capital spending for 2015, RMP continues to forecast industry-leading year-over-year production growth of 15%, with production estimated to average 13,500 boe/d (weighted 45% oil and NGLs). The 2015 capital program is expected to be funded by internally-generated funds from operations, which is forecasted to approximate $100 million, augmented by the aforementioned production increase and the Company’s low-cost operating profile. Forecasted funds from operations is based on a recent forward contango price strip of US$49.75 per barrel for WTI oil, C$2.75 per gigajoule for AECO gas and an exchange rate of $0.7875 (US$/C$). As a result of a “cash flow-based” exploration and development expenditures program for 2015, the Company’s year-end 2015 debt position is anticipated to remain relatively unchanged from year-end 2014 net debt.

With respect to commodity hedging, the Company’s natural gas revenue is partially protected from gas price weakness through a fixed swap wherein 10,000 GJs/d are hedged at a fixed AECO price of $3.70/GJ ($3.90/Mcf) for fiscal 2015. In early January 2015, the Company monetized its oil hedge contracts, realizing cash proceeds of $6.6 million. RMP elected to unwind its in-the-money oil hedge book in order to provide additional funding for its first quarter 2015 winter capital program, which has an anticipated quarterly spend level representing approximately 45% of the Company’s revised fiscal 2015 capital budget.

RMP will remain disciplined and flexible with its revised 2015 capital budget as it monitors commodity prices and business conditions over the near term and, may make further adjustments to its planned capital expenditures in 2015. The Company has flexibility to adjust the level of its capital investments, either upwards or downwards, as circumstances warrant.

First Quarter 2015 Operations Update

In the first quarter of this year, RMP successfully drilled and completed four (4.0 net) Ante Creek horizontal oil wells and one (1.0 net) Waskahigan horizontal oil well.

At Ante Creek, the Company has now drilled a total of 24 (24.0 net) Montney horizontal oil wells, of which only 14 wells are currently producing due to capacity limitations with associated solution gas processing at RMP’s Ante Creek 4-36 battery. In order to increase its gas processing capabilities and facilitate capacity for future full-phase development of the Ante Creek field, the Company is presently finalizing the construction of its second gas handling and battery facility (Ante Creek 5-26 battery). RMP has made good progress with this infrastructure project; the Company has taken physical delivery of all the major equipment and vessels, which are presently being connected to existing infrastructure. The scheduled in-service date for the Ante Creek 5-26 battery is on or about April 1, 2015. The estimated total capital investment is approximately $31 million, of which $16 million was incurred and recognized in fiscal 2014. At Ante Creek, the Company holds approximately 36 sections of land providing for a future drilling inventory of approximately 50 locations (of which 15 proved undeveloped locations and two probable undeveloped locations were included in the year-end 2014 independent reserves report outlined hereafter). This identified drilling inventory, along with the implementation of artificial lift and eventually secondary recovery techniques, is expected to result in increased recoveries of crude oil and solution gas at Ante Creek and the maintenance of production providing for a significant level of free cash flow generation for years into the future.

At Waskahigan, in the first quarter of this year, the Company continued to test enhanced well completion methods by conducting another slickwater hybrid fracture stimulation of a Montney horizontal well. This was the fifth slickwater completion tested by RMP on its Montney oil plays at Waskahigan and Grizzly. Four of the five slickwater tests completed to-date have yielded very encouraging early results. The Company’s acreage position at Waskahigan and Grizzly encompasses approximately 71 sections at 100% working interest providing for a future drilling inventory of approximately 200 locations (of which 18 proved undeveloped locations and 44 probable undeveloped locations were included in the year-end 2014 independent reserves report).

Year-End Reserves Information

RMP is pleased to provide information on its crude oil, natural gas and NGLs reserves as of December 31, 2014, 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. Unless stated otherwise, all reserves referred to in this news release are stated on a company gross basis (working interest before deduction of royalties and without including any royalty interests). More detailed information in respect of the Company’s reserves is included in RMP’s Annual Information Form for the year ended December 31, 2014. Highlights of RMP’s reserves include the following:

  • Proved plus probable oil and gas reserves increased 23% to 42.0 million boe (25.6 million boe proved) at year-end 2014, as compared to the 34.2 million boe (19.8 million boe proved) at December 31, 2013. This represents year-over-year proved plus probable and proved per share reserves growth (debt-adjusted) of 18% and 25%, respectively.
  • Added 12.1 million boe of proved plus probable reserves (10.2 million boe proved) in fiscal 2014, before production.
  • Replaced 282% of fiscal 2014 production with proved plus probable reserve additions (236% proved production replacement) with a finding, development and acquisition (“FD&A“) cost of $22.69 per proved plus probable boe ($21.26 per proved boe), including changes in future development costs (“FDC“) year-over-year, resulting in an operating netback recycle ratio of 1.8 times (1.9 times on a proved basis). The Company’s three-year average FD&A cost is $20.73 per proved plus probable boe ($24.52 per proved boe), including changes in FDC.
  • Significantly increased the Ante Creek proved plus probable reserves by 35% to 15.9 million boe (51% light oil weighted), as compared to 11.8 million boe at December 31, 2013. Proved developed producing reserves increased to 5.4 million boe from 2.2 million boe at December 31, 2013. Ante Creek finding and development costs in 2014 were $12.21 per proved plus probable boe ($13.55 per proved boe), resulting in a recycle ratio of 3.8 times for proved plus probable reserves (3.4 times for proved reserves) based on the realized Ante Creek field operating netback of $45.92 per boe in fiscal 2014.

Corporate Reserves Information

December 31, 2014 Reserves Summary (1) (company gross reserves)
Natural Gas Light Oil NGLs Oil Equivalent
(Columns may not add due to rounding) (Bcf ) (Mbbls ) (Mbbls ) (Mboe) (6:1 )
Proved developed producing 49.124 4,202.4 489.9 12,879.6
Proved developed non-producing 5.818 878.7 23.1 1,871.5
Proved undeveloped 41.404 3,574.2 384.7 10,859.5
Total Proved 96.346 8,655.3 897.7 25,610.6
Probable 54.934 6,936.6 270.1 16,362.3
Total Proved plus Probable 151.279 15,591.9 1,167.8 41,972.9
Note (1) Estimated using InSite’s forecast prices and costs as of December 31, 2014.
December 31, 2014 Net Present Value Summary (1) (company gross reserves)
(Columns may not add due to rounding)
Discount factor: 0% 5% 10% 15% 20%
Proved developed producing $ 304,089 $ 254,111 $ 219,926 $ 195,073 $ 176,191
Proved developed non-producing 39,475 29,989 23,729 19,294 15,982
Proved undeveloped 172,079 119,783 86,395 63,826 47,906
Total Proved 515,644 403,883 330,050 278,193 240,078
Probable 381,612 257,072 183,057 135,585 103,422
Total Proved plus Probable $ 897,256 $ 660,956 $ 513,107 $ 413,778 $ 343,500
Note (1) Net present values of future net revenue before taxes based on InSite’s forecast prices and costs as of December 31, 2014.

A summary of InSite’s escalated price forecast assumptions as of December 31, 2014 are as follows:

Edmonton Par
YEAR WTI @ Cushing Price 40 API AECO-C Propane Butane Condensate Inflation Rate Exchange Rate
$US/bbl $C/bbl C$/GJ $C/bbl $C/bbl $C/bbl % C$/US$
2015 65.00 68.58 3.40 34.29 48.01 75.44 2.0 0.8600
2016 75.00 80.07 3.94 40.03 56.05 86.47 2.0 0.8600
2017 80.00 85.74 4.20 42.87 60.02 90.88 2.0 0.8600
2018 85.00 91.41 4.47 45.70 63.99 96.89 2.0 0.8600
2019 90.00 97.07 4.74 48.54 67.95 102.90 2.0 0.8600
2020 95.00 102.74 5.00 51.37 71.92 108.90 2.0 0.8600
2021 96.90 104.79 5.27 52.40 73.35 111.08 2.0 0.8600
2022 98.84 106.89 5.37 53.44 74.82 113.30 2.0 0.8600
2023 100.81 109.02 5.48 54.51 76.32 115.57 2.0 0.8600
2024 102.83 111.21 5.59 55.60 77.84 117.88 2.0 0.8600
2025 104.89 113.43 5.70 56.71 79.40 120.24 2.0 0.8600
2026 106.99 115.70 5.81 57.85 80.99 122.64 2.0 0.8600
2027 109.13 118.01 5.93 59.01 82.61 125.09 2.0 0.8600
2028 111.31 120.37 6.05 60.19 84.26 127.59 2.0 0.8600
2029 113.53 122.78 6.17 61.39 85.95 130.15 2.0 0.8600
2030 115.80 125.24 6.29 62.62 87.66 132.75 2.0 0.8600
2031 118.12 127.74 6.42 63.87 89.42 135.40 2.0 0.8600
2032 120.48 130.29 6.55 65.15 91.21 138.11 2.0 0.8600

Net Asset Value

The Company’s net asset value details are as follows:

December 31, 2014 NPV 5% NPV 10%
(per share figures based on fully-diluted shares) ($000s) $/share ($000s) $/share
Proved plus probable reserves NPV (1,2) $ 660,956 $ 4.91 $ 513,107 $ 3.81
Undeveloped acreage (3) 169,868 1.26 169,868 1.26
Net debt (4) (123,450 ) (0.92 ) (123,450 ) (0.92 )
Proceeds from stock options and warrants(5) 51,083 0.38 51,083 0.38
Net Asset Value (fully-diluted) $ 758,457 $ 5.63 $ 610,608 $ 4.53
Notes:
(1) Evaluated by InSite as at December 31, 2014. 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, 2014.
(3) Independently-evaluated with average acreage value of $1,036 per acre.
(4) Net debt as at December 31, 2014, including working capital deficit (audited).
(5) Fully-diluted shares at December 31, 2014 total: including common shares of 122.13 million, 10.41 million stock options and 2.02 million stock warrants.

Capital Expenditures Efficiency and Future Development Costs (“FDC”)

Fiscal 2014
(amounts in $000s except reserve units and unit costs) Proved Proved + Probable
Exploration and development expenditures $ 187,104 $ 187,104
Acquisitions / (dispositions) (7,359 ) (7,359 )
Total capital expenditures (1) $ 179,745 $ 179,745
Future development cost – ending period (2) 177,625 359,675
Less: Future development cost – beginning period (2) (141,488 ) (264,269 )
All-in FD&A total, including change in FDC (3) $ 215,882 $ 275,151
Total F&D, excluding acquisitions / (dispositions) and including change in FDC(3) $ 223,241 $ 282,510
Total reserve additions (Mboe) 10,152.6 12,124.4
FD&A Costs ($/boe) $ 21.26 $ 22.69
F&D Costs ($/boe) $ 21.99 $ 23.30
Notes:
(1) Fiscal 2014 capital expenditures are audited and exclude non-cash capitalized share-based compensation expense of $2.0 million.
(2) Future development capital expenditures required to convert proved non-producing 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 reserves additions for that year.

The following table outlines the future development costs (“FDC“) required to bring proved and probable undeveloped reserves on-production. The FDC has been deducted in the estimation of future net revenue attributable to total proved reserves and total proved plus probable reserves (using forecast prices and costs).

Future Development Capital Costs(1)
(amounts in $000s) Total Proved Total Proved + Probable
2015 $ 64,510 $ 91,810
2016 51,410 105,175
2017 22,191 109,168
2018 39,514 53,522
Total undiscounted FDC $ 177,625 $ 359,675
Total discounted FDC at 10% per year $ 152,521 $ 302,688
Note (1) FDC as per InSite’s independent reserves evaluation as of December 31, 2014 and based on InSite’s forecast pricing as at December 31, 2014.

The Company expects to fund its future development cost requirements from internally-generated cash flow from operations and, as appropriate, from its existing committed bank credit facility, equity or debt financing. It is anticipated that the costs of funding the future development costs will not impact development of RMP’s properties or the Company’s reserves or future net revenue.

Pursuant to the requirements of NI 51-101 relating to issuer disclosure of finding and development (“F&D”) costs and finding, development and acquisition (“FD&A”)costs, the following outlines such costs for 2013, in addition to the average over the three-year period of 2012 to 2014.

Fiscal 2013 Three Year Average
(amounts in $000s except reserve units and unit costs) Proved Proved + Probable Proved Proved + Probable
Exploration and development expenditures (1) $ 132,282 $ 132,282 $ 415,244 $ 415,244
Acquisitions / (dispositions) 55,129 55,129 46,857 46,857
Total capital expenditures $ 187,411 $ 187,411 $ 462,101 $ 462,101
Future development cost – ending period (2) 141,488 264,269 177,625 359,675
Less: Future development cost – beginning period (2) (110,293 ) (205,081 ) (149,733 ) (239,855 )
All-in FD&A total, including change in FDC (3) $ 218,606 $ 246,599 $ 489,993 $ 581,921
Total F&D, excluding acquisitions / (dispositions) and including FDC (3) $ 163,477 $ 191,470 $ 443,136 $ 535,064
Total reserve additions (Mboe) 7,408.9 11,567.8 19,982.0 28,065.0
FD&A Costs ($/boe) $ 29.51 $ 21.32 $ 24.52 $ 20.73
F&D Costs ($/boe) $ 22.07 $ 16.55 $ 22.18 $ 19.07
Notes:
(1) Excludes non-cash capitalized share-based compensation expense.
(2) Future development capital expenditures required to convert proved non-producing reserves 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.

Ante Creek Montney Reserves Information

Based on InSite’s independent reserves evaluation, a total of 15.9 million boe of proved plus probable reserves weighted 51% light oil and NGLs (11.2 million boe proved) have been assigned at Ante Creek, as compared to 11.8 million boe of proved plus probable reserves weighted 82% light oil and NGLs (6.4 million boe proved) booked the previous year-end (December 31, 2013). Reserves booking at year-end 2014 consist of 21 proved developed wells and 17 drilling locations, with a breakdown as follows: 15 proved developed producing wells, six proved developed non-producing wells, 15 proved undeveloped locations and two probable undeveloped locations. Future development capital (undiscounted) associated with these proved plus probable reserves aggregate to $66.1 million ($59.7 million for proved undeveloped reserves). The gas weighting of the Ante Creek reserves increased year-over-year as a result of the increased producing gas-to-oil ratio experienced during 2014. The increased gas-to-oil ratio resulted in a recalculation of the recoverable natural gas solution reserves volumes for Ante Creek. RMP views these increased solution gas reserves positively as the incremental solution gas is expected to ultimately improve the oil recovery from Ante Creek. An average primary recovery factor of 8.2% was utilized in the determination of the proved plus probable light oil reserves at Ante Creek. The Company believes the primary recovery factor for its light oil reserves at Ante Creek will increase. A summary of the reserves assigned at Ante Creek as of December 31, 2014 is as follows:

Ante Creek Reserves (1) Reserves
(company gross reserves)
Net Present Value (2)
December 31, 2014 Solution Gas Light Oil & NGLs Oil Equivalent PV5% PV10%
(Bcf ) (Mbbls ) (Mboe)(6:1 ) ($000s ) ($000s )
Proved developed producing 16.298 2,635.2 5,351.6 $ 135,072 $ 118,919
Total Proved 32.712 5,795.3 11,247.3 $ 247,364 $ 208,344
Total Proved plus Probable 46.347 8,195.1 15,919.6 $ 358,908 $ 294,612
Notes:
(1) The estimates of reserves and future net revenue or net present value for individual properties may not reflect the same confidence level as estimates of reserves and net revenue or net present value for all properties due to the effects of aggregation.
(2) 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, 2014.

Waskahigan Montney Reserves Information

Based on InSite’s independent reserves evaluation, 13.8 million boe of proved plus probable reserves weighted 50% light oil (5.4 million boe of proved reserves) have been assigned to the Company’s Montney asset base at Waskahigan as at December 31, 2014, as compared to 11.4 million boe of proved plus probable reserves weighted 57% light oil (5.7 million boe proved) booked the previous year-end (December 31, 2013). Reserves booking at year-end 2014 consist of: 47 proved developed producing wells, two proved developed non-producing wells, 16 proved undeveloped locations and 41 probable undeveloped locations. Future development capital (undiscounted) associated with these proved plus probable reserves locations aggregate to $217.6 million ($61.2 million for proved undeveloped reserves).

A summary of the reserves assigned at Waskahigan as of December 31, 2014 is as follows:

Waskahigan Reserves (1) Reserves
(company gross reserves)
Net Present Value (2)
December 31, 2014 Solution Gas Light Crude Oil Oil Equivalent PV5% PV10%
(Bcf ) (Mbbls ) (Mboe)(6:1 ) ($000s ) ($000s )
Proved developed producing 9.861 1,485.8 3,129.2 $ 71,196 $ 60,369
Total Proved 16.450 2,642.3 5,383.9 $ 91,038 $ 72,600
Total Proved plus Probable 40.977 6,921.2 13,750.8 $ 206,690 $ 149,332
Notes:
(1) The estimates of reserves and future net revenue or net present value for individual properties may not reflect the same confidence level as estimates of reserves and net revenue or net present value for all properties due to the effects of aggregation.
(2) 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, 2014.

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/d Gigajoules per day
WTI West Texas Intermediate

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: RMP’s 2015 capital expenditure budget; 2015 forecasted WTI oil price, AECO gas price, RMP’s oil price discount and foreign exchange rate; 2015 corporate average daily production with crude oil and NGLs weighting; RMP’s year-end 2015 debt position; capital spending in the first quarter of 2015; Ante Creek project recycle economics; corporate, Waskahigan and Ante Creek future development capital costs; anticipated in-service date of the second Ante Creek gas handling and battery facility along with its estimated capital investment cost; the expected primary recovery factor of the Company’s light oil reserves at Ante Creek; and the number of drilling locations at Ante Creek and Waskahigan. 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 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.

In this news release, the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and net revenue for all properties due to the effects of aggregation. Estimates of reserves have been made assuming that development of each property, in respect of which estimates have been made, will occur without regard to the availability of funding required for that development.

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.

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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