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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| Forum Uranium Corp (delisted) | TSXV:FDC | TSX Venture | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0 | - |
Hot Features
Premium
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
----------------------------------------------------------------------------
(thousands except share and per
boe data) (6:1 oil equivalent
conversion) Dec. 31, 2013 Dec. 31, 2012 % change
----------------------------------------------------------------------------
P&NG revenue (1) 34,074 30,337 12
----------------------------------------------------------------------------
Funds from operations (2) 19,408 19,947 (3)
----------------------------------------------------------------------------
Per share - basic 0.17 0.19 (11)
----------------------------------------------------------------------------
Per share - diluted 0.16 0.19 (16)
----------------------------------------------------------------------------
Net income (loss) 2,452 (11,895) -
----------------------------------------------------------------------------
Per share - basic 0.02 (0.11) -
----------------------------------------------------------------------------
Per share - diluted 0.01 (0.11) -
----------------------------------------------------------------------------
E&D capital expenditures 54,671 32,170 70
----------------------------------------------------------------------------
Total capital expenditures 93,091 32,473 187
----------------------------------------------------------------------------
Net debt (3) - period end 116,157 76,667 52
----------------------------------------------------------------------------
Weighted average basic shares 115,074,028 104,281,424 10
----------------------------------------------------------------------------
Weighted average diluted shares 122,403,243 104,281,424 17
----------------------------------------------------------------------------
Issued and outstanding shares
(4) 118,096,756 104,281,424 13
----------------------------------------------------------------------------
Operating Results
----------------------------------------------------------------------------
Average daily production:
----------------------------------------------------------------------------
Natural gas (Mcf/d) 19,718 20,057 (2)
----------------------------------------------------------------------------
Liquids (Oil & NGLs)(bbls/d) 3,979 3,313 20
----------------------------------------------------------------------------
Oil equivalent (boe/d) 7,266 6,656 9
----------------------------------------------------------------------------
Average sales price (1):
----------------------------------------------------------------------------
Natural gas ($/Mcf) 3.97 3.66 8
----------------------------------------------------------------------------
Liquids (Oil & NGLs) ($/bbl) 73.39 77.37 (5)
----------------------------------------------------------------------------
Oil equivalent ($/boe) 50.98 49.54 3
----------------------------------------------------------------------------
Operating expenses ($/boe) 7.00 7.26 (4)
----------------------------------------------------------------------------
Operating netback (5) ($/boe) 33.76 36.64 (8)
----------------------------------------------------------------------------
Wells drilled: gross (net) 5 (5.0) 6 (6.0) (17)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial Results Yearly Summary
----------------------------------------------------------------------------
(thousands except share and per
boe data) (6:1 oil equivalent
conversion) Year 2013 Year 2012 % change
----------------------------------------------------------------------------
P&NG revenue (1) 136,078 85,993 58
----------------------------------------------------------------------------
Funds from operations (2) 78,553 51,696 52
----------------------------------------------------------------------------
Per share - basic 0.72 0.52 38
----------------------------------------------------------------------------
Per share - diluted 0.68 0.52 31
----------------------------------------------------------------------------
Net income (loss) 10,449 (7,819) -
----------------------------------------------------------------------------
Per share - basic 0.10 (0.08) -
----------------------------------------------------------------------------
Per share - diluted 0.09 (0.08) -
----------------------------------------------------------------------------
E&D capital expenditures 131,638 95,203 38
----------------------------------------------------------------------------
Total capital expenditures 187,411 94,946 97
----------------------------------------------------------------------------
Net debt (3) - period end 116,157 76,667 52
----------------------------------------------------------------------------
Weighted average basic shares 109,009,511 99,520,088 10
----------------------------------------------------------------------------
Weighted average diluted shares 115,244,968 99,520,088 16
----------------------------------------------------------------------------
Issued and outstanding shares
(4) 118,096,756 104,281,424 13
----------------------------------------------------------------------------
Operating Results
----------------------------------------------------------------------------
Average daily production:
----------------------------------------------------------------------------
Natural gas (Mcf/d) 19,316 18,246 6
----------------------------------------------------------------------------
Liquids (Oil & NGLs)(bbls/d) 3,653 2,315 58
----------------------------------------------------------------------------
Oil equivalent (boe/d) 6,872 5,356 28
----------------------------------------------------------------------------
Average sales price (1):
----------------------------------------------------------------------------
Natural gas ($/Mcf) 3.60 2.68 34
----------------------------------------------------------------------------
Liquids (Oil & NGLs) ($/bbl) 83.06 80.41 3
----------------------------------------------------------------------------
Oil equivalent ($/boe) 54.25 43.87 24
----------------------------------------------------------------------------
Operating expenses ($/boe) 7.22 7.97 (9)
----------------------------------------------------------------------------
Operating netback (5) ($/boe) 35.12 30.40 16
----------------------------------------------------------------------------
Wells drilled: gross (net) 18 (18.0) 17 (15.8) 6
----------------------------------------------------------------------------
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 19, 2014, 119.12 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 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 Oil
Gas Light Oil NGLs 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:
----------------------------------------------------------------------------
WTI Cushing Edmonton Par Natural Gas NGLs Edmonton
Oklahoma Price 40 API AECO-C Price Propanes
Year (US$/bbl) (C$/bbl) (C$/mmbtu) (C$/bbl)
----------------------------------------------------------------------------
2014 96.00 96.05 3.99 48.03
----------------------------------------------------------------------------
2015 95.00 97.50 4.14 53.63
----------------------------------------------------------------------------
2016 95.00 97.45 4.50 53.60
----------------------------------------------------------------------------
2017 95.00 97.40 4.75 53.57
----------------------------------------------------------------------------
2018 96.00 98.40 5.01 54.12
----------------------------------------------------------------------------
2019 97.00 99.40 5.26 54.67
----------------------------------------------------------------------------
2020 98.94 101.39 5.37 55.76
----------------------------------------------------------------------------
2021 100.92 103.41 5.47 56.88
----------------------------------------------------------------------------
2022 102.94 105.48 5.58 58.02
----------------------------------------------------------------------------
2023 105.00 107.59 5.69 59.18
----------------------------------------------------------------------------
2024 107.10 109.74 5.81 60.36
----------------------------------------------------------------------------
2025 109.24 111.94 5.92 61.57
----------------------------------------------------------------------------
2026 111.42 114.18 6.04 62.80
----------------------------------------------------------------------------
2027 113.65 116.46 6.16 64.05
----------------------------------------------------------------------------
2028 115.92 118.79 6.29 65.34
----------------------------------------------------------------------------
2029 118.24 121.17 6.41 66.64
----------------------------------------------------------------------------
2030 120.61 123.59 6.54 67.97
----------------------------------------------------------------------------
2031 123.02 126.06 6.67 69.33
----------------------------------------------------------------------------
Thereafter Escalation rate of 2.0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NGLs Edmonton NGLs Edmonton
Butanes Condensate Inflation Exchange
Year (C$/bbl) (C$/bbl) Rate (%) Rate (US$/C$)
----------------------------------------------------------------------------
2014 76.84 103.74 2.0 0.9500
----------------------------------------------------------------------------
2015 78.00 103.35 2.0 0.9500
----------------------------------------------------------------------------
2016 77.96 103.30 2.0 0.9500
----------------------------------------------------------------------------
2017 77.92 103.24 2.0 0.9500
----------------------------------------------------------------------------
2018 78.72 104.30 2.0 0.9500
----------------------------------------------------------------------------
2019 79.52 105.36 2.0 0.9500
----------------------------------------------------------------------------
2020 81.11 107.47 2.0 0.9500
----------------------------------------------------------------------------
2021 82.73 109.62 2.0 0.9500
----------------------------------------------------------------------------
2022 84.39 111.81 2.0 0.9500
----------------------------------------------------------------------------
2023 86.07 114.05 2.0 0.9500
----------------------------------------------------------------------------
2024 87.80 116.33 2.0 0.9500
----------------------------------------------------------------------------
2025 89.55 118.66 2.0 0.9500
----------------------------------------------------------------------------
2026 91.34 121.03 2.0 0.9500
----------------------------------------------------------------------------
2027 93.17 123.45 2.0 0.9500
----------------------------------------------------------------------------
2028 95.03 125.92 2.0 0.9500
----------------------------------------------------------------------------
2029 96.93 128.44 2.0 0.9500
----------------------------------------------------------------------------
2030 98.87 131.01 2.0 0.9500
----------------------------------------------------------------------------
2031 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 Proved +
unit costs) 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 Gross Booked Net Booked
FDC ($000s) Locations 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 Proved + Proved +
units and unit costs) Proved Probable 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.
----------------------------------------------------------------------------
Reserves Net Present Value
Ante Creek Reserves (1) (company gross reserves) (2)
----------------------------------------------------------------------------
December 31, 2013 Solution Light Oil Oil
Gas & NGLs 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.
----------------------------------------------------------------------------
Reserves Net Present Value
Waskahigan Reserves (1) (company gross reserves) (2)
----------------------------------------------------------------------------
Solution Light Oil
December 31, 2013 Gas Crude 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 barrel or barrels Mcf/d thousand cubic feet per
bbls 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 psi pounds per square inch
equivalent
----------------------------------------------------------------------------
boe/d barrels of oil equivalent kPa kilopascals
per day
----------------------------------------------------------------------------
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.
FOR FURTHER INFORMATION PLEASE CONTACT:
RMP Energy Inc.
John Ferguson
President and Chief Executive Officer
(403) 930-6303
john.ferguson@rmpenergyinc.com
RMP Energy Inc.
Dean Bernhard
Vice President, Finance and Chief Financial Officer
(403) 930-6304
dean.bernhard@rmpenergyinc.com
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