CALGARY, May 29, 2017 /CNW/ - Tourmaline Oil Corp.
(TSX:TOU) ("Tourmaline" or the "Company") is pleased to announce
three new extensive exploration and production ("EP") opportunities
within its existing core complexes and provide an update on its EP
activities.
NEW LIQUID-RICH OPPORTUNITIES
Liquid-rich Viking at Brazeau River
Tourmaline has been delineating a new extensive liquid-rich
opportunity in the Brazeau River area at the south end of the
Company's Deep Basin complex. The Company has brought on
production eight liquid-rich Viking horizontals over the past two
years. The average initial production ("IP") 30-day rate of
these wells is 11.7 mmcfpd of natural gas, the average IP 365 day
rate is 4.8 mmcfpd of natural gas, with average liquids production
of 27.5 bbls/mmcf and drill and complete costs averaging
$4.3 million. The type curve
based on these eight producing wells indicates an internally
estimated ultimate recovery ("EUR") of 5.1 bcf of sales gas and
146.5 mboe of condensate and NGL yielding an implied value of
$10.5 million per well (net present
value, discounted at 10%, before tax). The Company has a
defined future inventory of approximately 60 additional
horizontals, all of which can access Company operated
infrastructure.
Liquid-rich Cardium at Hinton-Anderson-Lambert
Tourmaline's initial horizontal well into an extensive,
liquid-rich, Cardium complex at Hinton-Anderson-Lambert has produced 1.6 bcf and
48,000 bbls of liquid (95% C5+) over the first 100 days of
production, with the well being production constrained as it is
only producing up tubing. Initial internal EURs are in excess
of 10 bcf and 300 mboe of liquids for the 16-25-50-23W5M well,
drill and complete costs were $3.5
million (1,500 m lateral, 30 stage completion). The
Company plans 4-5 follow-up and delineation wells prior to year-end
to further evaluate this potentially large gas/condensate complex,
with a very large associated drilling inventory.
Peace River High Montney Oil
Tourmaline's most recent Lower Montney horizontal at
Valhalla is currently producing at
1,540 boepd, 1,107 bpd of oil and 2.6 mmcfpd of natural gas after
five days of production. Multiple follow-up wells are planned
over the next few months with all of the incremental oil able to
access Tourmaline's oil and gas processing facilities at Spirit
River. The Company has a substantial inventory of Lower
Montney horizontals on existing lands which will be further defined
with the upcoming drilling program. The Lower Montney
opportunity complements the new extensive Lower Charlie Lake
development announced earlier this month (15 new wells on
production, 284 future Lower Charlie Lake locations in
inventory).
SECOND HALF ("2H") 2017 EP PROGRAM
Full-year 2017 annual EP capital spending of $1.33 billion remains unchanged and will generate
approximately 30% production growth in 2017 and is anticipated to
be funded with available cash flow. The Company plans to
operate 18 rigs in 2H 2017, with an estimated 175 new wells
completed and brought on production by year end. Q2 2017
production has averaged 240,000-245,000 boepd to date which is
already within the full year average production guidance of
240,000-260,000 boepd. The Company will provide full Q2
production guidance after the magnitude of the third party firm
transportation restrictions, currently planned for June, are better
quantified.
ADDITIONAL EP HIGHLIGHTS
- The Company's Spirit River
3-10 sour gas injection plant has been expanded from 30 to 60
mmcfpd during the second quarter. This will facilitate accelerated
development of the new Lower Charlie Lake and Lower Montney oil
developments along with the ongoing Upper Charlie Lake program.
- Enhanced stimulation of the Lower Montney turbidite at
Dawson-Sunrise is yielding strong
initial results. The Sunrise D9-10 well, completed with 38 stages
(vs 28 stages historically), is testing 5.9 mmcfpd of natural gas
with 621 bbls/day of condensate at the wellhead after 20 days of
production. Total liquid production from the well, including plant
liquid recoveries, is 1,250 bpd gross (210 bbls/mmcfpd). Completed
well cost was $2.9 million.
- The Company has now drilled five Triassic Montney horizontals
on the first 9 well pad at Gundy Ck in NEBC. To date drilling costs
have been reduced from the $3.1
million (as contained in the existing year-end independent
reserve report for the previous operator) to $1.6 million per well (average lateral length of
1,715 m).
READER ADVISORIES
CURRENCY
All amounts in this news release are stated in Canadian dollars
unless otherwise specified.
FORWARD-LOOKING INFORMATION
This news release contains forward-looking information within
the meaning of applicable securities laws. The use of any of the
words "forecast", "expect", "anticipate", "continue", "estimate",
"objective", "ongoing", "may", "will", "project", "should",
"believe", "plans", "intends" and similar expressions are intended
to identify forward-looking information. More particularly and
without limitation, this news release contains forward-looking
information concerning Tourmaline's plans and other aspects of its
anticipated future operations, management focus, objectives,
strategies, financial, operating and production results and
business opportunities, including anticipated petroleum and natural
gas production for various periods, drilling inventory or
locations, cash flow, the net present value of future net reserves
related to certain of the Company's wells, capital spending, cost
reduction initiatives, projected operating and drilling costs, the
timing for facility expansions and facility start-up dates, as well
as Tourmaline's future drilling prospects and plans, business
strategy, future development and growth opportunities, prospects
and asset base. The forward-looking information is based on certain
key expectations and assumptions made by Tourmaline, including
expectations and assumptions concerning: prevailing commodity
prices and currency exchange rates; applicable royalty rates and
tax laws; interest rates; future well production rates and reserve
volumes; operating costs the timing of receipt of regulatory
approvals; the performance of existing and future wells; the
success obtained in drilling new wells; anticipated timing and
results of capital expenditures; the sufficiency of budgeted
capital expenditures in carrying out planned activities; the
timing, location and extent of future drilling operations; the
successful completion of acquisitions and dispositions; the
state of the economy and the exploration and production business;
the availability and cost of financing, labour and services; and
ability to market crude oil, natural gas and NGL successfully.
Information relating to "reserves" is also deemed to be forward
looking information, as it involves the implied assessment, based
on certain estimates and assumptions, that the reserves described
exist in the quantities predicted or estimated and that the
reserves can be profitably produced in the future.
Although Tourmaline believes that the expectations and
assumptions on which such forward-looking information is based are
reasonable, undue reliance should not be placed on the
forward-looking information because Tourmaline can give no
assurances that they will prove to be correct. Since
forward-looking information addresses future events and conditions,
by its very nature it involves inherent risks and uncertainties.
Actual results could differ materially from those currently
anticipated due to a number of factors and risks. These include,
but are not limited to: the risks associated with the oil and gas
industry in general such as operational risks in development,
exploration and production; delays or changes in plans with respect
to exploration or development projects or capital expenditures; the
uncertainty of estimates and projections relating to reserves,
production, revenues, costs and expenses; health, safety and
environmental risks; commodity price and exchange rate
fluctuations; interest rate fluctuations; marketing and
transportation; loss of markets; environmental risks; competition;
incorrect assessment of the value of acquisitions; failure to
complete or realize the anticipated benefits of acquisitions or
dispositions; ability to access sufficient capital from internal
and external sources; failure to obtain required regulatory and
other approvals; and changes in legislation, including but not
limited to tax laws, royalties and environmental regulations.
Readers are cautioned that the foregoing list of factors is not
exhaustive.
Additional information on these and other factors that could
affect Tourmaline, or its operations or financial results, are
included in the Company's most recently filed Management's
Discussion and Analysis (See "Forward-Looking Statements" therein),
Annual Information Form (See "Risk Factors" and "Forward-Looking
Statements" therein) and other reports on file with applicable
securities regulatory authorities and may be accessed through the
SEDAR website (www.sedar.com) or Tourmaline's website
(www.tourmalineoil.com).
The forward-looking information contained in this news release
is made as of the date hereof and Tourmaline undertakes no
obligation to update publicly or revise any forward-looking
information, whether as a result of new information, future events
or otherwise, unless expressly required by applicable securities
laws.
INITIAL PRODUCTION (IP) RATES
Any references in this news release to IP rates are useful in
confirming the presence of hydrocarbons, however, such rates are
not determinative of the rates at which such wells will continue
production and decline thereafter and 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. Such rates are based on field estimates and may be
based on limited data available at this time.
NET PRESENT VALUES
This news release contains an estimate of the net present value
of future net revenue from the estimated reserves associated with
certain of the Company's wells. Such net present value has been
calculated based on the Q2 2017 GLJ pricing assumptions and total
drill, complete and tie-in costs of $4.6
million per well, and is based on the Company's internal
evaluation of reserves prepared by a qualified reserves evaluator
in accordance NI‐51‐101 and the COGE Handbook. Such estimates
of future net revenue are after the deduction of royalties,
development costs, production costs and well abandonment costs but
before deduction of future income tax expenses and before
consideration of indirect costs such as administrative, overhead
and other miscellaneous expenses. The estimated future net
revenue does not represent the fair market value of the reserves.
There is no assurance that the forecast prices and costs
assumptions upon which such estimates are made will be attained and
variances could be material. The reserve estimates of the Company's
crude oil, NGL and natural gas reserves and any estimated recovery
factors provided herein are estimates only and there is no
guarantee that the estimated reserves will be recovered. Actual
crude oil, NGL and natural gas reserves and related net present
values may be greater than or less than the estimates provided
herein.
BOE EQUIVALENCY
In this news release, production and reserves information may be
presented on a "barrel of oil equivalent" or "boe" basis. Boe's may
be misleading, particularly if used in isolation. A boe
conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. In
addition, as the value ratio between natural gas and crude oil
based on the current prices of natural gas and crude oil is
significantly different from the energy equivalency of 6:1,
utilizing a conversion on a 6:1 basis may be misleading as an
indication of value.
TYPE CURVE INFORMATION
The type curve information included in this news release,
including IP 30, represents estimates of the production decline and
ultimate volumes expected to be recovered from wells over the life
of the well. This information is based on internally generated type
curves based on a combination of historical performance of older
wells and management's expectation of what might be achieved from
future wells. The information represents what management thinks an
average well will achieve. Individual wells may be higher or lower
but over a larger number of wells management expects the average to
come out to the type curve. Over time type curves can and will
change based on achieving more production history on older wells or
more recent completion information on newer wells. There is no
certainty that future wells will generate results to match historic
type curves presented herein.
INDUSTRY METRICS
The term EUR, while commonly used in the oil and gas industry,
does not have a standardized meaning and may not be comparable to
similar measures presented by other companies, and therefore should
not be used to make such comparisons. This metric has been
included to provide readers with an additional measure to evaluate
the Company's performance; however, such measure is not a reliable
indicator of the future performance of the Company and future
performance may not compare to the performance in previous periods
and therefore this metric should not be unduly relied upon. EUR is
calculated as estimated ultimate recovery of oil from a typical
well in the area. EUR was determined internally by the Company by a
non-independent qualified reserves evaluator incorporating current
well results and historical well performance from the Company's
analogous pools in the nearby area.
ESTIMATED DRILLING INVENTORY
This news release discloses drilling locations based on four
categories: (i) proved undeveloped locations; (ii) probable
undeveloped locations; (iii) unbooked locations; and (iv) an
aggregate total of (i), (ii) and (iii). Of the Company's 344
undrilled locations which are disclosed herein, 29 are proved
undeveloped locations, nil are proved non-producing
locations, 19 are probable undeveloped locations, nil are
probable non-producing and 296 are unbooked. Proved undeveloped
locations, proved non-producing locations, probable undeveloped
locations and probable non-producing locations are booked and
derived from the Company's most recent independent reserves
evaluation as prepared by GLJ Petroleum Consultants Ltd. and
Deloitte LLP 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 (including contingent and prospective). 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 natural gas
reserves, resources or production. The drilling locations on which
the Company will actually drill wells, including the number and
timing thereof is ultimately dependent upon the availability of
funding, 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
natural gas reserves, resources or production.
CERTAIN DEFINITIONS:
bbl
|
barrel
|
bbls/day
|
barrels per
day
|
bbl/mmcf
|
barrels per million
cubic feet
|
bcf
|
billion cubic
feet
|
bcf/d
|
billion cubic feet
per day
|
bpd or
bbl/d
|
barrels per
day
|
boe
|
barrel of oil
equivalent
|
boepd or
boe/d
|
barrel of oil
equivalent per day
|
bopd or
bbl/d
|
barrel of oil,
condensate or liquids per day
|
FCP
|
final circulating
pressure
|
gj
|
gigajoule
|
gjs/d
|
gigajoules per
day
|
mbbls
|
thousand
barrels
|
mboe
|
thousand barrels of
oil equivalent
|
mcf
|
thousand cubic
feet
|
mcfpd or
mcf/d
|
thousand cubic feet
per day
|
mcfe
|
thousand cubic feet
equivalent
|
mmboe
|
million barrels of
oil equivalent
|
mmbtu
|
million British
thermal units
|
mmbtu/d
|
million British
thermal units per day
|
mmcf
|
million cubic
feet
|
mmcfpd or
mmcf/d
|
million cubic feet
per day
|
MPa
|
megapascal
|
mstboe
|
thousand stock tank
barrels of oil equivalent
|
NGL
|
natural gas
liquids
|
ABOUT TOURMALINE OIL CORP.
Tourmaline is a Canadian senior crude oil and natural gas
exploration and production company focused on long-term growth
through an aggressive exploration, development, production and
acquisition program in the Western Canadian Sedimentary Basin.
SOURCE Tourmaline Oil Corp.