FOR: RMP ENERGY INC.
TSX SYMBOL: RMP
Date issue: March 21, 2017
Time in: 8:09 PM e
Attention:
CALGARY, ALBERTA–(Marketwired – March 21, 2017) – RMP Energy Inc. (“RMP” or
the “Company”) (TSX:RMP) is pleased to provide an update on its first quarter
2017 field operations and to announce its year-end independent reserves
evaluation in addition to its financial results for the fourth quarter and
fiscal year ended December 31, 2016.
OPERATIONS UPDATE
Waskahigan Montney, West Central Alberta
At Waskahigan in the first quarter of 2017, RMP successfully drilled and
completed a 100% working interest Montney ‘step-out’ horizontal oil well (13-
30 -63-23W5), located on the western flank of the Company’s acreage position.
The flow test result from the recently completed hybrid slick-water operation
was strong. Production flow testing was for a 200-hour period (approximately 8
days). Over the last 72 hours of the production test, the 13-30 well tested at
an average rate of approximately 760 bbls/d of 40-degree API crude oil and 1.5
MMcf/d of associated sweet solution gas for an oil-equivalent rate of
approximately 1,000 boe/d. RMP expects to have the 13-30 well tied into
company-owned infrastructure and placed on-production later this week. The
Company expects to book and assign proved developed reserves to this well and
recognize proved undeveloped and probable undeveloped reserves for future
locations offsetting the 13-30 well, none of which were booked or assigned in
the year-end 2016 independent reserves report.
At Waskahigan, the Company’s hybrid slick-water completions have resulted in
improved well productivity, and corresponding improvement in well project
economics. In addition to the 13-30 well, the Company is budgeted to drill
three more (3.0 net) Montney horizontal wells at Waskahigan this year. In the
first quarter of 2017, the Company increased its acreage position by five (5.0
net) sections (3,200 gross acres), and its land base at Waskahigan now consists
of 78.5 (77.6 net) sections (50,240 gross acres) of operated acreage. RMP
estimates its future Waskahigan drilling inventory to consist of approximately
200 potential unbooked and undeveloped drilling locations (of which only 47
locations have assigned proved and/or probable reserves in the Company’s
year-end 2016 independent reserves report).
Elmworth (Gold Creek) Montney, West Central Alberta
At Elmworth (formerly known as Gold Creek) during the first quarter of 2017,
the Company commenced the strategic delineation of the areal extent of the
hydrocarbon-bearing Middle Montney reservoir oil window.
As follow-up to last year’s successful exploration well (3-22-68-3W6), RMP
drilled two more wells at Elmworth. A 100% working interest, exploration well
(8-25-68-4W6) was drilled and completed with hybrid slick-water, approximately
one township to the west of the Company’s 3-22 well. The 8-25 well production
test results were successful, with flow-back results indicating the discovery
of a new oil pool and demonstrating the Middle Montney reservoir to be oil
bearing and gas charged. The 8-25 well was drilled to a total measured depth of
4,523 metres, with 2,208 metres of horizontal section. The production flow test
was for a 173-hour period (approximately seven days). Over the last 72 hours of
the production test, the 8-25 well tested at an average rate of approximately
220 bbls/d of 45-degree API crude oil and approximately 1.0 MMcf/d of natural
gas, resulting in an oil-equivalent rate of approximately 390 boe/d. Please
refer to Reader Advisories at the end of this news release.
The Company also successfully drilled and completed its third, 100% working
interest well in the Middle Montney oil window at Elmworth (4-18-68-2W6).
Drilled from the same surface lease pad as the 3-22 well, the 4-18 well is a
‘step-out’ to the southeast. The 4-18 delineation well, drilled to a total
measured depth of 4,935 metres with 2,518 metres of horizontal length, was
fracture stimulated with hybrid slick-water. The production flow test was for a
165-hour period (approximately seven days). Over the last 72 hours of the
production test, the 4-18 well tested at an average rate of approximately 200
bbls/d of 45-degree API crude oil and 2.3 MMcf/d of natural gas, resulting in
an oil-equivalent rate of approximately 600 boe/d. Please refer to Reader
Advisories at the end of this news release.
In addition to delineation drilling of its Montney acreage, RMP also secured
strategic infrastructure in the Elmworth area for hydrocarbon egress. As
previously disclosed, the Company has entered into gathering, processing and
transportation agreements with a regional mid-stream service provider to handle
RMP’s Elmworth crude oil and natural gas production. The agreements encompass
an area dedication and are not subject to take-or-pay commitments. The
mid-stream company is in the process of installing a gathering system in order
to connect their existing infrastructure to RMP’s oil battery facility located
at 2-23-68-3W6, which is presently undergoing construction. The Company’s
Elmworth natural gas will be processed at the mid-stream company’s Patterson
Creek Gas Plant, which will undergo expansion later this year with an expected
capacity level of 150 MMcf/d. This gas plant will provide pipeline connections
for sales gas into both the TransCanada and Alliance gas systems. Oil volumes
will be transported downstream of the gas plant with connectivity to a Pembina
crude oil sales terminal. Barring any unforeseen delays, the gathering pipeline
and oil battery facility is scheduled to be commissioned and operational in May
2017.
At Elmworth, RMP has now successfully drilled and completed three (3.0 net)
Middle Montney horizontal wells. The Company has a large undeveloped land base
consisting of 79 (78.5 net) sections (50,560 gross acres) of operated acreage.
RMP estimates that it has potentially in excess of 300 unbooked and undeveloped
drilling locations at Elmworth (of which only six locations have assigned
proved and/or probable reserves in the Company’s year-end 2016 independent
reserves report). With drilling and completion results to-date, and continued
exploration and development activity, Elmworth has the potential to be a
long-term production and reserves growth asset for RMP.
Updated Market Guidance and 2017 Capital Budget
For 2017, the Company is budgeting to incur $49 million in exploration and
development capital expenditures. In addition to key infrastructure investment
at Elmworth, the 2017 capital plan includes the drilling of three (3.0 net)
Middle Montney horizontal wells at Elmworth, of which two have been drilled
already, and four (4.0 net) Montney horizontal wells at Waskahigan, of which
one has been drilled to-date. The focus of the capital budget for the first
half of this year is to maintain corporate base production levels through a
pared-back level of drilling operations at Waskahigan while de-risking and
delineating its large Elmworth resource potential with the strategic objective
of establishing additional inventory and scale for the Company. Infrastructure
commissioning at Elmworth is expected to bolster RMP’s base production levels
thereafter, providing production momentum for the second half of this year and
into fiscal 2018. For the second half of this year, the Company is forecasting
production to average approximately 4,500 boe/d (weighted 42% light crude oil
and NGLs).
YEAR-END 2016 RESERVES
The following provides information on RMP’s crude oil, natural gas and NGLs
reserves as of December 31, 2016, 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). The reported reserves at December 31, 2016 exclude reserves that
were disposed of in connection with the sale of the Company’s Ante Creek asset
(the “Ante Creek Disposition”), which closed on November 15, 2016. The
Company’s year-end 2016 reserves highlights include the following:
/T/
— Total proved plus probable reserves at December 31, 2016 were 27.7
million boe. The Ante Creek Disposition (9.8 million boe), fiscal 2016
production (2.9 million boe) and a minor Pine Creek divestiture (1.2
million boe), partially offset by positive additions (net of revisions)
of 3.1 million boe, resulted in lower reserves reported at year-end 2016
as compared to 38.5 million boe of proved plus probable reserves at
December 31, 2015. Adjusting for production and the reserves disposed
with the Ante Creek Disposition, total proved plus probable reserves
increased year-over-year.
— Total proved reserves at December 31, 2016 were 16.4 million boe. The
Ante Creek Disposition (6.6 million boe), fiscal 2016 production (2.9
million boe) and a minor Pine Creek divestiture (0.7 million boe),
partially offset by positive additions (net of revisions) of 1.2 million
boe, resulted in lower reserves reported at year-end 2016 as compared to
25.3 million boe of proved reserves at December 31, 2015. Adjusting for
production and the reserves disposed with the Ante Creek Disposition,
total proved reserves increased year-over-year.
— Total proved developed producing reserves at December 31, 2016 were 6.8
million boe, as compared to 15.1 million boe at December 31, 2015. The
Ante Creek Disposition (6.2 million boe), a minor Pine Creek divestiture
(0.1 million boe) and fiscal 2016 production (2.9 million boe) were
partially offset by positive additions (net revisions) of approximately
1.0 million boe. Adjusting for production and the reserves disposed with
the Ante Creek Disposition, total proved developed producing reserves
increased year-over-year.
— RMP’s net asset value at December 31, 2016 is estimated at $2.19 per
share (discounted at 10%). Refer to the detailed calculation under the
Net Asset Value heading hereafter.
— Booked and assigned initial reserves at Elmworth (formerly Gold Creek)
at December 31, 2016, of 4.7 million boe proved plus probable and 1.5
million boe proved.
— Achieved finding and development (“F&D”) costs of $18.45 per proved plus
probable boe, including changes in future development capital (“FDC”).
Refer to the detailed calculation under the Capital Expenditures
Efficiency heading hereafter.
/T/
Corporate Reserves Information
/T/
—————————————————————————-
December 31, 2016 Reserves Summary (1) (company gross reserves)
—————————————————————————-
Natural Oil
Gas (2) Oil (3) NGLs Equivalent
—————————————————————————-
(Columns may not add due to (Mboe)
rounding) (Bcf) (Mbbls) (Mbbls) (6:1)
—————————————————————————-
Proved developed producing 28.438 1,590.7 474.3 6,804.6
—————————————————————————-
Proved developed non-producing 3.298 202.1 47.6 799.3
—————————————————————————-
Proved undeveloped 34.684 2,496.6 480.8 8,758.0
—————————————————————————-
Total Proved 66.419 4,289.4 1,002.7 16,361.9
—————————————————————————-
Probable 41.285 4,037.5 421.1 11,339.5
—————————————————————————-
Total Proved plus Probable 107.705 8,326.9 1,423.8 27,701.4
—————————————————————————-
(1) Estimated using InSite’s forecast prices and costs as of December 31,
2016.
—————————————————————————-
(2) Includes conventional natural gas and shale gas.
—————————————————————————-
(3) Substantially all tight oil.
—————————————————————————-
—————————————————————————-
December 31, 2016 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 $ 110,932 $ 90,689 $ 77,226 $ 67,625 $ 60,452
—————————————————————————-
Total Proved 215,371 151,644 111,437 84,414 65,423
—————————————————————————-
Probable 205,358 134,869 93,247 66,671 48,749
—————————————————————————-
Total Proved plus
Probable $ 420,729 $ 286,513 $ 204,684 $ 151,085 $ 114,172
—————————————————————————-
(1) Net present values reported are before taxes based on InSite’s forecast
prices and costs as of December 31, 2016. No provision for bank debt
interest and general and administrative expenses have been made within the
net present values.
—————————————————————————-
/T/
A summary of InSite’s escalated price forecast assumptions as of December 31,
2016 are as follows:
/T/
—————————————————————————-
Edm
Par
Price
WTI @ Exchange Inflation
YEAR Cushing 40 API AECO-C Propane Butane Condensate Rate Rate
—————————————————————————-
$US/bbl $C/bbl C$/GJ $C/bbl $C/bbl $C/bbl $C/$US %
——————————————————————
2017 55.00 68.33 3.29 23.92 47.83 75.17 0.7500 2.00%
2018 60.00 72.32 3.24 25.31 52.07 79.55 0.7750 2.00%
2019 65.00 76.05 3.40 26.62 54.75 83.65 0.8000 2.00%
2020 70.00 79.54 3.72 27.84 57.27 87.50 0.8250 2.00%
2021 75.00 82.82 3.80 28.99 59.63 91.11 0.8500 2.00%
2022 80.00 88.60 3.95 31.01 63.79 97.46 0.8500 2.00%
2023 81.60 90.37 4.05 31.63 65.07 99.41 0.8500 2.00%
2024 83.23 92.18 4.20 32.26 66.37 101.39 0.8500 2.00%
2025 84.90 94.02 4.28 32.91 67.69 103.42 0.8500 2.00%
2026 86.59 95.90 4.37 33.57 69.05 105.49 0.8500 2.00%
2027 88.33 97.82 4.46 34.24 70.43 107.60 0.8500 2.00%
2028 90.09 99.77 4.54 34.92 71.84 109.75 0.8500 2.00%
2029 91.89 101.77 4.64 35.62 73.27 111.95 0.8500 2.00%
2030 93.73 103.81 4.73 36.33 74.74 114.19 0.8500 2.00%
2031 95.61 105.88 4.82 37.06 76.23 116.47 0.8500 2.00%
2032 97.52 108.00 4.92 37.80 77.76 118.80 0.8500 2.00%
2033 99.47 110.16 5.02 38.56 79.31 121.18 0.8500 2.00%
2034 101.46 112.36 5.12 39.33 80.90 123.60 0.8500 2.00%
—————————————————————————-
/T/
Net Asset Value
The Company’s net asset value details, as of December 31, 2016, are as follows:
/T/
—————————————————————————-
(columns may not add due to
rounding) NPV 10% NPV 15%
—————————————————————————-
(per share figures based on
basic outstanding shares) ($000s) $/share ($000s) $/share
—————————————————————————-
Proved plus probable reserves
NPV (1,2) $ 204,684 $ 1.36 $ 151,085 $ 1.00
—————————————————————————-
Undeveloped acreage (3) 126,634 0.84 126,634 0.84
—————————————————————————-
Net debt (4) (885) (0.01) (885) (0.01)
—————————————————————————-
Net Asset Value $ 330,433 $ 2.19 $ 276,835 $ 1.83
—————————————————————————-
(1) Evaluated by InSite as at December 31, 2016. Net present values do not
represent fair market value of the reserves.
—————————————————————————-
(2) Net present values (“NPV”) reported are before taxes based on InSite’s
forecast prices and costs as of December 31, 2016. No provision for bank
debt interest and general and administrative expenses have been made within
the net present values.
—————————————————————————-
(3) Independently-evaluated with average acreage value of $890 per net acre.
Reflects an independent third-party estimate of the fair market value of
RMP’s undeveloped acreage based on past Crown land sale activity, adjusted
for tenure and other considerations.
—————————————————————————-
(4) Working capital deficit net of deferred charge asset at December 31,
2016 (unaudited).
—————————————————————————-
(5) Shares outstanding at December 31, 2016 total 150.97 million.
—————————————————————————-
/T/
Capital Expenditures Efficiency
The following table provides an overview of RMP’s finding and development
(“F&D”) costs for fiscal 2016. Generally the calculation of both F&D costs and
finding, development and acquisition (“FD&A”) costs includes incorporating
changes in future development capital (“FDC”) required to bring the proved
undeveloped and probable undeveloped reserves on-production. Changes in
forecasted FDC occur annually due to capital development activities,
acquisition and/or disposition activities, undeveloped reserve revisions and
capital cost estimates that reflect the independent reserves evaluators best
estimate of what it will cost to bring the proved undeveloped and probable
undeveloped reserves on-production. For fiscal 2016, the Company cannot
calculate its FD&A costs, including changes in FDC, as the impact of the Ante
Creek Disposition and the change in FDC more than offsets 2016 exploration and
development expenditures. The Company, however, has calculated its F&D costs
for its exploration and development capital expenditures, exclusive of its net
acquisition/disposition activities.
/T/
—————————————————————————-
Fiscal 2016
—————————————————————————-
Proved +
(amounts in $000s except reserve units and unit costs) Proved Probable
—————————————————————————-
Exploration and development expenditures (1,2,3) 30,229 30,229
—————————————————————————-
Acquisitions / (dispositions), net (1,2) (89,426) (89,426)
—————————————————————————-
Total capital expenditures (59,197) (59,197)
——————————————————======================
Change in future development capital (“FDC”): (1)
—————————————————————————-
Exploration and development 12,588 23,432
—————————————————————————-
Acquisitions / (dispositions), net (19,352) (30,595)
—————————————————————————-
Aggregate F&D, including change in FDC (4) 42,817 53,661
—————————————————————————-
Aggregate FD&A, including change in FDC (4) (65,961) (66,360)
—————————————————————————-
Reserve additions (Mboe):
—————————————————————————-
Exploration and development 1,091 2,909
—————————————————————————-
Acquisitions / (dispositions), net (7,108) (10,854)
—————————————————————————-
F&D Costs ($/boe)(4) $ 39.25 $ 18.45
—————————————————————————-
FD&A Costs ($/boe) (4,5) N/A N/A
—————————————————————————-
(1) 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 F&D costs related
to reserves additions for that year.
—————————————————————————-
(2) Capital incurred during 2016 at Ante Creek before the disposition ($10.5
million) has been included in “Acquisitions / (dispositions), net”.
—————————————————————————-
(3) Fiscal 2016 capital expenditures are unaudited and exclude non-cash
capitalized share-based compensation expense of $1.5 million.
—————————————————————————-
(4) Calculation includes changes in FDC.
—————————————————————————-
(5) Due to the impact on reserves and FDC related to the Ante Creek
Disposition, FD&A costs are deemed non-applicable (“N/A”).
—————————————————————————-
/T/
The following outlines F&D costs for the prior year of 2015, in addition to the
average over the three-year period of 2014 to 2016, inclusive.
/T/
—————————————————————————-
Fiscal 2015 Three Year Average
—————————————————————————-
(amounts in $000s except reserve Proved + Proved +
units and unit costs) Proved Probable Proved Probable
—————————————————————————-
Total exploration and
development expenditures (1,4) 97,003 97,003 314,337 314,337
—————————————————————————-
Future development capital –
ending period (2) 158,290 286,124 151,526 278,961
—————————————————————————-
Less: Future development capital
– beginning period (2) (177,625) (359,675) (141,488) (264,269)
—————————————————————————-
Aggregate F&D, including change
in FDC (4) 77,668 23,452 324,374 329,029
——————————–============================================
Total reserve additions (Mboe) 4,047.5 952.2 15,291.4 15,985.9
—————————————————————————-
F&D Costs ($/boe)(3) $ 19.19 $ 24.63 $ 21.21 $ 20.58
—————————————————————————-
(1) Excludes non-cash capitalized share-based compensation expense.
—————————————————————————-
(2) FDC expenditures required to convert proved non-producing reserves and
probable reserves to proved producing.
—————————————————————————-
(3) Calculation includes changes in FDC.
—————————————————————————-
(4) The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated
future development costs generally will not reflect total F&D costs related
to reserves additions for that year.
—————————————————————————-
/T/
Future Development Capital
The following table outlines the FDC required to bring proved undeveloped and
probable undeveloped reserves on-production. The FDC has been deducted in the
estimation of future net revenue attributable to total proved reserves and
total proved plus probable reserves (using forecast prices and costs).
/T/
—————————————————————————-
Future Development Capital (1)
—————————————————————————-
Total
Total Proved +
(amounts in $000s) Proved Probable
—————————————————————————-
2017 $ 46,640 $ 63,490
—————————————————————————-
2018 33,303 69,156
—————————————————————————-
2019 39,106 64,180
—————————————————————————-
2020 27,382 68,769
—————————————————————————-
2021 5,094 13,366
—————————————————————————-
Total undiscounted FDC $ 151,525 $ 278,961
—————————————————————————-
Total discounted FDC at 10% per year $ 126,365 $ 226,418
—————————————————————————-
(1) FDC as per InSite’s independent reserves evaluation as of December 31,
2016 and based on InSite’s forecast pricing as at December 31, 2016.
—————————————————————————-
/T/
The Company expects to fund its FDC requirements from internally-generated cash
flow from operations and, as appropriate, from its existing committed bank
credit facility, equity or debt financing. It is anticipated that the costs of
funding the FDC will not impact development of RMP’s properties or the
Company’s reserves or future net revenue.
FINANCIAL RESULTS
For the year ended December 31, 2016, RMP reported funds from operations of
$29.6 million ($0.20 per fully-diluted share) on revenue of $77.3 million and
average daily production of 7,895 barrels of oil equivalent (42% light oil and
NGLs weighted). Detailed results are as follows:
/T/
—————————————————————————-
Financial
Results Three Months Ended Twelve Months Ended
—————————————————————————-
(thousands
except share
and per boe
data) (6:1
oil
equivalent Dec. 31, Dec. 31, % %
conversion) 2016 2015 change Year 2016 Year 2015 change
—————————————————————————-
P&NG revenue
(1) 13,371 34,178 (61) 77,322 161,633 (52)
—————————————————————————-
Funds from
operations
(2) 3,373 18,725 (82) 29,584 92,452 (68)
—————————————————————————-
Per share –
basic /
diluted 0.02 0.15 (87) 0.20 0.75 (73)
—————————————————————————-
Net loss (65,508) (32,380) 102 (86,019) (84,795) 1
—————————————————————————-
Per share –
basic /
diluted (0.43) (0.26) 65 (0.59) (0.69) (14)
—————————————————————————-
Total capital
expenditures (103,076) 12,008 – (59,197) 97,003 –
—————————————————————————-
Net debt (3) –
period end 885 117,956 (99) 885 117,956 (99)
—————————————————————————-
Weighted
average basic
shares 150,970,068 124,790,535 21 145,415,191 123,220,485 18
—————————————————————————-
Weighted
average
diluted
shares 150,970,068 124,790,535 21 145,415,191 123,220,485 18
—————————————————————————-
Issued and
outstanding
shares (4) 150,970,068 126,475,068 19 150,970,068 126,475,068 19
—————————————————————————-
Operating
Results
—————————————————————————-
Average daily
production:
—————————————————————————-
Natural gas
(Mcf/d) 17,110 36,352 (53) 27,599 38,606 (29)
—————————————————————————-
Crude oil
(bbls/d) 1,500 4,952 (70) 2,983 5,318 (44)
—————————————————————————-
NGLs
(bbls/d) 301 246 22 312 274 14
—————————————————————————-
Oil
equivalent
(boe/d) 4,652 11,257 (59) 7,895 12,026 (34)
—————————————————————————-
Average sales
price (1):
—————————————————————————-
Natural gas
($/Mcf) 2.79 3.26 (14) 2.22 3.32 (33)
—————————————————————————-
Crude oil
($/bbl) 58.75 50.13 17 47.80 57.86 (17)
—————————————————————————-
NGLs ($/bbl) 31.60 19.83 59 23.86 25.06 (5)
—————————————————————————-
Oil
equivalent
($/boe) 31.24 33.00 (5) 26.76 36.82 (27)
—————————————————————————-
Operating
expenses
($/boe) 9.67 4.61 110 5.92 4.90 21
—————————————————————————-
Operating
netback (5)
($/boe) 13.88 20.95 (34) 13.71 23.65 (42)
—————————————————————————-
Wells drilled:
gross (net) – 2 (2.0) – 8 (8.0) 15 (15.0) (47)
—————————————————————————-
/T/
Table Notes:
/T/
(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 20, 2017, 151.0 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.
/T/
Fourth Quarter 2016 Highlights
/T/
— In connection with the Company’s strategic initiatives review undertaken
last year, RMP completed the transformational disposition of its crude
oil and natural gas interests in the Ante Creek area of West Central
Alberta for net cash proceeds of $109.2 million, after normal and
customary closing adjustments (the “Ante Creek Disposition”). The assets
sold in the Ante Creek Disposition, which closed mid-fourth quarter on
November 15, 2016, included reserves, land acreage, infrastructure
facility and pipeline interests. Net disposition proceeds were used to
eliminate the Company’s outstanding bank indebtedness. The Ante Creek
Disposition resulted in the recognition of a gain on disposition of
$35.5 million.
— Fourth quarter 2016 production averaged 4,652 boe/d (weighted 39% light
oil and NGLs), lower from the preceding third quarter production due to
the intra-quarter Ante Creek Disposition on November 15, 2016 and the
Pembina and Alliance sales pipeline service outages in early-October
2016 (as previously disclosed). RMP’s fiscal 2016 average daily
production was 7,895 boe/d, comprised of crude oil and NGLs production
of 3,295 bbls/d and natural gas output of 27.6 MMcf/d
— Fourth quarter petroleum and natural gas revenue amounted to $13.4
million (including a realized hedging loss of $1.1 million).
Approximately 67% of the Company’s revenue was derived from crude oil
and NGLs sales. Petroleum and natural gas revenue for fiscal 2016
amounted to approximately $77.3 million (including a realized hedging
loss of $1.2 million).
— Fourth quarter petroleum and natural gas royalties amounted to $1.7
million (12% of petroleum and natural gas sales excluding realized
hedging results), as compared to $3.4 million (15% of petroleum and
natural gas sales) in the third quarter of 2016.
— Fourth quarter field operating costs on an oil-equivalent per unit basis
were $9.67/boe, as compared to the preceding third quarter 2016 per-unit
expense of $5.58/boe. In the fourth quarter, battery facility
‘turnaround’ maintenance activity conducted during the aforementioned
sales pipelines service outages affected per-unit costs by approximately
$1/boe. Additionally, the Ante Creek Disposition resulted in the
Company’s reported per-unit operating costs to increase, since the Ante
Creek field had a lower per-unit operating cost profile than RMP’s other
producing assets as a whole. RMP continues to be highly-focused on
delivering meaningful operating cost reductions and efficiency gains
across its field operations.
— Fourth quarter transportation costs were $3.64/boe on an oil-equivalent
basis, which reflects oil sales pipeline tariffs, gas sales pipeline
firm service tolls, and pipeline fuel surcharges. This compares to the
$3.51/boe of reported per-unit transportation cost for the preceding
third quarter of 2016.
— Fourth quarter general and administrative (“G&A”) expenses amounted to
$2.2 million, as compared to $1.6 million in the preceding third quarter
of 2016. As a result of year-end G&A activities associated with the
independent reserves report and the fiscal financial statement audit,
fourth quarter 2016 gross G&A costs were $835 thousand higher than the
preceding third quarter. Personnel retention costs in connection with
the corporate strategic review process undertaken in 2016 also
contributed to the quarter-over-quarter increase. RMP continues to
maintain an efficient organizational structure and presently employs 19
head office personnel and engages the services of two consultants on a
part-time basis. For 2017 the Company’s personnel have taken a 10%
salary decrease, in addition to the 10% compensation reduction put in-
place last year.
— In fiscal 2016, the Company incurred approximately $40 million on its
2016 exploration and development program. RMP undertook a light oil-
focused exploration and development capital program in 2016, albeit to a
lesser scale due to a pared-back capital expenditures budget reduced in
response to lower commodity prices. In 2016, a total of eight (8.0 net)
Montney horizontal crude oil wells were drilled, as compared to a
drilling program in fiscal 2015 of 15 (15.0 net) horizontal wells. RMP’s
2016 drilling program encompassed four (4.0 net) wells at Waskahigan,
three (3.0 net) wells at Ante Creek and one (1.0 net) exploration well
in Elmworth (formerly known as Gold Creek). The Company also completed
an asset acquisition at Elmworth in June 2016 for $10 million.
— At year-end 2016, RMP was not drawn on its bank credit facility. The
Company is presently drawn approximately $7 million on its bank line of
credit, with a current debt-servicing rate of 3.4% (per annum). The
Company’s bank credit facility has a maximum borrowing base limit of
$40.0 million and the lender’s annual borrowing base re-determination is
scheduled to occur in June 2017. RMP’s working capital deficit at
December 31, 2016 was $885 thousand.
— Fourth quarter funds from operations was $3.4 million ($0.02 per basic
share). Funds from operations for fiscal 2016 was approximately $30
million ($0.20 per basic share). The Company’s fourth quarter 2016
operating netback was $13.88/boe. For fiscal 2016, RMP’s realized
operating netback was $13.71/boe.
— For the year ended December 31, 2016, RMP reported a net loss of $86.0
million, as compared to a net loss of $84.8 million in fiscal 2015. The
Company’s earnings in fiscal 2016 was impacted by the non-cash
impairment charge on the carrying value of its property, plant and
equipment of approximately $80 million, net of the gain on the Ante
Creek Disposition. The non-cash impairment charge primarily related to
RMP’s Greater Waskahigan Cash Generating Unit (“CGU”), which prior to
the Ante Creek Disposition included the Waskahigan, Ante Creek and
Grizzly Montney fields. As a result of the transformational Ante Creek
Disposition, the Ante Creek field was removed from this CGU, which
resulted in the CGU to be assessed for indicators of impairment and
subsequent recognition of such.
/T/
The Company’s audited consolidated financial statements and associated
Management’s Discussion and Analysis for the year ended December 31, 2016 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.
ANNUAL SHAREHOLDERS MEETING
RMP’s annual meeting of shareholders is scheduled for 3:00 p.m. on Tuesday,
June 6, 2017 in the McMurray Room of the Calgary Petroleum Club, located at 319
– 5th Avenue S.W., Calgary, Alberta.
Abbreviations
/T/
—————————————————————————-
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
—————————————————————————-
/T/
Reader Advisories
Forward-Looking Statements
The information in this news release contains certain forward-looking
statements. These statements relate to future events or our future performance.
All statements other than statements of historical fact may be forward-looking
statements. Forward-looking statements are often, but not always, identified by
the use of words such as “seek”, “anticipate”, “budget”, “plan”, “continue”,
“estimate”, “approximate”, “expect”, “may”, “will”, “project”, “predict”,
“potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”,
“would” and similar expressions.
More particularly and without limitation, this news release contains
forward-looking information relating to, the terms of certain gas processing
and oil transportation agreements entered into by RMP with a regional
mid-stream service provider, including the anticipated timing of completion of
the installation of a gathering system by such mid-stream service provider; the
anticipated timing of commissioning RMP’s oil battery facility; expected
construction at the Patterson Creek Gas Plant, including the anticipated timing
thereof, expected capacity level upon completion and pipeline connections;
anticipated number of drilling locations; the Company’s belief that Elmworth
has the potential to be a long-term production and reserves growth asset for
RMP; RMP’s drilling and completion plans, including the anticipated timing that
the 13-30 well at Waskahigan will be tied into company-owned infrastructure and
placed on production, the Company’s expectation that reserves will be booked to
such well and future locations offsetting the well, and expected total budgeted
number of wells to be drilled at Waskahigan in 2017; the Company’s capital
budget for 2017, including the amount and focus thereof and anticipated
drilling plans; the Company’s expectation that production additions from the
Waskahigan drilling program will maintain corporate base production levels; the
Company’s expectation that infrastructure commissioning at Elmworth will
bolster RMP’s base production levels and provide production momentum for the
second half of 2017 and into 2018; the Company’s forecasted production for the
second half of 2017; anticipated timing of the Company providing its market
guidance for the balance of the year; RMP’s plans to fund its FDC requirements
from internally-generated cash flow from operations and, as appropriate, from
its existing committed bank credit facility, equity or debt financing and RMP’s
expectation that the costs of funding the FDC will not impact development of
RMP’s properties or its reserves or future net revenue; anticipated timing of
the Company’s next borrowing base determination under its credit facility; and
other matters. In addition, 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.
, based on certain estimates and assumptions, that the reserves described can
be profitably produced in the future.
With respect to forward-looking statements contained in this news release, RMP
has made assumptions regarding, but not limited to: conditions in general
economic and financial markets; effects of regulation by governmental agencies;
current and future commodity prices and royalty regimes; future exchange rates;
royalty rates; future operating costs; availability of skilled labor;
availability of drilling and related equipment; timing and amount of capital
expenditures; the impact of increasing competition; the price of crude oil and
natural gas; that the Company will have sufficient cash flow, debt or equity
sources or other financial resources required to fund its capital and operating
expenditures and requirements as needed; that the Company’s conduct and results
of operations will be consistent with its expectations; available pipeline
capacity; that the Company will have the ability to develop the Company’s
properties in the manner currently contemplated; that the Company will be able
to drill, complete and tie-in wells in the manner and on the timing described
herein; current or, where applicable, proposed assumed industry conditions,
laws and regulations will continue in effect or as anticipated; and the
estimates of the Company’s production and reserves volumes and the assumptions
related thereto (including commodity prices and development costs) are accurate
in all material respects.
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; obtaining required approvals of
regulatory authorities; unexpected drilling results; the Company’s is unable to
achieve its objectives; changes in capital expenditures, reserves or reserves
estimates and debt service requirements; the occurrence of unexpected events
involved in the exploration for, and the operation and development of, oil and
gas properties, including hazards such as fire, explosion, blowouts, cratering,
and spills, each of which could result in substantial damage to wells,
production facilities, other property and the environment or in personal
injury; changes or fluctuations in production levels; delays in anticipated
timing of drilling and completion of wells; lack of available capacity on
pipelines; the lack of availability of qualified personnel; uncertainties
associated with estimating oil and natural gas reserves; that the Company isn’t
able to book any reserves related to the 13-30 well at Waskahigan or other
wells off-setting such well; and ability to access sufficient capital from
internal and external sources. Many of these risks and uncertainties and
additional risk factors are described in the Company’s Annual Information Form
which is available at www.sedar.com. 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.
Oil and Gas Matters
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.
This news release may disclose drilling locations in three categories: (i)
proved undeveloped locations; (ii) probable undeveloped locations; and (iii)
unbooked locations. Proved undeveloped locations and probable undeveloped
locations are booked and derived from the Company’s most recent independent
reserves evaluation as prepared by InSite as of December 31, 2016 and account
for drilling locations that have associated proved and/or probable reserves, as
applicable. Unbooked locations are internal estimates based on the Company’s
prospective acreage and an assumption as to the number of wells that can be
drilled per section based on industry practice and internal review. Unbooked
locations do not have attributed reserves or resources. Unbooked locations have
been identified by management as an estimation of the Company’s multi-year
drilling activities based on evaluation of applicable geologic, seismic,
engineering, production and reserves information. There is no certainty that
the Company will drill all unbooked drilling locations and if drilled there is
no certainty that such locations will result in additional oil and gas
reserves, resources or production. The drilling locations on which the Company
will actually drill wells is ultimately dependent upon the availability of
capital, regulatory approvals, seasonal restrictions, oil and natural gas
prices, costs, actual drilling results, additional reservoir information that
is obtained and other factors. While certain of the unbooked drilling locations
have been derisked by drilling existing wells in relative close proximity to
such unbooked drilling locations, the majority of other unbooked drilling
locations are farther away from existing wells where management has less
information about the characteristics of the reservoir and therefore there is
more uncertainty whether wells will be drilled in such locations and if drilled
there is more uncertainty that such wells will result in additional oil and gas
reserves, resources or production.
This news release contains a number of oil and gas metrics, including F&D,
FD&A, operating netback, net asset value and reserve additions, which do not
have standardized meanings or standard methods of calculation and therefore
such measures may not be comparable to similar measures used by other companies
and should not be used to make comparisons. Such metrics have been included
herein to provide readers with additional measures to evaluate the Company’s
performance; however, such measures are not reliable indicators of the future
performance of the Company and future performance may not compare to the
performance in previous periods and therefore such metrics should not be unduly
relied upon. F&D and FD&A costs take into account reserves revisions during the
year on a per boe basis. The aggregate of the costs incurred in the financial
year and changes during that year in estimated FDC may not reflect total
finding and development costs related to reserves additions for that year. F&D
costs both including and excluding acquisitions and dispositions have been
presented in this news release because acquisitions and dispositions can have a
significant impact on our ongoing reserves replacement costs and excluding
these amounts could result in an inaccurate portrayal of our cost structure.
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 F&D costs related to
reserves additions for that year. Operating netback is calculated using
realized wellhead revenues less royalties, operating expenses and
transportation costs calculated on a per boe equivalent basis. Management uses
these oil and gas metrics for its own performance measurements and to provide
shareholders with measures to compare RMP’s operations over time. Readers are
cautioned that the information provided by these metrics, or that can be
derived from the metrics presented in this news release, should not be relied
upon for investment or other purposes.
Any references in this news release to production test rates, flow-back
results, flow test results and production flow test 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. Furthermore, neither a pressure transient analysis
or a well-test interpretation has been carried out yet, and as such, test
results should be considered to be preliminary until such analysis or
interpretation has been completed.
In this news release, references to the Company’s 2016 reserves are based on a
report prepared by InSite with an effective date of December 31, 2016 prepared
in accordance with definitions, standards and procedures prescribed in NI
51-101 and the Canadian Oil and Gas Evaluation Handbook and based on InSite
forecast pricing effective January 1, 2017.
In this news release, the estimates of reserves and future net revenue for
individual properties may not reflect the same confidence level as estimates of
reserves and net revenue for all properties due to the effects of aggregation.
Estimates of reserves have been made assuming that development of each
property, in respect of which estimates have been made, will occur without
regard to the availability of funding required for that development. It should
not be assumed that the estimates of future net revenues presented herein
represent the fair market value of the reserves.
Financial Matters
This news release contains certain financial measures, including operating
netback, net debt and funds from operations, which do not have standardized
meanings or standard methods of calculation nor are recognized measures under
IFRS and therefore such measures may not be comparable to similar measures used
by other companies and should not be used to make comparisons. Such financial
measures have been included herein to provide readers with additional measures
to evaluate the Company’s performance; however, such measures are not reliable
indicators of the future performance of the Company and future performance may
not compare to the performance in previous periods and therefore such metrics
should not be unduly relied upon. Operating netback refers to realized wellhead
revenue less royalties, operating expenses and transportation costs per barrel
of oil equivalent. The Company believes that this financial netback measure is
useful supplemental information to analyze operating performance and provide an
indication of the results generated by the Company’s principal business
activities. Investors should be cautioned that this measure should not be
construed as an alternative to other measures of financial performance as
determined in accordance with IFRS. Net debt refers to outstanding bank debt
less deferred charge plus working capital deficiency (or minus working capital
surplus), excluding unrealized amounts pertaining to risk management contracts.
Net debt is not a recognized measure under IFRS and does not have a
standardized meaning. The Company’s method of calculating net debt may differ
from other companies, and accordingly, they may not be comparable to similar
measures used by other companies. 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
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. As disclosed within this news release, funds from
operations represents cash flow from operating activities before: any expensed
corporate acquisition-related costs, any decommissioning obligation cash
expenditures, changes in non-cash working capital from operating activities and
non-cash changes in deferred charge. The Company presents funds from operations
per share whereby per share amounts are calculated consistent with the
calculation of earnings per share.
– END RELEASE – 21/03/2017
For further information:
RMP Energy Inc.
Jon Grimwood
President
(403) 930-6311
jon.grimwood@rmpenergyinc.com
OR
RMP Energy Inc.
Dean Bernhard
Vice President, Finance and Chief Financial Officer
(403) 930-6304
dean.bernhard@rmpenergyinc.com
COMPANY:
FOR: RMP ENERGY INC.
TSX SYMBOL: RMP
INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170321CC0109
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