CALGARY, ALBERTA--(Marketwired - March 19, 2014) - RMP Energy Inc. ("RMP" or the "Company") (TSX:RMP) is pleased to announce for the year ended December 31, 2013 reported funds from operations of $78.6 million ($0.72 per basic share) on revenue of $136.1 million and average daily production of 6,872 barrels of oil equivalent (53% light oil and NGLs weighted). Detailed results are as follows:
| Financial Results |
Fourth Quarterly Summary |
|
Yearly Summary |
|
| (thousands except share and per boe data) (6:1 oil equivalent conversion) |
Dec. 31, 2013 |
|
Dec. 31, 2012 |
|
% change |
|
Year 2013 |
|
Year 2012 |
|
% change |
|
| P&NG revenue (1) |
34,074 |
|
30,337 |
|
12 |
|
136,078 |
|
85,993 |
|
58 |
|
| Funds from operations (2) |
19,408 |
|
19,947 |
|
(3 |
) |
78,553 |
|
51,696 |
|
52 |
|
| |
Per share - basic |
0.17 |
|
0.19 |
|
(11 |
) |
0.72 |
|
0.52 |
|
38 |
|
| |
Per share - diluted |
0.16 |
|
0.19 |
|
(16 |
) |
0.68 |
|
0.52 |
|
31 |
|
| Net income (loss) |
2,452 |
|
(11,895 |
) |
- |
|
10,449 |
|
(7,819 |
) |
- |
|
| |
Per share - basic |
0.02 |
|
(0.11 |
) |
- |
|
0.10 |
|
(0.08 |
) |
- |
|
| |
Per share - diluted |
0.01 |
|
(0.11 |
) |
- |
|
0.09 |
|
(0.08 |
) |
- |
|
| E&D capital expenditures |
54,671 |
|
32,170 |
|
70 |
|
131,638 |
|
95,203 |
|
38 |
|
| Total capital expenditures |
93,091 |
|
32,473 |
|
187 |
|
187,411 |
|
94,946 |
|
97 |
|
| Net debt (3) - period end |
116,157 |
|
76,667 |
|
52 |
|
116,157 |
|
76,667 |
|
52 |
|
| Weighted average basic shares |
115,074,028 |
|
104,281,424 |
|
10 |
|
109,009,511 |
|
99,520,088 |
|
10 |
|
| Weighted average diluted shares |
122,403,243 |
|
104,281,424 |
|
17 |
|
115,244,968 |
|
99,520,088 |
|
16 |
|
| Issued and outstanding shares (4) |
118,096,756 |
|
104,281,424 |
|
13 |
|
118,096,756 |
|
104,281,424 |
|
13 |
|
| Operating Results |
|
|
|
|
|
|
|
|
|
|
|
|
| Average daily production: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas (Mcf/d) |
19,718 |
|
20,057 |
|
(2 |
) |
19,316 |
|
18,246 |
|
6 |
|
| |
Liquids (Oil & NGLs)(bbls/d) |
3,979 |
|
3,313 |
|
20 |
|
3,653 |
|
2,315 |
|
58 |
|
| |
Oil equivalent (boe/d) |
7,266 |
|
6,656 |
|
9 |
|
6,872 |
|
5,356 |
|
28 |
|
| Average sales price (1): |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas ($/Mcf) |
3.97 |
|
3.66 |
|
8 |
|
3.60 |
|
2.68 |
|
34 |
|
| |
Liquids (Oil & NGLs) ($/bbl) |
73.39 |
|
77.37 |
|
(5 |
) |
83.06 |
|
80.41 |
|
3 |
|
| |
Oil equivalent ($/boe) |
50.98 |
|
49.54 |
|
3 |
|
54.25 |
|
43.87 |
|
24 |
|
| Operating expenses ($/boe) |
7.00 |
|
7.26 |
|
(4 |
) |
7.22 |
|
7.97 |
|
(9 |
) |
| Operating netback (5) ($/boe) |
33.76 |
|
36.64 |
|
(8 |
) |
35.12 |
|
30.40 |
|
16 |
|
| Wells drilled: gross (net) |
5 (5.0 |
) |
6 (6.0 |
) |
(17 |
) |
18 (18.0 |
) |
17 (15.8 |
) |
6 |
|
Table Notes:
- Petroleum and natural gas ("P&NG") revenue and pricing includes realized gains or losses from risk management commodity contract settlements.
- 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.
- Net debt is not a recognized measure under IFRS. Please refer to the Reader Advisories at the end of the news release.
- As of March 19, 2014, 119.12 million common shares were outstanding.
- Operating netback is not a recognized measure under IFRS. Please refer to the Reader Advisories at the end of the news release.
Fourth Quarter and Fiscal 2013 Highlights
- Fourth quarter 2013 production averaged 7,266 boe/d, weighted 55% light oil and NGLs and 45% natural gas; an overall increase of 9% over the preceding third quarter 2013 production of 6,639 boe/d. Fiscal 2013 production averaged 6,872 boe/d, weighted 53% light oil and NGLs, as compared to the previous year of 5,356 boe/d (43% light oil and NGLs) and fiscal 2011 of 3,472 boe/d (25% light oil and NGLs). Please refer to Corporate Production Update section within this news release.
- Petroleum and natural gas revenue for the fourth quarter amounted to $34.1 million, of which 79% was derived from crude oil and NGLs (including a realized commodity hedging loss of $754 thousand). The Company's crude oil discount to the Canadian-dollar converted WTI price averaged $23.80/bbl during the fourth quarter, as compared to the $7.83/bbl in the preceding third quarter of 2013. The first quarter 2014 estimated crude oil discount, based on the near-term forward market, is approximately $14.00/bbl and the Company has budgeted an oil price differential average of $15.00/bbl for fiscal 2014. Petroleum and natural gas revenue for fiscal 2013 amounted to approximately $136.1 million (including an annual realized commodity hedging loss of $2.0 million), reflecting an increase of 58% over the $86.0 million in fiscal 2012.
- Petroleum and natural gas royalties amounted to $5.5 million (15% of petroleum and natural gas sales excluding a realized loss on risk management commodity contracts), as compared to $8.4 million (24% of petroleum and natural gas sales) in the preceding third quarter of 2013 and $2.1 million (7% of petroleum and natural gas sales) in the comparative fourth quarter of 2012. The Company's Crown royalty costs vary significantly quarter-over-quarter primarily as a result of the production performance of its Ante Creek oil wells. Horizontal wells producing on Alberta Crown acreage are initially eligible for the volume-based, 5% Crown royalty maximum provided by the Alberta Government under its drilling incentive program (typically the first 80,000 to 90,000 produced boe for RMP's wells). After a well produces through this cumulative volume, its royalty rate reverts to a calculated formula involving both market price and production rate, with a maximum well royalty rate of 40%. The effective royalty rate for the Ante Creek field in the fourth quarter was 25%, as compared to 38% in the preceding third quarter and 27% in the second quarter of 2013. For 2014, the Company is budgeting a field royalty rate for Ante Creek of 28%.
- Fourth quarter corporate operating costs of $7.00/boe decreased by 4% on a per boe basis, when compared to the operating costs for the fourth quarter of 2012 of $7.26/boe. Fiscal 2013 operating costs of $7.22/boe decreased by 9% on a per boe basis, when compared to operating costs for the previous year of $7.97/boe. Fiscal 2013 operating costs at RMP's Waskahigan and Ante Creek light oil fields were $6.46/boe and $3.83/boe, respectively.
- Quarterly funds from operations of $19.4 million ($0.17 per basic share) for the three months ended December 31, 2013. Funds from operations for fiscal 2013 were $78.6 million, an increase of 52% (38% per basic share) over fiscal 2012. For fiscal 2014, the Company is budgeting funds from operations of approximately $142 million ($1.20 per basic share).
- For the year ended December 31, 2013, RMP reported net income of $10.4 million, as compared to a net loss in fiscal 2012 of $7.8 million as a result of a year-end 2012 non-cash impairment charge of $18.5 million to its gas-weighted assets at Kaybob and Pine Creek due mainly to lower forecasted natural gas prices at that time.
- In fiscal 2013, the Company had capital expenditures of $187.4 million, including two strategic undeveloped land property purchases of $51.5 million in aggregate and $30.7 million incurred with the Ante Creek pipeline interconnect and infrastructure expansion. During 2013, RMP drilled seventeen (17.0 net) horizontal wells and a water disposal well. The Company's 2013 capital program resulted in an all-in finding and development cost of $21.32 per proved plus probable boe. Please refer to the Year-End Reserves Information disclosure hereafter. For fiscal 2014, RMP has set a capital spending budget of $130 million.
- At year-end 2013, the Company remained well capitalized with net debt outstanding of approximately $116.2 million, which included drawn bank debt of approximately $89.1 million. On December 23, 2013, RMP's borrowing limit under its bank credit facility was increased to $160 million from $140 million, facilitating additional financial flexibility and liquidity. As at March 18, 2014, the Company was drawn approximately $120 million on the bank credit facility.
The Company'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, 2013 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.
Ante Creek Drilling Update
Subsequent to RMP's last operations update, which was announced on February 27, 2014, the Company has drilled and completed two additional 100% working interest Montney formation horizontal oil wells, as described below.
RMP successfully drilled and completed a 'step-out' horizontal Montney light oil well located at 1-22-66-24W5. Subsequent to a multi-stage hydraulic fracture operation, the 1-22 well recovered all of the associated frac fluid during the initial 68 hour clean-up. During the subsequent 24 hour production test, the 1-22 well produced 1,220 bbls/d of 35 degree API light oil and 2.2 MMcf/d of associated solution gas for an oil equivalent rate of approximately 1,600 boe/d, with an average surface wellhead pressure of 600 psi. Please refer to important Reader Advisories at the end of this news release.
In addition to the 1-22 well, the Company successfully drilled and completed a development horizontal oil well located at 8-36-66-24W5. Following a multi-stage fracture stimulation, the 8-36 well recovered all of the frac fluid during the initial 48 hour clean-up. Subsequently, prior to installing the final production string which is presently underway, the 8-36 well produced 2,200 bbls of 36 degree API light oil over a 33 hour period, for an average daily rate of 1,600 bbls/d and 5.4 MMcf/d of associated solution gas for an oil equivalent rate of approximately 2,500 boe/d. The 8-36 well flowed at an average surface wellhead pressure of 750 psi. Please refer to important Reader Advisories at the end of this news release.
Corporate Production Update
On March 1, 2014, RMP started-up its expanded battery facility and pipeline interconnect at Ante Creek and began delivering oil and associated natural gas into the downstream sales receipt point through its Ante Creek-to-Waskahigan pipeline. Concurrently, the Company is trucking crude oil from its Ante Creek battery in excess of the deliveries though the pipeline.
RMP's corporate average daily production has exceeded 12,000 boe/d since the infrastructure start-up with only six of twelve Ante Creek wells presently on-production. Despite current production levels exceeding the Company's budget, RMP is not increasing its fiscal 2014 production guidance at this time, as the Company would like to establish more production history from the Ante Creek wells. Additionally, trucking oil is still required at Ante Creek due to capacity limitations on the crude oil sales system downstream of RMP's Waskahigan battery. The Company expects 'spring break-up' imposed road bans to limit crude oil trucking and temper its production output during the months of April, May and potentially June. For fiscal 2014, the Company is budgeting daily production to average 10,000 boe/d (weighted 68% light oil and NGLs), a 46% increase over fiscal 2013. Production during the second half of this year is budgeted to exceed 12,000 boe/d, weighted 70% light oil and NGL's.
Year-End Reserves Information
RMP is pleased to provide information on its crude oil, natural gas and NGLs reserves as of December 31, 2013, 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, 2013. Highlights of RMP's reserves include the following:
- Added 11.6 million boe of proved plus probable reserves (7.4 million boe proved) in fiscal 2013, before production, for a reserve replacement ratio of 461% (295% proved).
- Year-end 2013 total proved plus probable oil and gas reserves increased to 34.2 million boe (19.8 million boe total proved), as compared to the 25.1 million boe (14.9 million boe total proved) at December 31, 2012. Proved developed producing reserves increased to 9.9 million boe, as compared to 8.2 million boe at December 31, 2012.
- Increased the Ante Creek area Montney proved plus probable reserves to 11.8 million boe (82% light oil weighted), as compared to 4.5 million boe at December 31, 2012. Ante Creek finding and development costs in 2013, excluding non-reserves capital related to the pipeline interconnect and battery expansion and undeveloped land purchases, were $8.30 per proved plus probable boe ($11.25 per proved boe), resulting in a recycle ratio of 5.3 times for proved plus probable reserves (3.9 times for proved reserves) based on the realized Ante Creek field operating netback of $44.45 per boe in fiscal 2013. Including the pipeline interconnect and battery expansion capital of $30.7 million, Ante Creek finding and development costs increase to $11.93 per proved plus probable boe ($17.21 per proved boe) with a recycle ratio of 3.7 times for proved plus probable reserves (2.6 times for proved reserves).
- Replaced 461% of fiscal 2013 production with proved plus probable reserve additions (295% total proved production replacement) with an all-in finding and development ("F&D") costs of $21.32 per proved plus probable boe ($29.51 per proved boe), including non-reserves capital related to the pipeline interconnect and battery expansion ($30.7 million) and the capital spent on two strategic undeveloped land property purchases ($51.5 million) and changes in future development costs ("FDC") year-over-year. Finding and development ("F&D") costs, excluding capital related to the pipeline interconnect and battery expansions and undeveloped land purchases and including changes in future development costs ("FDC") year-over-year are $14.21 per proved plus probable boe ($18.41 per proved boe), resulting in a recycle ratio of 2.5 times proved plus probable boe (1.9 times proved boe). RMP 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. Please refer to Finding and Development Costs table disclosure hereafter for calculation details.
- RMP's year-end 2013 net asset value increased to $5.97 per share (discounted 5%) and $4.69 per share (discounted 10%) (fully-diluted). Please refer to Net Asset Value table disclosure hereafter for calculation details.
Corporate Reserves Information
| December 31, 2013 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 |
32.723 |
|
4,010.9 |
|
453.3 |
|
9,918.0 |
|
| Proved developed non-producing |
3.539 |
|
755.1 |
|
23.4 |
|
1,368.3 |
|
| Proved undeveloped |
24.936 |
|
3,990.9 |
|
325.4 |
|
8,472.4 |
|
| Total Proved |
61.198 |
|
8,756.9 |
|
802.1 |
|
19,758.7 |
|
| Probable |
36.141 |
|
8,073.8 |
|
293.1 |
|
14,390.4 |
|
| Total Proved plus Probable |
97.339 |
|
16,830.7 |
|
1,095.2 |
|
34,149.1 |
|
| Note (1) Estimated using InSite's forecast prices and costs as of December 31, 2013. |
|
| |
| December 31, 2013 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 |
$ 290,924 |
|
$ 238,231 |
|
$ 204,229 |
|
$ 180,513 |
|
$ 162,999 |
| Proved developed non-producing |
47,949 |
|
43,841 |
|
40,771 |
|
38,351 |
|
36,371 |
| Proved undeveloped |
203,002 |
|
126,768 |
|
86,086 |
|
61,239 |
|
44,685 |
| Total Proved |
541,875 |
|
408,840 |
|
331,086 |
|
280,103 |
|
244,055 |
| Probable |
476,449 |
|
298,285 |
|
208,733 |
|
156,136 |
|
121,953 |
| Total Proved plus Probable |
$ 1,018,324 |
|
$ 707,125 |
|
$ 539,819 |
|
$ 436,238 |
|
$ 366,008 |
| Note (1) Net present values of future net revenue before taxes based on InSite's forecast prices and costs as of December 31, 2013. |
| |
| |
| A summary of InSite's escalated price forecast assumptions as of December 31, 2013 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
Rate (% |
) |
Exchange
Rate (US$/C$ |
) |
| 2014 |
96.00 |
|
96.05 |
|
3.99 |
|
48.03 |
|
76.84 |
|
103.74 |
|
2.0 |
|
0.9500 |
|
| 2015 |
95.00 |
|
97.50 |
|
4.14 |
|
53.63 |
|
78.00 |
|
103.35 |
|
2.0 |
|
0.9500 |
|
| 2016 |
95.00 |
|
97.45 |
|
4.50 |
|
53.60 |
|
77.96 |
|
103.30 |
|
2.0 |
|
0.9500 |
|
| 2017 |
95.00 |
|
97.40 |
|
4.75 |
|
53.57 |
|
77.92 |
|
103.24 |
|
2.0 |
|
0.9500 |
|
| 2018 |
96.00 |
|
98.40 |
|
5.01 |
|
54.12 |
|
78.72 |
|
104.30 |
|
2.0 |
|
0.9500 |
|
| 2019 |
97.00 |
|
99.40 |
|
5.26 |
|
54.67 |
|
79.52 |
|
105.36 |
|
2.0 |
|
0.9500 |
|
| 2020 |
98.94 |
|
101.39 |
|
5.37 |
|
55.76 |
|
81.11 |
|
107.47 |
|
2.0 |
|
0.9500 |
|
| 2021 |
100.92 |
|
103.41 |
|
5.47 |
|
56.88 |
|
82.73 |
|
109.62 |
|
2.0 |
|
0.9500 |
|
| 2022 |
102.94 |
|
105.48 |
|
5.58 |
|
58.02 |
|
84.39 |
|
111.81 |
|
2.0 |
|
0.9500 |
|
| 2023 |
105.00 |
|
107.59 |
|
5.69 |
|
59.18 |
|
86.07 |
|
114.05 |
|
2.0 |
|
0.9500 |
|
| 2024 |
107.10 |
|
109.74 |
|
5.81 |
|
60.36 |
|
87.80 |
|
116.33 |
|
2.0 |
|
0.9500 |
|
| 2025 |
109.24 |
|
111.94 |
|
5.92 |
|
61.57 |
|
89.55 |
|
118.66 |
|
2.0 |
|
0.9500 |
|
| 2026 |
111.42 |
|
114.18 |
|
6.04 |
|
62.80 |
|
91.34 |
|
121.03 |
|
2.0 |
|
0.9500 |
|
| 2027 |
113.65 |
|
116.46 |
|
6.16 |
|
64.05 |
|
93.17 |
|
123.45 |
|
2.0 |
|
0.9500 |
|
| 2028 |
115.92 |
|
118.79 |
|
6.29 |
|
65.34 |
|
95.03 |
|
125.92 |
|
2.0 |
|
0.9500 |
|
| 2029 |
118.24 |
|
121.17 |
|
6.41 |
|
66.64 |
|
96.93 |
|
128.44 |
|
2.0 |
|
0.9500 |
|
| 2030 |
120.61 |
|
123.59 |
|
6.54 |
|
67.97 |
|
98.87 |
|
131.01 |
|
2.0 |
|
0.9500 |
|
| 2031 |
123.02 |
|
126.06 |
|
6.67 |
|
69.33 |
|
100.85 |
|
133.63 |
|
2.0 |
|
0.9500 |
|
| Thereafter |
Escalation rate of 2.0% |
|
Net Asset Value
The Company's net asset value details are as follows:
| December 31, 2013 |
NPV 5% |
|
NPV 10% |
|
| (per share figures based on fully-diluted shares) |
($000s |
) |
$/share |
|
($000s |
) |
$/share |
|
| Proved plus probable reserves NPV (1,2) |
$ 707,125 |
|
$ 5.42 |
|
$ 539,819 |
|
$ 4.14 |
|
| Undeveloped acreage (3) |
160,248 |
|
1.23 |
|
160,248 |
|
1.23 |
|
| Net debt (4) |
(116,157 |
) |
(0.89 |
) |
(116,157 |
) |
(0.89 |
) |
| Proceeds from stock options and warrants (5) |
28,331 |
|
0.21 |
|
28,331 |
|
0.21 |
|
| Net Asset Value (fully-diluted) |
$ 779,547 |
|
$ 5.97 |
|
$ 612,241 |
|
$ 4.69 |
|
| Notes: |
|
|
|
|
|
|
|
|
| (1) Evaluated by InSite as at December 31, 2013. 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, 2013. |
|
| (3) Independently-evaluated with average acreage value of $1,210 per acre. |
|
| (4) Net debt as at December 31, 2013, including working capital deficit (audited). |
|
| (5) Fully-diluted shares at December 31, 2013 total: including outstanding common shares of 119.12 million and 11.39 million stock options and warrants. |
|
Finding and Development Costs
The following highlights the Company's finding and development ("F&D") costs in 2013:
| F&D Costs |
Fiscal 2013 |
|
| (amounts in $000s except reserve units and unit costs) |
Proved |
|
Proved + Probable |
|
| Exploration and development expenditures |
$ 104,575 |
|
$ 104,575 |
|
| Ante Creek pipeline and battery expansion expenditures |
30,687 |
|
30,687 |
|
| Undeveloped land property purchases |
51,505 |
|
51,505 |
|
| Capitalized general and administrative and office costs |
644 |
|
644 |
|
| Total finding and development expenditures (1) |
$ 187,411 |
|
$ 187,411 |
|
| Future development cost - ending period (2) |
141,488 |
|
264,269 |
|
| Less: Future development cost - beginning period (2) |
(110,293 |
) |
(205,081 |
) |
| All-in total, including change in future development cost (3) |
$ 218,606 |
|
$ 246,599 |
|
| Total reserve additions (Mboe) |
7,408.9 |
|
11,567.8 |
|
| F&D Costs ($/boe) |
$ 29.51 |
|
$ 21.32 |
|
| F&D Costs ($/boe) - excluding Ante Creek pipeline and battery expansion expenditures and property purchases, net |
$ 18.41 |
|
$ 14.21 |
|
| Notes: |
|
| (1) Total capital expenditures for fiscal 2013 are audited and exclude non-cash capitalized share-based compensation expense of $1.05 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 |
| 2014 |
$ 72,950 |
|
$ 124,450 |
| 2015 |
27,999 |
|
49,470 |
| 2016 |
30,979 |
|
55,532 |
| 2017 and subsequent |
9,560 |
|
34,817 |
| Total undiscounted FDC |
$ 141,488 |
|
$ 264,269 |
| Total discounted FDC at 10% per year |
$ 126,045 |
|
$ 231,530 |
| Note (1) FDC as per InSite's independent reserves evaluation as of December 31, 2013 and based on InSite's forecast pricing as at December 31, 2013. |
| Future Development Capital Costs by Area(1) |
| |
Total Proved + Probable
FDC ($000s |
) |
Gross Booked Locations |
|
Net Booked Locations |
| Waskahigan |
$ 125,429 |
|
30 |
|
30.0 |
| Ante Creek |
67,904 |
|
15 |
|
15.0 |
| Grizzly |
25,060 |
|
6 |
|
6.0 |
| Kaybob |
31,014 |
|
8 |
|
6.7 |
| Pine Creek |
12,738 |
|
3 |
|
2.4 |
| Other |
2,124 |
|
1 |
|
1.0 |
| Total |
$ 264,269 |
|
63 |
|
61.1 |
| Note (1) Total proved plus probable FDC as per InSite's independent reserves evaluation as of December 31, 2013 and based on InSite's forecast pricing as at December 31, 2013. |
| |
| 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 2012, in addition to the average over the three-year period of 2011 to 2013. |
| |
| F&D Costs |
Fiscal 2012 |
|
Three Year Average |
|
| (amounts in $000s except reserve units and unit costs) |
Proved |
|
Proved + Probable |
|
Proved |
|
Proved + Probable |
|
| Total finding and development expenditures (1) |
$ 94,946 |
|
$ 94,946 |
|
$ 383,357 |
|
$ 383,357 |
|
| Future development cost - ending period (2) |
110,293 |
|
205,081 |
|
141,488 |
|
264,269 |
|
| Less: Future development cost - beginning period (2) |
(149,734 |
) |
(239,855 |
) |
(81,953 |
) |
(97,573 |
) |
| All-in total, including change in FDC (3) |
$ 55,505 |
|
$ 60,172 |
|
$ 442,893 |
|
$ 550,054 |
|
| Reserve additions - including revisions (Mboe) |
2,420.6 |
|
4,372.8 |
|
14,959.7 |
|
23,200.6 |
|
| Total F&D Costs - including reserves revisions ($/boe) |
$ 22.93 |
|
$ 13.76 |
|
$ 29.61 |
|
$ 23.71 |
|
| 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 the independent reserves evaluation by InSite, 11.8 million boe of proved plus probable reserves weighted 82% light oil and NGLs (6.4 million boe proved) have been assigned at Ante Creek, as compared to 4.5 million boe of proved plus probable reserves (2.3 million boe proved) booked the previous year-end (December 31, 2012). Reserves booking at year-end 2013 consist of: eight proved developed producing wells, eight proved undeveloped locations and seven probable undeveloped locations. Future development capital (undiscounted) associated with these proved plus probable reserves locations aggregate to $53.5 million ($28.4 million for proved undeveloped reserves).
A summary of the reserves assigned at Ante Creek as of December 31, 2013 is as follows.
| Ante Creek Reserves (1) |
Reserves
(company gross reserves) |
|
Net Present Value (2) |
|
| December 31, 2013 |
Solution Gas |
|
Light Oil & NGLs |
|
Oil Equivalent |
|
PV5% |
|
PV10% |
|
| |
(Bcf |
) |
(Mbbls |
) |
(Mboe)(6:1 |
) |
($000s |
) |
($000s |
) |
| Proved developed producing |
2.496 |
|
1,813.6 |
|
2,229.5 |
|
$ 71,089 |
|
$ 63,233 |
|
| Total Proved |
7.131 |
|
5,247.6 |
|
6,436.0 |
|
$ 201,923 |
|
$ 167,921 |
|
| Total Proved plus Probable |
12.709 |
|
9,678.2 |
|
11,796.3 |
|
$ 354,180 |
|
$ 278,880 |
|
| 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, 2013. |
|
Waskahigan Montney Reserves Information
In 2013, the Company successfully drilled ten (10.0 net) horizontal oil wells at Waskahigan. Nine of these wells were previously booked at year-end 2012 as either proved undeveloped and probable undeveloped locations. As a result, at year-end 2013 they were re-categorized as proved developed producing. Based on InSite's independent reserves evaluation, 11.4 million boe of proved plus probable reserves (5.7 million boe of proved reserves) have been assigned to the Company's Montney asset base at Waskahigan as at December 31, 2013, as compared to 10.7 million boe of proved plus probable reserves (5.3 million boe proved) booked the previous year-end (December 31, 2012).
Reserves booking at year-end 2013 consist of: forty proved producing wells, eleven proved undeveloped locations and nineteen probable undeveloped locations. Future development capital (undiscounted) associated with these proved plus probable reserves locations aggregate to $125.4 million ($45.7 million for proved undeveloped reserves).
A summary of the reserves assigned at Waskahigan as of December 31, 2013 is as follows.
| Waskahigan Reserves (1) |
Reserves
(company gross reserves) |
|
Net Present Value (2) |
|
| December 31, 2013 |
Solution Gas |
|
Light Crude Oil |
|
Oil Equivalent |
|
PV5% |
|
PV10% |
|
| |
(Bcf |
) |
(Mbbls |
) |
(Mboe)(6:1 |
) |
($000s |
) |
($000s |
) |
| Proved developed producing |
10.687 |
|
2,135.9 |
|
3,917.0 |
|
$ 114,133 |
|
$ 96,214 |
|
| Total Proved |
15.210 |
|
3,195.0 |
|
5,730.0 |
|
$ 137,417 |
|
$ 111,108 |
|
| Total Proved plus Probable |
29.628 |
|
6,455.6 |
|
11,393.5 |
|
$ 247,970 |
|
$ 186,866 |
|
| 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, 2013. |
|
Executive Retirement
The Company announces the retirement of Mr. Ross MacDonald, Vice-President Engineering, effective May 1, 2014. Mr. MacDonald has been an executive of RMP since the restructuring of Orleans Energy in May, 2011 and his career extends over thirty years in the oil and gas business. He has been a key member of the management team for over twenty years. The Company's board of directors and his fellow RMP employees would like to thank him for his outstanding service and wish him all the best in his retirement. The Company intends to hire a replacement for Mr. MacDonald during the second quarter of this year. In the interim, his duties will be assumed by Mr. Derek Riddell, RMP's Vice-President, Operations.
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: 2014 budgeted and forecasted items including the first quarter crude oil price discount, the Ante Creek field royalty rate, funds from operations in aggregate and per basic share, capital expenditures, and full year and second half corporate average daily production with crude oil and NGLs weighting; Waskahigan and Ante Creek light oil project recycle economics and accelerated capital payouts; corporate and Ante Creek future development capital costs; and, estimated corporate average daily production since the start-up of the Ante Creek pipeline and battery expansion. 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. Field operating netback or operating netback is not a recognized measure under IFRS and does not have a standardized meaning.