/NOT FOR DISTRIBUTION TO U.S. NEWS WIRE SERVICES OR
DISSEMINATION IN THE U.S./
CALGARY, April 17, 2013 /CNW/ - Novus Energy Inc. ("Novus"
or the "Company") (TSXV: NVS) is pleased to announce a substantial
increase to its reserves and production from its successful 2012
capital program.
The Company's year-end independent reserve
evaluation was prepared by Sproule Associates Limited ("Sproule")
effective December 31, 2012 (the
"Sproule Report").
Reserve Highlights
- Proved reserves at December 31,
2012 increased by 68% to 14.85 million boe, up substantially
from 8.84 million boe on December 31,
2011.
- Proved plus probable reserves at December 31, 2012 increased by 56% to 22.72
million boe, up from 14.56 million boe on December 31, 2011.
- The net present value of proved plus probable reserves, before
income tax and discounted at 10%, increased to $377.1 million up from $331.3 million at December
31, 2011.
- Oil and natural gas liquids ("NGLs") at December 31, 2012 represent 82% of proved plus
probable reserves on a boe basis and 81% of total proved
reserves.
- Total proved reserves at December 31,
2012 represent 65% of total proved plus probable reserves,
up from 61% on December 31, 2011.
- Reserve replacement for the year was 829% on a proved plus
probable basis and 637% based on proved reserves.
- The Company's Reserve Life Index at December 31, 2012 was 18.1 years on a proved plus
probable basis and 11.8 years on a proved basis (based on
annualized fourth quarter 2012 production).
- Finding, development and acquisition costs, excluding future
development capital ("FDC"), were $9.41/boe for proved plus probable reserves and
$12.25/boe for proved reserves.
Including FDC, finding, development and acquisition costs were
$26.87/boe for proved plus probable
reserves and $28.62/boe for proved
reserves.
Operational Highlights
- The Company's average production for 2012 was 3,059 boe/d,
representing 55% year over year average production volume
growth.
- Novus achieved production of 3,444 boe/d in the fourth quarter
of 2012 (78% oil and liquids) representing a 21% increase over
fourth quarter 2011 production volumes.
- The preliminary estimate of first quarter 2013 average
production based on field estimates is 4,090 boe/d.
- Operating netbacks in 2012 for the Company's Viking light oil
production in Dodsland were
estimated to be $54.16/boe.
- During 2012 Novus operated the drilling of 72 wells all using
horizontal multi stage frac technology.
- During the first quarter of 2013 Novus drilled 17 wells all
using horizontal multi stage frac technology. Twenty wells
were completed and brought on production during the quarter.
- Novus currently controls 219 net sections of Viking rights, and
has a risked drilling inventory of 1,585 net, undrilled Viking oil
locations.
Operational Update
In the fourth quarter of 2012, Novus achieved
production of 3,444 boe/d, a 21% increase over fourth quarter
2011 average production volumes of 2,845 boe/d. 2012 average annual
production was 3,059 boe/d, a 55% increase over 2011 average annual
production volumes of 1,971 boe/d.
The Company drilled a total of 72 wells (72.0
net) in 2012 all targeting Viking oil within the Dodsland region of Saskatchewan. Twenty-four of these wells
(24.0 net) were drilled in the fourth quarter of 2012.
During the fourth quarter of 2012, Novus
drilled, completed and placed on production three wells to the west
of its Flaxcombe field. The
western most well drilled in this extension is situated over 12
miles from the Flaxcombe field. In
the first quarter of 2013, Novus drilled, cased and put on
production four additional successful wells in the region. With
recent land purchases Novus controls approximately 17.5 sections of
land in this western extension and with its success, has materially
added to its drilling inventory.
Due to higher than average snowfall levels in
Saskatchewan this year, Novus has
taken several steps to mitigate the impact of spring breakup on its
production. The Company has tied all possible wells into its
pipeline system and has negated the need for trucks in regular
operations in its core Flaxcombe
area. Within the region, where trucks will be required, the
Company has distributed a large quantity of rig matting to ensure
emulsion hauling can continue on access roads through
breakup. All field oil storage tanks were emptied prior to
road bans being applied giving the Company ample capacity to
maintain regular production in the event of inadvertent short term
trucking disruptions.
Novus had a very active and highly successful
year in 2012. The large reserve additions the Company obtained were
almost exclusively generated in its key Viking light oil resource
play in Dodsland,
Saskatchewan. Virtually all of the proved and probable
reserve growth the Company achieved came from organic drilling. The
attractive finding, development and acquisition costs the Company
enjoys validate its growth strategy of assembling a predictable,
low risk, multi-year drilling inventory within a concentrated core
area with year round access. Novus now controls 219 net
sections of Viking rights in the Greater
Dodsland area of Saskatchewan and the Greater Provost area of
Alberta.
Financial Position
The Company ended the 2012 fiscal year with net
debt of $78.9 million, against lines
of credit of $105 million.
Novus' strong financial position and unused lines of credit provide
the Company with the ability to maintain its growth profile and
continue the exploitation of its significant drilling
inventory.
Value Optimization Process
On December 4,
2012, Novus announced that it had retained financial
advisors to assist the Special Committee of the Board of Directors
in exploring and evaluating a broad range of options to optimize
shareholder value. Technical presentations commenced during the
third week of January 2013 for
interested and qualified parties who have entered into a
confidentiality agreement with Novus. The Company does not
intend to disclose future developments with respect to the process
unless and until the Board of Directors has approved a specific
transaction or otherwise determines that disclosure is appropriate
or required.
Reserves
The reserves data set forth below is based upon
the Sproule Report. The following presentation summarizes the
Company's crude oil, natural gas liquids and natural gas reserves
and the net present values of future net revenue of the Company's
reserves before income taxes and using forecast prices and costs.
The Sproule Report has been prepared in accordance with the
standards contained in the COGE Handbook and the reserves
definitions contained in NI 51-101.
All evaluations and reviews of future net cash
flows are stated prior to any provisions for interest costs or
general and administrative costs and after the deduction of
estimated future capital expenditures for wells to which reserves
have been assigned. It should not be assumed that the estimates of
future net revenues presented in the tables below represent the
fair market value of the reserves. There is no assurance that the
forecast prices and cost assumptions will be attained and variances
could be material. The recovery and reserve estimates of crude oil,
natural gas liquids and natural gas reserves provided herein are
estimates only and there is no guarantee that the estimated
reserves will be recovered. Actual crude oil, natural gas and
natural gas liquids reserves may be greater than or less than the
estimates provided herein.
|
|
|
|
|
Light and Medium
Oil |
|
Heavy Oil |
|
Natural Gas
Liquids |
|
Natural Gas |
|
Barrels of oil
equivalent |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
|
(Mbbl) |
|
(Mbbl) |
|
(Mbbl) |
|
(Mbbl) |
|
(Mbbl) |
|
(Mbbl) |
|
(Mmcf) |
|
(Mmcf) |
|
(Mboe) |
|
(Mboe) |
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing |
|
3,501.0 |
|
3,107.7 |
|
11.4 |
|
9.4 |
|
65.3 |
|
44.3 |
|
6,965 |
|
6,133 |
|
4,738.6 |
|
4,183.4 |
|
Non-Producing |
|
68.9 |
|
59.5 |
|
- |
|
- |
|
0.9 |
|
0.8 |
|
124 |
|
104 |
|
90.5 |
|
77.6 |
|
Undeveloped |
|
8,424.2 |
|
7,604.4 |
|
- |
|
- |
|
19.7 |
|
16.3 |
|
9,485 |
|
8,651 |
|
10,024.6 |
|
9,062.6 |
Total Proved |
|
11,994.1 |
|
10,771.6 |
|
11.4 |
|
9.4 |
|
85.9 |
|
61.3 |
|
16,574 |
|
14,888 |
|
14,853.7 |
|
13,323.6 |
Probable |
|
6,427.9 |
|
5,802.2 |
|
33.7 |
|
25.8 |
|
52.2 |
|
37.9 |
|
8,093 |
|
7,307 |
|
7,862.4 |
|
7,083.9 |
Total Proved plus |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Probable |
|
18,422.0 |
|
16,573.8 |
|
45.1 |
|
35.2 |
|
138.1 |
|
99.3 |
|
24,666 |
|
22,196 |
|
22,716.1 |
|
20,407.5 |
Notes:
- "Gross" means the Company's reserves before calculation of
royalties, and before consideration of the Company's royalty
interests.
- "Net" means the Company's reserves after deduction of royalty
obligations, and including the Company's royalty interests.
- Oil equivalent amounts have been calculated using a conversion
rate of six thousand cubic feet of natural gas to one barrel of
oil.
- Columns may not add due to rounding.
Reserves Values
The estimated before tax future net revenues
associated with the Company's reserves, effective December 31, 2012 and based on Sproule's
December 31, 2012 future price
forecast, are summarized in the following table:
|
|
|
|
|
|
|
|
|
|
|
(M$) |
|
0% |
|
5% |
|
10% |
|
15% |
|
20% |
Proved |
|
|
|
|
|
|
|
|
|
|
|
Producing |
|
182,823 |
|
154,829 |
|
134,577 |
|
119,431 |
|
107,760 |
|
Non-Producing |
|
1,998 |
|
1,550 |
|
1,214 |
|
956 |
|
753 |
|
Undeveloped |
|
239,703 |
|
156,922 |
|
103,133 |
|
67,153 |
|
42,444 |
Total Proved |
|
424,524 |
|
313,301 |
|
238,923 |
|
187,539 |
|
150,957 |
Probable |
|
318,009 |
|
203,435 |
|
138,202 |
|
98,773 |
|
73,626 |
Total Proved plus
Probable |
|
742,533 |
|
516,736 |
|
377,125 |
|
286,313 |
|
224,583 |
Notes:
- Net present value of future net revenue includes all resource
income:
- Sale of oil, gas, and by-product reserves
- Processing third party reserves
- Other income
- Values are based on net reserve volumes
- Columns may not add due to rounding
Price Forecast
The December 31,
2012 Sproule price forecast is summarized as
follows:
Year |
$US/$Cdn
Exchange Rate |
WTI @
Cushing |
AB Edmonton
Light |
Hardisty
Bow River |
Natural Gas at
AECO-C Spot |
|
|
(US$/bbl) |
(C$/bbl) |
(C$/bbl) |
(C$/Mmbtu) |
2013 |
1.001 |
89.63 |
84.55 |
70.18 |
3.31 |
2014 |
1.001 |
89.93 |
89.84 |
75.47 |
3.72 |
2015 |
1.001 |
88.29 |
88.21 |
74.09 |
3.91 |
2016 |
1.001 |
95.52 |
95.43 |
81.12 |
4.70 |
2017 |
1.001 |
96.96 |
96.87 |
82.34 |
5.32 |
2018 |
1.001 |
98.41 |
98.32 |
83.57 |
5.40 |
2019 |
1.001 |
99.89 |
99.79 |
84.82 |
5.49 |
2020 |
1.001 |
101.38 |
101.29 |
86.10 |
5.58 |
2021 |
1.001 |
102.91 |
102.81 |
87.39 |
5.67 |
2022 |
1.001 |
104.45 |
104.35 |
88.70 |
5.76 |
2023 |
1.001 |
106.02 |
105.92 |
90.03 |
5.85 |
2024+ |
|
+1.5%/yr |
+1.5%/yr |
+1.5%/yr |
+1.5%/yr |
Note: Inflation is accounted for at 1.5%
per year.
Finding, Development and Acquisition Costs
("FD&A")
Novus' F&D and FD&A costs for 2012, 2011
and the three year average are presented in the tables below. The
costs used in the F&D and FD&A calculations are the capital
costs related to: land acquisition and retention; drilling;
completions; tangible well site equipment; tie-ins; facilities; and
other costs, plus the change in estimated FDC as per the
independent reserve report, inclusive of the effects of the Alberta
Drilling Royalty Credit program. Acquisition costs are net of any
proceeds from dispositions of properties. Due to the timing
of capital costs and the subjectivity in the estimation of further
costs, the aggregate of the exploration and developments 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 reserve
additions for that year (all figures in the following tables are in
thousands of dollars unless otherwise stated).
Finding & Development Costs - Proved |
|
|
|
|
3 Year |
(000's, except $/boe amounts) |
2012 |
|
2011 |
|
Average |
Capital expenditures (excluding acquisitions and
dispositions) |
$87,536 |
|
$73,580 |
|
$71,588 |
Change in future development capital |
116,702 |
|
53,657 |
|
82,751 |
Total capital for F&D |
204,238 |
|
127,237 |
|
154,339 |
Reserve additions, excluding acquisitions and
dispositions |
7,155.8 |
|
4,665.1 |
|
5,051.6 |
Proved F&D costs - including future
development capital ($/boe) |
28.54 |
|
27.27 |
|
30.55 |
Proved F&D costs - excluding future
development capital ($/boe) |
12.23 |
|
15.77 |
|
14.17 |
|
|
|
|
|
|
|
|
|
|
|
|
Finding & Development Costs - Proved plus
probable |
|
|
|
|
3 Year |
(000's, except $/boe amounts) |
2012 |
|
2011 |
|
Average |
Capital expenditures (excluding acquisitions and
dispositions) |
$87,536 |
|
$73,580 |
|
$71,588 |
Change in future development capital |
162,072 |
|
58,889 |
|
108,687 |
Total capital for F&D |
249,608 |
|
132,469 |
|
180,275 |
Reserve additions, excluding acquisitions and
dispositions |
9,351.9 |
|
5,896.4 |
|
7,210.5 |
Proved plus probable F&D costs - including
future development capital ($/boe) |
26.69 |
|
22.47 |
|
25.00 |
Proved plus probable F&D costs - excluding
future development capital ($/boe) |
9.36 |
|
12.48 |
|
9.93 |
|
|
|
|
|
|
Finding, Development & Acquisition Costs -
Proved |
|
|
|
|
3 Year |
(000's, except $/boe amounts) |
2012 |
|
2011 |
|
Average |
Capital expenditures (including acquisitions, net
of dispositions) |
$87,306 |
|
$73,110 |
|
$76,234 |
Change in future development capital |
116,692 |
|
48,052 |
|
82,751 |
Total capital for FD&A |
203,998 |
|
121,162 |
|
158,985 |
Reserve additions, including net acquisitions |
7,128.6 |
|
4,734.2 |
|
5,211.1 |
Proved FD&A costs - including future
development capital ($/boe) |
28.62 |
|
25.59 |
|
30.51 |
Proved FD&A costs - excluding future
development capital ($/boe) |
12.25 |
|
15.44 |
|
14.63 |
|
|
|
|
|
|
Finding, Development & Acquisition Costs -
Proved plus probable |
|
|
|
|
3 Year |
(000's, except $/boe amounts) |
2012 |
|
2011 |
|
Average |
Capital expenditures (including acquisitions, net
of dispositions) |
$87,306 |
|
$73,110 |
|
$76,234 |
Change in future development capital |
162,062 |
|
48,416 |
|
108,687 |
Total capital for FD&A |
249,368 |
|
121,526 |
|
184,921 |
Reserve additions, including net acquisitions |
9,278.8 |
|
6,037.6 |
|
7,485.0 |
Proved plus probable FD&A costs - including
future capital ($/boe) |
26.87 |
|
20.13 |
|
24.71 |
Proved plus probable FD&A costs - excluding
future capital ($/boe) |
9.41 |
|
12.11 |
|
10.18 |
Notes:
- The reserves used in the above calculations are Company gross
reserves additions, including revisions.
- The 2012 capital expenditures used in the above calculations
are unaudited as the Company's 2012 annual financial statements are
in the process of being finalized. These numbers and
calculations thereon are subject to change upon completion of the
audit.
Reserves Replacement
Novus' 2012 FD&A activities replaced 829% of
production on a proved plus probable basis and 637% on a proved
basis.
|
|
|
|
|
Production (Mboe) |
|
|
|
1,119.5 |
Proved plus probable reserve additions (Mboe) |
|
|
|
9,278.8 |
Proved plus probable reserve replacement |
|
|
|
829% |
Proved reserve additions (Mboe) |
|
|
|
7,128.6 |
Proved reserve replacement |
|
|
|
637% |
Contingent Resource Assessment
Sproule previously provided Novus with an
independent Contingent Resource Assessment for the Company's
Dodsland Viking light oil assets effective as at December 31, 2011 (the "Contingent Resource
Assessment"), the intent of which was to independently assess the
contingent resource potential of the area. Novus did not commission
Sproule to perform an update to the Contingent Resource Assessment
in 2012 given the growth in production and reserves the Company
exhibited, and the significant amount of industry development in
the area that occurred during the year.
Measurements
Reported production represents Novus' ownership
share of sales before the deduction of royalties. Where amounts are
expressed on a barrel of oil equivalent ("boe") basis, natural gas
has been converted at a ratio of six thousand cubic feet to one
boe. This ratio is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead. Boe's may be
misleading, particularly if used in isolation. References to
natural gas liquids ("liquids") include condensate, propane, butane
and ethane and one barrel of liquids is considered to be equivalent
to one boe.
Neither the TSX Venture Exchange nor its
Regulation Services Provider (as that term is defined in the
policies of the TSX Venture Exchange) accepts responsibility for
the adequacy or accuracy of this release.
This news release will not constitute an
offer to sell or the solicitation of an offer to buy the securities
in any jurisdiction. Such securities have not been registered under
the United States Securities Act
of 1933 and may not be offered or sold in the United States, or to a U.S. person, absent
registration, or an applicable exemption therefrom.
Advisory Regarding Forward-Looking
Statements
The information provided above includes
references to discovered and undiscovered oil and natural gas
resources. There is no certainty that any portion of the resources
will be discovered. If discovered, there is no certainty that it
will be commercially viable to produce any portion of the
resource.
This press release contains forward-looking
statements and forward-looking information within the meaning of
applicable securities laws. The use of any of the words
"expect", "anticipate",
"continue", "estimate",
"objective", "ongoing",
"may", "will", "project",
"should", "believe",
"plans", "intends" and similar expressions
are intended to identify forward-looking information or statements.
More particularly and without limitation, this press release
contains forward looking statements and information concerning the
company's petroleum and natural gas production; reserves;
undeveloped land holdings; business strategy; future development
and growth opportunities; prospects; asset base; future cash flows;
value and debt levels; capital programs; treatment under tax laws;
and oil and natural gas prices. The forward-looking statements and
information are based on certain key expectations and assumptions
made by Novus, including expectations and assumptions concerning
prevailing commodity prices and exchange rates, applicable royalty
rates and tax laws; future well production rates and reserve
volumes; the performance of existing wells; the success obtained in
drilling new wells; the sufficiency of budgeted capital
expenditures in carrying out planned activities; and the
availability and cost of labour and services. Although Novus
believes that the expectations and assumptions on which such
forward-looking statements and information are based are
reasonable, undue reliance should not be placed on the forward
looking statements and information because Novus can give no
assurance that they will prove to be correct. Since forward-looking
statements and information address future events and conditions, by
their very nature they involve 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 reserve estimates; the uncertainty of estimates and
projections relating to reserves, production, costs and expenses;
health, safety and environmental risks; commodity price and
exchange rate fluctuations; marketing and transportation; loss of
markets; environmental risks; competition; incorrect assessment of
the value of acquisitions; failure to realize the anticipated
benefits of acquisitions; 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 Novus' operations or financial
results are included in reports on file with applicable securities
regulatory authorities and may be accessed through the SEDAR
website (www.sedar.com), and at Novus' website
(www.novusenergy.ca). The forward-looking statements and
information contained in this press release are made as of the date
hereof and Novus undertakes no obligation to update publicly or
revise any forward-looking statements or information, whether as a
result of new information, future events or otherwise, unless so
required by applicable securities laws.
Special Note Regarding Disclosure of Reserves or
Resources
"Discovered Petroleum
Initially-In-Place" (equivalent to discovered resources) is
defined in the Canadian Oil and Gas Evaluation Handbook as that
quantity of petroleum that is estimated, as of a given date, to be
contained in known accumulations prior to production. The
recoverable portion of discovered petroleum initially-in-place
includes production, reserves, and contingent resources; the
remainder is unrecoverable. "Contingent resources" are defined in
the COGE Handbook as those quantities of petroleum estimated to be
potentially recoverable from known accumulations using established
technology or technology under development, but which are not
currently considered to be commercially recoverable due to one or
more contingencies. Contingencies may include factors such as
economic, legal, environmental, political, and regulatory
matters, or a lack of markets. It is also appropriate to classify
as contingent resources the estimated discovered recoverable
quantities associated with a project in the early evaluation stage.
The Contingent Resources estimates and the DPIIP estimates are
estimates only and the actual results may be greater than or less
than the estimates provided herein. There is no certainty
that it will be commercially viable to produce any portion of the
resources except to the extent identified as proved or
probable reserves. "Best estimate" is defined in the COGE Handbook
with respect to entity level estimates, as the value derived by an
evaluator using deterministic methods that best represent the
expected outcome with no optimism or conservatism. If probabilistic
methods are used, there should be at least a 50 percent probability
(P50) that the quantities actually recovered will equal or exceed
the best estimate.
SOURCE Novus Energy Inc.