RMP Energy Announces Fiscal 2012 and Fourth Quarter Financial Results and Provides Year-End Reserves and Operations Update
CALGARY, ALBERTA--(Marketwire - March 13, 2013) - RMP Energy Inc. ("RMP" or the "Company") (RMP.TO) is pleased to announce its fiscal 2012 and fourth quarter financial results and provide information on its year-end crude oil and natural gas reserves in addition to an operations and hedging update.
Fiscal 2012 and Fourth Quarter 2012 Financial Results
For the year ended December 31, 2012, RMP reported funds from operations of $51.7 million ($0.52 per fully-diluted share) on revenue of $86.0 million and average daily production of 5,356 barrels of oil equivalent (43% light oil and NGLs weighted). Detailed results are as follows:
Financial Results | Quarterly Summary | Fiscal Summary | |||||||||||||
(thousands except share and per boe data) (6:1 oil equivalent conversion) | Dec. 31, 2012 | Sept. 30, 2012 | % change | Dec. 31, 2011 | Year 2012 | Year 2011 | % change | ||||||||
P&NG revenue (1) | 30,337 | 19,511 | 55 | 18,474 | 85,993 | 49,511 | 74 | ||||||||
Funds from operations (2) | 19,947 | 11,789 | 69 | 11,558 | 51,696 | 24,406 | 112 | ||||||||
Per share - basic & diluted | 0.19 | 0.12 | 58 | 0.12 | 0.52 | 0.30 | 73 | ||||||||
Net loss | (11,895 | ) | (1,164 | ) | - | (70,980 | ) | (7,819 | ) | (74,974 | ) | (90 | ) | ||
Per share - basic & diluted | (0.11 | ) | (0.01 | ) | - | (0.75 | ) | (0.08 | ) | (0.93 | ) | (91 | ) | ||
Total capital expenditures | 32,473 | 25,805 | 26 | 42,688 | 94,946 | 134,897 | (30 | ) | |||||||
Net debt (3) - period end | 76,667 | 64,069 | 20 | 49,087 | 76,667 | 49,087 | 56 | ||||||||
Weighted average basic shares | 104,281,424 | 100,225,439 | 4 | 95,233,832 | 99,520,088 | 80,455,353 | 24 | ||||||||
Weighted average diluted shares | 104,281,424 | 100,225,439 | 4 | 95,233,832 | 99,520,088 | 80,455,353 | 24 | ||||||||
Issued and outstanding shares (4) | 104,281,424 | 104,281,424 | - | 96,647,655 | 104,281,424 | 96,647,655 | 8 | ||||||||
Operating Results | |||||||||||||||
Average daily production: | |||||||||||||||
Natural gas (Mcf/d) | 20,057 | 17,874 | 12 | 19,337 | 18,246 | 15,568 | 17 | ||||||||
Liquids (Oil & NGLs)(bbls/d) | 3,313 | 1,988 | 67 | 1,496 | 2,315 | 877 | 164 | ||||||||
Oil equivalent (boe/d) | 6,656 | 4,967 | 34 | 4,719 | 5,356 | 3,472 | 54 | ||||||||
Average sales price (1): | |||||||||||||||
Natural gas ($/Mcf) | 3.66 | 2.47 | 48 | 3.41 | 2.68 | 3.86 | (31 | ) | |||||||
Liquids (Oil & NGLs) ($/bbl) | 77.37 | 84.52 | (8 | ) | 90.11 | 80.41 | 86.22 | (7 | ) | ||||||
Oil equivalent ($/boe) | 49.54 | 42.70 | 16 | 42.56 | 43.87 | 39.07 | 12 | ||||||||
Operating expenses ($/boe) | 7.26 | 9.04 | (20 | ) | 8.21 | 7.97 | 9.56 | (17 | ) | ||||||
Operating netback (5) ($/boe) | 36.64 | 29.55 | 24 | 31.35 | 30.40 | 23.66 | 28 | ||||||||
Wells drilled: gross (net) | 6 (6.0 | ) | 4 (3.4 | ) | 50 | 7 (5.8 | ) | 17 (15.8 | ) | 18 (15.0 | ) | (6 | ) | ||
Table Notes:
(1) | Petroleum and natural gas ("P&NG") revenue and pricing includes any 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 12, 2013, 104.28 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. |
Highlights
Fourth quarter 2012 production averaged 6,656 boe/d, weighted 47% light oil, 3% NGLs and 50% natural gas; an overall increase of 34% over the third quarter 2012 production of 4,967 boe/d. The increase is attributable to the successful development of the Company's light oil properties at Waskahigan and Ante Creek, which has enabled RMP's crude oil weighting for the fourth quarter to increase to 47%, as compared to an oil production weighting of 25% in the fourth quarter 2011.
Petroleum and natural gas revenue for the fourth quarter amounted to $30.3 million (including a realized oil hedging gain of $758 thousand), of which 78% was derived from crude oil and NGLs sales. The Company's realized crude oil discount differential to the Canadian-dollar converted WTI price averaged $9.84/bbl during the fourth quarter. Petroleum and natural gas revenue for fiscal 2012 amounted to approximately $86.0 million (including a realized oil hedging gain of $1.3 million), an increase of 74% over the $49.5 million in fiscal 2011.
In fiscal 2012, the Company incurred net capital expenditures of approximately $95 million. RMP drilled seventeen (15.8 net) horizontal wells and a water disposal well in 2012. The Company's 2012 capital program resulted in a finding and development cost of $13.76 per proved plus probable boe (please refer to the Year-End Reserves Information disclosure hereafter).
The Company was drawn $69.0 million on its bank lines as at December 31, 2012 and had negative working capital of $7.7 million for a year-end net debt total of $76.7 million. As at March 12, 2013, RMP was drawn approximately $76 million on the bank facility, which presently has a $110 million borrowing base limit.
RMP reported quarterly funds from operations of approximately $20 million ($0.19 per share) for the three months ended December 31, 2012, up 69% in aggregate (58% per share) from funds from operations for the preceding third quarter of 2012. Funds from operations for fiscal 2012 were $51.7 million, an increase of 112% (73% per share) over fiscal 2011.
For the year ended December 31, 2012, RMP reported a net loss of $7.8 million. The net loss is primarily a result of an $18.5 million non-cash impairment charge to its gas-weighted assets at Greater Kaybob and West Central Alberta, which includes Pine Creek, mainly due to lower forecasted natural gas prices.
The Company's audited consolidated financial statements and associated Management's Discussion and Analysis for the year ended December 31, 2012 is available on RMP's website at www.rmpenergyinc.com within "Investors" under "Financials". Additionally, these documents have been 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.
Year-End Reserves Information
RMP is pleased to provide information on its crude oil and natural gas reserves as of December 31, 2012, 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 will be included in RMP's Annual Information Form for the year ended December 31, 2012, which will be filed on the Company's SEDAR profile before March 31, 2013. Highlights of RMP's reserves include the following:
Added 4.37 million boe of proved plus probable reserves (2.42 million boe proved) in 2012, before production, for a reserve replacement ratio of 223% (123% proved).
Total proved plus probable oil and gas reserves increased to 25.09 million boe (14.86 million boe total proved), as compared to the 22.68 million boe (14.39 million boe total proved) at December 31, 2011. Proved developed producing reserves increased to 8.23 million boe, as compared to 7.01 million boe at December 31, 2011.
Increased the Ante Creek area Montney reserves to 4.46 million boe (88% light oil weighted), as compared to 844 thousand boe at December 31, 2011 (proved plus probable). Ante Creek finding and development costs in 2012 were $10.20 per proved plus probable boe ($14.49 per proved), resulting in a recycle ratio of 5.7 times proved plus probable (4.0 times proved) based on the realized Ante Creek field operating netback of $58.10 per boe in 2012.
As a result of a very successful light oil drilling program in 2012, achieved all-in finding, and development ("F&D") costs of $13.76 per proved plus probable boe ($22.93 per proved boe), including changes in future development costs ("FDC"), resulting in a recycle ratio of 2.2 times proved plus probable boe (1.3 times proved boe). Using the fourth quarter 2012 field operating netback of $36.64 per boe, which is more representative of the Company's current oil and gas production composition, the recycle ratio increases to 2.7 times proved plus probable boe (1.6 times proved boe). Future development costs decreased by 14% to $205.1 million, as compared to December 31, 2011 FDC of $239.9 million (proved plus probable). The Company continues to direct capital towards light oil drilling at Waskahigan and Ante Creek, which provide for project recycle economics of greater than two times and five times, respectively, and accelerated capital payouts.
Despite a year-over-year decrease in the forward price deck utilized by InSite for both light oil (approximately 6% lower) and natural gas (approximately 17% lower), RMP's year-end 2012 net asset value increased to $4.09 per share (discounted 8%) and $3.68 per share (discounted 10%) (fully-diluted), as compared to $3.93 per share and $3.47 per share, respectively, at the prior year-end of 2011 (please refer to Net Asset Value table disclosure hereafter for calculation details).
Corporate Reserves Information
December 31, 2012 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 | 27.809 | 3,147.3 | 448.3 | 8,230.5 | ||||
Proved developed non-producing | 3.192 | - | 56.5 | 588.4 | ||||
Proved undeveloped | 19.383 | 2,523.1 | 285.5 | 6,039.1 | ||||
Total Proved | 50.384 | 5,670.4 | 790.3 | 14,858.0 | ||||
Probable | 25.917 | 5,621.8 | 290.2 | 10,231.5 | ||||
Total Proved plus Probable | 76.301 | 11,292.2 | 1,080.5 | 25,089.5 | ||||
Note (1) | Estimated using InSite's forecast prices and costs as of December 31, 2012. |
December 31, 2012 Net Present Value Summary (company gross reserves) | |||||||||||||||
(Columns may not add due to rounding) | |||||||||||||||
Discount factor: | 0 | % | 8 | % | 10 | % | 12 | % | 15 | % | |||||
Proved developed producing | $ | 250,752 | $ | 183,939 | $ | 173,238 | $ | 164,005 | $ | 152,326 | |||||
Proved developed non-producing | 7,763 | 4,645 | 4,159 | 3,746 | 3,234 | ||||||||||
Proved undeveloped | 148,377 | 55,497 | 43,998 | 34,747 | 23,914 | ||||||||||
Total Proved | 406,891 | 244,082 | 221,395 | 202,498 | 179,474 | ||||||||||
Probable | 383,344 | 171,308 | 146,426 | 126,584 | 103,493 | ||||||||||
Total Proved plus Probable | $ | 790,235 | $ | 415,390 | $ | 367,820 | $ | 329,082 | $ | 282,967 | |||||
Note (1) | Estimated using InSite's forecast prices and costs as of December 31, 2012. |
A summary of InSite's escalated price forecast assumptions as of December 31, 2012 are as follows:
Year | WTI Cushing Oklahoma (US$/bbl | ) | Edmonton Par Price 40 API (C$/bbl | ) | Natural Gas AECO-C Price (C$/mmbtu | ) | NGLs Edmonton Propanes (C$/bbl | ) | NGLs Edmonton Butanes (C$/bbl | ) | NGLs Edmonton Condensate (C$/bbl | ) | Inflation | %) | Exchange | ) | |
2013 | 92.00 | 90.00 | 3.34 | 36.00 | 76.50 | 97.20 | 2.0 | 1.000 | |||||||||
2014 | 94.00 | 91.96 | 3.83 | 45.98 | 78.17 | 97.48 | 2.0 | 1.000 | |||||||||
2015 | 96.00 | 93.92 | 4.33 | 56.35 | 79.83 | 99.55 | 2.0 | 1.000 | |||||||||
2016 | 98.00 | 95.88 | 4.77 | 57.53 | 81.50 | 101.63 | 2.0 | 1.000 | |||||||||
2017 | 100.00 | 97.84 | 5.11 | 58.70 | 83.16 | 103.71 | 2.0 | 1.000 | |||||||||
2018 | 102.00 | 99.79 | 5.40 | 59.88 | 84.82 | 105.78 | 2.0 | 1.000 | |||||||||
2019 | 104.04 | 101.79 | 5.64 | 61.07 | 86.52 | 107.89 | 2.0 | 1.000 | |||||||||
2020 | 106.12 | 103.82 | 5.83 | 62.29 | 88.25 | 110.05 | 2.0 | 1.000 | |||||||||
2021 | 108.24 | 105.90 | 5.95 | 63.54 | 90.01 | 112.25 | 2.0 | 1.000 | |||||||||
2022 | 110.41 | 108.02 | 6.07 | 64.81 | 91.82 | 114.50 | 2.0 | 1.000 | |||||||||
2023 | 112.62 | 110.18 | 6.19 | 66.11 | 93.65 | 116.79 | 2.0 | 1.000 | |||||||||
2024 | 114.87 | 112.38 | 6.31 | 67.43 | 95.52 | 119.12 | 2.0 | 1.000 | |||||||||
2025 | 117.17 | 114.63 | 6.44 | 68.78 | 97.44 | 121.51 | 2.0 | 1.000 | |||||||||
2026 | 119.51 | 116.92 | 6.57 | 70.15 | 99.38 | 123.94 | 2.0 | 1.000 | |||||||||
2027 | 121.90 | 119.26 | 6.70 | 71.56 | 101.37 | 126.42 | 2.0 | 1.000 | |||||||||
2028 | 124.34 | 121.65 | 6.83 | 72.99 | 103.40 | 128.94 | 2.0 | 1.000 | |||||||||
2029 | 126.82 | 124.08 | 6.97 | 74.45 | 105.47 | 131.52 | 2.0 | 1.000 | |||||||||
2030 | 129.36 | 126.56 | 7.11 | 75.94 | 107.58 | 134.15 | 2.0 | 1.000 | |||||||||
Thereafter | Escalation rate of 2.0 | % | |||||||||||||||
Net Asset Value
The Company's net asset value details are as follows:
December 31, 2012 | NPV 8% | NPV 10% | ||||||||||
(per share figures based on fully-diluted shares) | $ | (000s | ) | $ | /share | $ | (000s | ) | $ | /share | ||
Proved plus probable reserves NPV (1,2) | $ | 415,390 | $ | 3.56 | $ | 367,820 | $ | 3.15 | ||||
Undeveloped acreage (3) | 113,078 | 0.97 | 113,078 | 0.97 | ||||||||
Net debt (4) | (76,667 | ) | (0.66 | ) | (76,667 | ) | (0.66 | ) | ||||
Proceeds from stock options and warrants (5) | 25,439 | 0.22 | 25,439 | 0.22 | ||||||||
Net Asset Value (fully-diluted) | $ | 477,240 | $ | 4.09 | $ | 429,670 | $ | 3.68 | ||||
Notes: | |
(1) | Evaluated by InSite as at December 31, 2012. 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, 2012. |
(3) | Independently-evaluated with average acreage value of $1,025 per acre. |
(4) | Net debt as at December 31, 2012, including working capital deficit (audited). |
(5) | Fully-diluted shares at December 31, 2012 total: including outstanding common shares of 104,281,424 and 12,349,005 stock options and warrants. |
Finding and Development Costs
The following highlights the Company's finding and development ("F&D") costs in 2012:
F&D Costs | Fiscal 2012 | |||||
(amounts in $000s except reserve units and unit costs) | Proved | Proved + Probable | ||||
Exploration and development expenditures | $ | 95,203 | $ | 95,203 | ||
Property divestiture | (912 | ) | (912 | ) | ||
Capitalized general and administrative and office costs | 655 | 655 | ||||
Total finding and development expenditures (1) | $ | 94,946 | $ | 94,946 | ||
Future development cost - ending period (2) | 110,293 | 205,081 | ||||
Less: Future development cost - beginning period (2) | (149,734 | ) | (239,855 | ) | ||
All-in total, including change in future development cost (3) | $ | 55,505 | $ | 60,172 | ||
Total reserve additions (Mboe) | 2,420.6 | 4,372.8 | ||||
F&D Costs ($/boe) | $ | 22.93 | $ | 13.76 | ||
Notes: | |
(1) | Total capital expenditures for fiscal 2012 are audited and exclude non-cash capitalized share-based compensation expense of $1.82 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 are summaries of InSite's estimated future development capital ("FDC") required to bring proved and probable undeveloped reserves on production.
Future Development Capital Costs(1) | ||||
(amounts in $000s) | Total Proved | Total Proved + Probable | ||
2013 | $ | 53,689 | $ | 84,689 |
2014 | 17,850 | 76,388 | ||
2015 | 20,028 | 25,278 | ||
2016 and subsequent | 18,726 | 18,726 | ||
Total undiscounted FDC | $ | 110,293 | $ | 205,081 |
Total discounted FDC at 10% per year | $ | 95,140 | $ | 180,813 |
Note (1) | FDC as per InSite's independent reserves evaluation as of December 31, 2012 and based on InSite's forecast pricing as at December 31, 2012. |
Future Development Capital Costs by Area(1) | |||||
Total Proved + Probable | Gross Locations | Net Locations | |||
Waskahigan / Grizzly | $ | 128,791 | 30 | 29.7 | |
Ante Creek | 30,272 | 7 | 7.0 | ||
Kaybob | 33,069 | 8 | 6.7 | ||
Pine Creek | 10,712 | 2 | 2.0 | ||
Other | 2,237 | 2 | 1.7 | ||
Total | $ | 205,081 | 49 | 47.1 | |
Note (1) | Total proved plus probable FDC as per InSite's independent reserves evaluation as of December 31, 2012 and based on InSite's forecast pricing as at December 31, 2012. |
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 2011, in addition to the average over the three-year period of 2010 to 2012.
F&D Costs | 2011 | Three Year Average | ||||||||||
(amounts in $000s except reserve units and unit costs) | Proved | Proved + Probable | Proved | Proved + Probable | ||||||||
Total finding and development expenditures (1) | $ | 101,001 | $ | 101,001 | $ | 213,224 | $ | 213,224 | ||||
Future development cost - ending period (2) | 149,734 | 239,855 | 110,293 | 205,081 | ||||||||
Less: Future development cost - beginning period (2) | (81,953 | ) | (97,573 | ) | (71,502 | ) | (111,820 | ) | ||||
All-in total, including change in FDC (3) | $ | 168,782 | $ | 243,283 | $ | 252,015 | $ | 306,485 | ||||
Reserve additions - including revisions (Mboe) | 5,130.3 | 7,260.1 | 8,118.1 | 9,776.5 | ||||||||
Total F&D Costs - including reserves revisions ($/boe) | $ | 32.90 | $ | 33.51 | $ | 31.04 | $ | 31.35 | ||||
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. |
Waskahigan Montney Reserves Information
In 2012, the Company successfully drilled eleven (11.0 net) horizontal oil wells at Waskahigan in West Central Alberta. These wells were previously booked at year-end 2011 as proved undeveloped locations. As a result, at year-end 2012 they were re-categorized as proved developed producing, fostering the net present value economics of the Waskahigan field.
Based on InSite's independent reserves evaluation, 10.68 million boe of proved plus probable reserves (5.32 million boe proved) have been assigned to the Company's Montney asset base at Waskahigan as at December 31, 2012. Of the Company's 37 gross (37.0 net) sections of contiguous land held as at December 31, 2012, reserves were assigned to 17 sections, consisting of 27 proved producing wells, 12 proved undeveloped locations and 17 probable undeveloped locations. Future development capital (undiscounted) associated with these proved plus probable reserves aggregate to $124.56 million ($50.74 million for proved undeveloped reserves), a $65.68 million decrease from the future development capital booked at year-end 2011 (proved plus probable). The Company has identified a drilling inventory of approximately 120 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, 2012 is as follows.
Waskahigan Reserves | Reserves | Net Present Value (1) | ||||||||||||
December 31, 2012 | Solution Gas | Light Crude Oil | Oil Equivalent | PV5 | % | PV10 | % | |||||||
(Bcf | ) | (Mbbls | ) | (Mboe)(6:1 | ) | $ | (000s | ) | $ | (000s | ) | |||
Proved developed producing | 6.717 | 2,313.2 | 3,433.4 | $ | 112,579 | $ | 93,800 | |||||||
Total Proved | 10.381 | 3,593.4 | 5,324.4 | $ | 147,167 | $ | 112,634 | |||||||
Total Proved plus Probable | 20.346 | 7,286.4 | 10,678.7 | $ | 280,563 | $ | 196,935 | |||||||
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, 2012. |
Ante Creek Montney Reserves Information
Last year marked a significant year in the on-going delineation of RMP's Montney light oil asset at Ante Creek in West Central Alberta. As previously disclosed, an additional two horizontal oil wells (100% working interest) were successfully drilled and tested in 2012 (13-26-66-24W5 and 1-36-66-24W5) as follow-up to the initial Montney discovery well (4-35-66-24W5). As a result, based on the independent reserves evaluation by InSite, 4.46 million boe of proved plus probable reserves weighted 88% light oil (2.34 million boe proved) have been assigned at Ante Creek, as compared to 0.84 million boe of proved plus probable reserves (0.47 million boe proved) booked the previous year-end (December 31, 2011). Reserves booking at year-end 2012 consist of three proved developed producing wells, four proved undeveloped locations and three offset probable undeveloped locations. Future development capital (undiscounted) associated with these proved plus probable reserves aggregate to $30.27 million ($17.20 million for proved undeveloped reserves).
Ante Creek finding and development costs in 2012, including change in future development cost, were $10.20 per proved plus probable boe ($14.49 per proved), resulting in a recycle ratio of 5.7 times proved plus probable (4.0 times proved) based on a realized Ante Creek field operating netback of $58.10 per boe in 2012.
At Ante Creek, the Company holds a contiguous, 100% working interest, six section acreage position and has drilled an additional two (2.0 net) horizontal oil wells in the first quarter of 2013 (please refer to Ante Creek Operations Update commentary hereafter). Based on down-spacing to four wells per section, there are a potential 19 additional horizontal locations on RMP's lands. Augmenting this inventory is the potential to down-space drill to eight wells per section, as area operators have undertaken similar increased drilling densities in the Montney formation.
A summary of the reserves assigned at Ante Creek as of December 31, 2012 is as follows.
Ante Creek Reserves | Reserves | Net Present Value (1) | ||||||||||||
December 31, 2012 | Solution Gas | Light Oil & NGLs | Oil Equivalent | PV5 | % | PV10 | % | |||||||
(Bcf | ) | (Mbbls | ) | (Mboe)(6:1 | ) | $ | (000s | ) | $ | (000s | ) | |||
Proved developed producing | 0.904 | 840.3 | 990.9 | $ | 39,361 | $ | 36,505 | |||||||
Total Proved | 1.789 | 2,045.4 | 2,343.7 | $ | 72,234 | $ | 57,148 | |||||||
Total Proved plus Probable | 3.225 | 3,918.0 | 4,455.5 | $ | 132,640 | $ | 101,739 | |||||||
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, 2012. |
Corporate Production Update
Field estimated average daily production for the first two months of 2013 was approximately 6,600 boe/d, weighted 50% light oil, 3% NGLs and 47% natural gas, which reflects the second Ante Creek oil well coming on-stream during the first week of February. On February 28, 2013, a segment of the Peace Pipeline crude oil system downstream of RMP's Waskahigan battery experienced an unscheduled outage, impacting the oil volumes delivered by the Company. The pipeline operator has indicated that they anticipate the line to resume operating service on or about March 15, 2013. RMP has been mitigating the impact of this outage through oil trucking from both its Waskahigan and Ante Creek oil batteries. The Company remains on-track to achieve its fiscal 2013 guided average daily production target of 6,000 to 6,500 boe/d.
Waskahigan Operations Update
In the first quarter of this year, RMP drilled three (3.0 net) Waskahigan Montney horizontal oil wells (two infill and one step-out). The wells were successfully completed with production test results as expected. All three wells have been tied into the Company's field infrastructure and are awaiting resumption of the Peace Pipeline service in order to commence production flow.
Overall, the Company has drilled a total of thirty (30.0 net) Montney horizontal oil wells at Waskahigan with 100% success. RMP continues to expand and foster critical mass with its Montney light oil resource project at Waskahigan. The Company's acreage position at Waskahigan encompasses 37 contiguous sections at 100% working interest providing for a future light oil drilling inventory of approximately 120 locations.
RMP has recently expanded the oil processing capability at its 100% company-owned Waskahigan oil battery. This expansion is expected to facilitate the oil handling and processing of future production additions at Waskahigan, provide for the handling of third-party volumes and will allow the Company to truck oil from Ante Creek to the facility at its operational discretion.
Ante Creek Operations Update
At Ante Creek, RMP continues to experience drilling success with the Montney formation. Thus far this year, the Company has drilled and completed an additional two horizontal wells (2.0 net) located at 13-27-66-24W5 and 5-35-66-24W5.
The 13-27 well was recently flow-tested and over the forty-two hour flow back clean-up, the well recovered all of the fluid used for fracture stimulation. During the final twenty-four hours of the new oil production test, the well produced approximately 1,150 bbls/d of 35 degree API crude oil and approximately 3.0 MMcf/d of associated solution gas for a total of approximately 1,650 boe/d at a strong average flowing tubing wellhead pressure of 1,000 psi. Please refer to important Reader Advisories at the end of this news release.
The 5-35 well was also recently completed and is presently undertaking new oil production flow test operations. Prior to snubbing out the frac string to put in-place production tubing, the 5-35 well recovered all of its frac fluid during the forty-six hour flow back clean-up. Over the next 14 hour new oil production flow test, the 5-35 well test rate was approximately 2,000 bbls/d of 35 degree API crude oil and 2.6 MMcf/d of associated solution gas, corresponding to a daily average of approximately 2,400 boe/d at an average flowing tubing wellhead pressure of 760 psi. Please refer to important Reader Advisories at the end of this news release.
To-date, the Company now has five, 100% working interest light oil wells drilled at Ante Creek. In February 2013, the expansion of both RMP's Ante Creek oil battery and the non-operated, solution gas gathering line downstream of the battery was completed. As a result, the Company has been producing two wells concurrently. RMP continues to evaluate alternatives to increase the Company's production take-away capacity in the area. As previously disclosed, RMP has secured firm service capacity at an area operator's gas plant, providing for the processing of its Montney solution gas production. Firm service of 3.5 MMcf/d has been negotiated for calendar 2013, with 2.0 MMcf/d locked-in for both calendar 2014 and 2015.
Grizzly Operations Update
At Grizzly, to the southeast of Waskahigan, RMP successfully drilled and completed its second horizontal oil well located at 4-5-63-22W5 (100% working interest). The 4-5 well was drilled to a total measured depth of 3,913 metres, with 1,409 metres of horizontal section. Completion operations encompassed an 18 stage, 218 tonne fracture stimulation (average 12 tonnes per stage). Over the first fifty-one hour flow back, the 4-5 well recovered all of the fluid used to fracture the well. During the final twenty-four hours of a 92 hour new oil production test, it produced approximately 550 bbls/d of 42 degree API light crude oil and 1.9 MMcf/d of associated solution gas for a total of approximately 870 boe/d at an average flowing tubing wellhead pressure of 290 psi. Over the duration of the new oil production test, the 4-5 well produced approximately 3,600 bbls of light oil. Please refer to important Reader Advisories at the end of this news release.
The Grizzly 4-5 well is expected to be tied-in and flowing into third-party area infrastructure by May 1, 2013. At Grizzly, the Company holds a 100% working interest position on 12.25 sections (7,840 acres) of land for mineral rights which include the Montney formation, however, exclude the deep rights.
Hedging Update
In order to ensure the Company's cash flow is protected from lower-than-budgeted crude oil prices, for calendar 2013, RMP has 1,500 bbls/d of crude oil hedged with a fixed Nymex WTI price of $97.65 Canadian per bbl. Additionally, on the gas side, the Company has 5,000 GJs/d hedged at a fixed AECO price of $3.05/GJ during the summer injection season (April 1 - October 31, 2013).
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 new release contains forward looking information relating to: Waskahigan and Ante Creek light oil project recycle economics and accelerated capital payouts, Ante Creek finding and development costs and recycle ratios, identified drilling locations at Ante Creek and Waskahigan, the capability and uses of the Company's expanded oil processing capabilities at Waskahigan, estimated corporate average daily production for the first two months of 2013 and the associated commodity weighting, estimated corporate average daily production for fiscal 2013, the timing of the resumption of service of the Peace Pipeline crude oil system and the timing of the Grizzly 4-5 well tie-in and on-stream date. 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.
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.
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 and changes in non-cash working capital from operating activities. 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 plus working capital deficit or less any working capital surplus (excludes current unrealized amounts pertaining to risk management commodity 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 ("boe"). Field operating netback or Operating netback is not a recognized measure under IFRS and does not have a standardized meaning.
