Mr. Hugh Ross reports
NOVUS ENERGY INC. REPORTS SIGNIFICANT 2011 RESERVES & PRODUCTION GROWTH AND PROVIDES 2012 CAPITAL BUDGET GUIDANCE
Novus Energy Inc. has substantially increased its reserves and production from its successful 2011 capital program.
The company is also pleased to release its 2012 production and capital
budget guidance which demonstrates another year of significant growth.
The company's year-end independent reserve evaluation was prepared by
Sproule Associates Ltd. effective Dec. 31, 2011.
2011 reserve highlights
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Proved reserves at Dec. 31, 2011, increased by 83 per cent to 8.84 million
barrels of oil equivalent, up substantially from 4.83 million boe on Dec. 31, 2010.
-
Proved plus probable reserves at Dec. 31, 2011, increased by 58 per cent to
14.56 million boe, up from 9.24 million boe on Dec. 31, 2010.
-
The net present value of proved plus probable reserves, before income
tax and discounted at 10 per cent, increased 102 per cent to $331.3-million up from
$164.2-million at Dec. 31, 2010, representing an increase of $167.1-million.
-
The company's fully diluted net asset value per share increased
dramatically to $1.64.
-
Total proved reserves increased 81 per cent on a per share basis, and proved
plus probable reserves increased 56 per cent on a per share basis.
-
Oil and natural gas liquids (NGLs) at Dec. 31, 2011, represent 82 per cent
of proved plus probable reserves on a boe basis and 82 per cent of total proved
reserves.
-
Total proved reserves at Dec. 31, 2011, represent 61 per cent of total proved
plus probable reserves, up from 52 per cent on Dec. 31, 2010.
-
Reserve replacement for the year was 839 per cent on a proved plus probable
basis and 658 per cent based on proved reserves.
-
The company's reserve life index at Dec. 31, 2011, was 14.0 years on
a proved plus probable basis and 8.5 years on a proved basis (based on
annualized fourth quarter 2011 production).
-
Finding, development and acquisition costs, excluding future development
capital (FDC), were $12.16 per boe for proved plus probable reserves and
$15.51/boe for proved reserves. Including FDC, finding, development
and acquisition costs were $20.18/boe for proved plus probable reserves
and $25.66/boe for proved reserves.
-
In the Dodsland area of Saskatchewan, which encompasses the company's
core Viking light oil properties, the 2011 capital program resulted in
a 72-per-cent increase in proved plus probable reserves. The Dodsland area
accounts for 13.3 million boe of proved plus probable reserves which
represent 91 per cent of the company's total proved plus probable reserve
volumes.
-
Sproule has provided Novus with an updated independent contingent
resource assessment for the company's Dodsland Viking light oil assets, the intent of which was to
independently assess the contingent resource potential of the area.
The contingent resource assessment, effective as at Dec. 31, 2011,
reports a "best estimate" of discovered petroleum initially in place
(DPIIP) on Novus working interest and option lands totalling 644.8
million barrels (MMSTB) of light Viking oil, up 15 per cent from Nov. 30,
2010. This estimate consists of 527.9 MMSTB on company-owned land and
an additional 116.9 MMSTB on lands under option to Novus. Eighty-two per cent of the
DPIIP now reside on Novus working interest land up from 68 per cent at Nov. 30, 2010. In the contingent resource assessment, approximately 56 per cent of
the net acreage controlled by Novus (56.9 net sections owned and 9.9
net sections under option) was recognized by Sproule as containing
DPIIP.
-
As part of the contingent resource assessment, Sproule included
estimates of recoverable contingent resource volumes beyond booked
reserves captured in the Dec. 31, 2011, reserve report. The
contingent resource assessment reports a best estimate of contingent
resources on Novus working interest and option lands totalling 11.8
MMSTB, which are economic at current prices and costs. This estimate
consists of 7.9 MMSTB on company-owned land and an additional 3.9 MMSTB
on lands under option to Novus.
-
Total proved plus probable reserves plus the best estimate of
recoverable contingent resources represent approximately 4 per cent of the
DPIIP.
2011 operational highlights
-
The company began its 2012 drilling program on Feb. 1, and has
drilled two wells to date.
-
The company's average production for 2011 was an estimated 1,971 barrels of oil equivalent per day,
representing 77-per-cent year-over-year average production volume growth.
-
Novus achieved record production of an estimated 2,845 boe/d in the
fourth quarter of 2011 (83 per cent oil and liquids) representing an 81-per-cent
increase over fourth quarter 2010 production volumes.
-
Operating netbacks in the fourth quarter of 2011 for the company's
Viking light oil production in Dodsland were estimated to be a record
$68.34/boe.
-
Novus achieved a recycle ratio of 3.9 times for the current year for
proved plus probable reserves based on 2011 finding, development and
acquisition costs excluding FDC and a 2011 corporate operating netback
of $47.17/boe.
-
During 2011, Novus achieved a 100-per-cent success rate on its Dodsland area
Viking oil drilling campaign. Novus operated the drilling of 52 wells
throughout the year, all using horizontal multistage frac technology.
-
Results from the company's Flaxcombe lands in the Dodsland area continue
to materially exceed expectations. In 2011, Novus drilled 16 wells in
the area with 90-day average rates, excluding associated gas production
volumes, of 64 barrels per day.
-
Well costs in the Dodsland area continued to decrease in 2011, with
costs for drilling and completions averaging approximately $835,000, tie-in costs averaging $95,000 and on stream costs
averaging $930,000 per well.
-
Novus currently controls 119 net sections of Viking rights, and has a
risked drilling inventory of 610 net, undrilled Viking oil locations
based on eight-well-per-section spacing and the development of only one
of the two distinct cycles present on its Flaxcombe lands.
2012 capital program
With the continued success the company has enjoyed with its large land
position in the Dodsland Viking light oil resource play of southwestern
Saskatchewan, the 2012 capital expenditure budget of $81-million will
exclusively be devoted to light oil development drilling activity in
the area. This budget will incorporate the drilling of 73 wells (73
net), all of which will be horizontal multistage frac wells targeting
Viking oil in Dodsland. In addition to drilling, the company is
planning to expend capital on facilities, pipelines and battery
expansions in the Dodsland area. No capital has been budgeted for
acquisitions although the company continues to evaluate new
opportunities within and similar to its existing core area. Novus will
have complete control over its 2012 capital program, with 100 per cent of
budgeted expenditures for the year being operated by the company.
Production volumes
The 2012 capital budget is expected to result in 2012 average production
of 3,300 boe/d (84 per cent oil and liquids) which represents growth of
approximately 67 per cent over the estimated 2011 average production rate. The
forecasted 2012 exit production rate is 4,500 boe/d, 85 per cent of which will
be oil and liquids.
Financial position
The company ended the 2011 fiscal year with estimated net debt of $49-million, against a line of credit of $60-million. Novus will provide
its lender with the Sproule report and have its credit facility
reviewed in conjunction with finalizing its 2011 audited financial
statements.
Novus's 2012 capital budget will be entirely financed through internally
generated funds flow, proceeds from in the money warrant exercises and
its existing line of credit. Two thousand twelve year-end net debt is estimated to be
approximately $59-million, and would result in Novus having a debt to
annualized fourth quarter 2012 funds flow ratio of approximately 0.8
times. The company expects to see positive funds flow from operations
of $52-million for 2012. This forecast is based on an oil price of $95 (U.S.) West Texas Institute per barrel, an AECO natural gas price of $2.50 (Canadian) per
million British thermal units and an exchange rate of $1 (Canadian) to $1 (U.S.).
At the end of 2011, Novus estimates it had in excess of $230-million of
tax pools which provide significant flexibility and shelter for cash
taxes in 2012 and future years.
2012 guidance summary (1)
Net capital expenditures: $81-million
Net wells drilled: 73
Average production volumes: 3,300 boe/d (84 per cent oil and liquids)
Exit production volumes: 4,500 boe/d (85 per cent oil and liquids)
Funds flow from operations: $52-million
Fourth quarter annualized funds flow from operations: $70-million
2012 estimated year-end net debt: $59-million
Crude oil pricing: $95 (U.S.) WTI
Natural gas pricing: $2.50 (Canadian) per mmbtu
Exchange rate: $1 (Canadian)/$1 (U.S.)
(1) The projection of capital expenditures excludes corporate and property acquisitions, which are separately considered and evaluated.
Key Viking resource play
Novus had a very active and highly successful year in 2011. The large
reserve additions the company obtained were almost exclusively
generated in its key Viking light oil resource play in Dodsland,
Sask. Virtually all of the proved and probable reserve growth
the company achieved came from organic drilling. The attractive
finding, development and acquisition costs and healthy recycle ratio
validate the growth strategy of assembling a predictable, low-risk,
multiyear drilling inventory within a concentrated core area.
Novus begins 2012 with an extensive light oil development drilling
inventory of more than 600 net locations which represent over eight
years of development potential. This already significant opportunity
base does not reflect the ability to down space from eight wells to 16
wells per section or the future potential to water flood the
reservoir. Novus believes that the development of the Viking resource
is in its early stages and that there is further significant upside to
recovery factors by applying secondary recovery methods. Novus shall
continue to actively drill its existing land base, and shall remain
focused on expanding its presence within this large oil resource play.
Novus has been focused on continually lowering its drilling and
completion costs, employing new completion techniques to improve the
economic performance of its wells, and building the necessary area
infrastructure to support stable, low operating cost production.
Upgrades at Novus's owned and operated facilities at Whiteside and Avon
Hills were completed in the fourth quarter of 2011 which increased
fluid handling capacities at each facility. An exclusive agreement was
signed with a third party to take the company's wet solution gas in
Whiteside and will significantly reduce operating costs. Construction
of a sales gas line and emulsion line from the Whiteside facility to
the meter station was also completed.
Novus is currently running an emulsion line from its core facility at
Whiteside to the Flaxcombe field and a total of 22 wells in the
southern portion of the area will be tied in and have their gas
production conserved. This line will be used to tie in all new wells
drilled in the Flaxcombe area throughout 2012 and will serve to reduce
downtime and reduce future operating costs.
Novus's operating costs have continued to materially decrease from
$18.20/boe in the first quarter of 2011 to an estimated $12.88/boe in
the fourth quarter of 2011. The company's fourth quarter 2011
operating costs for its Viking production were estimated to be
$8.96/boe, with further reductions anticipated in the second quarter of
2012 once all facility upgrades are completed.
Based upon the stable production rates, highly economic netbacks,
significant recoverable reserves, and lower drilling and completion
costs in the Dodsland area the company has experienced to date, Novus
plans on maintaining an aggressive drilling program on its current
acreage and will continue its efforts to further consolidate and expand
its position within the area through acquisitions. With a strong
technical team and continual evolution by industry and the company in
lowering costs and improving production in its Viking light oil play,
Novus is once again poised to exhibit strong growth in the coming year.
Landholdings
Of the total corporate net undeveloped acres, 80 per cent or 103,327 net acres
are situated in Saskatchewan.
A summary of the company's landholdings at Dec. 31, 2011, is
outlined in the table.
(acres) Developed Undeveloped Total
Gross Net Gross Net Gross Net
Alberta 70,198 35,804 38,640 25,694 108,838 61,498
Saskatchewan 20,189 14,800 110,670 103,327 130,859 118,127
Other 1,943 1,347 1,943 932 3,886 2,279
Total 92,330 51,951 151,253 129,953 243,583 181,904
Reserves
The reserves data set forth below are 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 the 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 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 the company's 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
Gross Net Gross Net Gross Net
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
Proved
Producing 2,223.9 1,982.6 36.7 30.2 92.4 62.1
Non-producing - - - - 3.4 2.8
Undeveloped 4,817.0 4,303.6 25.0 20.6 16.4 14.1
Total proved 7,040.9 6,286.2 61.7 50.9 112.2 79.0
Probable 4,533.4 4,136.4 108.6 89.6 56.2 39.6
Total proved plus probable 11,574.3 10,422.6 170.3 140.5 168.4 118.6
Natural gas barrels of oil equivalent
Gross Net Gross Net
(Mmcf) (Mmcf) (Mboe) (Mboe)
Proved
Producing 2,952 2,586 2,845.0 2,505.9
Non-producing 1,357 1,074 229.5 181.8
Undeveloped 5,470 4,973 5,770.2 5,167.1
Total proved 9,779 8,633 8,844.6 7,854.8
Probable 6,084 5,459 5,712.2 5,175.5
Total proved plus probable 15,863 14,092 14,556.8 13,030.3
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 Dec. 31, 2011, and based on Sproule's
Dec. 31, 2011, future price forecast, are summarized in the
table.
(M$) 0% 5% 10% 15% 20%
Proved
Producing 127,892 112,869 101,459 92,548 85,416
Non-producing 1,615 668 57 (355) (644)
Undeveloped 165,559 122,897 92,387 70,047 53,332
Total proved 295,066 236,434 193,903 162,240 138,105
Probable 275,598 189,629 137,376 103,762 81,046
Total proved plus probable 570,664 426,063 331,279 266,002 219,151
Notes:
Net present value of future net revenue includes all resource income:
* Sale of oil, gas and byproduct reserves;
* Processing third party reserves;
* Other income.
Values are based on net reserve volumes.
Columns may not add due to rounding.
Price forecast
The Dec. 31, 2011, Sproule price forecast is summarized as displayed in the table.
Alberta Hardisty Natural gas at
U.S.$/Cdn$ WTI at Cushing Edmonton light Bow River AECO-C spot
Year exchange rate (U.S.$/bbl) (C$/bbl) (C$/bbl) (C$/Mmbtu)
2012 1.012 98.07 96.87 82.34 3.16
2013 1.012 94.90 93.75 79.69 3.78
2014 1.012 92.00 90.89 77.25 4.13
2015 1.012 97.42 96.23 81.80 5.53
2016 1.012 99.37 98.16 83.44 5.65
2017 1.012 101.35 100.12 85.10 5.77
2018 1.012 103.38 102.12 86.81 5.89
2019 1.012 105.45 104.17 88.54 6.01
2020 1.012 107.56 106.25 90.31 6.14
2021 1.012 109.71 108.38 92.12 6.27
2022+ 1.012 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
Note: Inflation is accounted for at 2 per cent per year.
Finding, development and acquisition costs (FD&A)
Novus's F&D and FD&A costs for 2011, 2010 and the three-year average are
presented in the tables. The costs used in the F&D and FD&A
calculation 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 tables are in thousands of dollars unless
otherwise stated).
Finding and development costs -- proved (000s, except $/boe amounts) 2011 2010 Three-year average
Capital expenditures (excluding acquisitions and dispositions) $73,990 $53,711 $44,358
Change in future development capital 53,657 77,895 45,142
Total capital for F&D 127,647 131,606 89,500
Reserve additions, excluding acquisitions and dispositions 4,665.1 3,333.8 2,793.8
Proved F&D costs -- including future development capital ($/boe) 27.36 39.48 32.04
Proved F&D costs -- excluding future development capital ($/boe) 15.86 16.11 15.88
Finding and development costs -- proved plus probable (000s, except
$/boe amounts) 2011 2010 Three-year average
Capital expenditures (excluding acquisitions and dispositions) $73,990 $53,711 $44,358
Change in future development capital 58,889 105,102 56,330
Total capital for F&D 132,879 158,813 100,688
Reserve additions, excluding acquisitions and dispositions 5,896.4 6,382.9 4,236.6
Proved plus probable F&D costs -- including future development
capital ($/boe) 22.54 24.88 23.77
Proved plus probable F&D costs -- excluding future development
capital ($/boe) 12.55 8.41 10.47
Finding, development and acquisition costs -- proved (000s, except
$/boe amounts) 2011 2010 Three-year average
Capital expenditures (including acquisitions, net of dispositions) $73,411 $68,349 $56,738
Change in future development capital 48,052 83,509 46,212
Total capital for FD&A 121,463 151,858 102,950
Reserve additions, including net acquisitions 4,734.2 3,770.3 3,038.2
Proved FD&A costs -- including future development capital ($/boe) 25.66 40.28 33.89
Proved FD&A costs -- excluding future development capital ($/boe) 15.51 18.13 18.67
Finding, development and acquisition costs -- proved plus probable
(000s, except $/boe amounts) 2011 2010 Three-year average
Capital expenditures (including acquisitions, net of dispositions) $73,411 $68,349 $56,738
Change in future development capital 48,416 115,584 58,150
Total capital for FD&A 121,827 183,933 114,888
Reserve additions, including net acquisitions 6,037.6 7,138.4 4,676.5
Proved plus probable FD&A costs -- including future capital ($/boe) 20.18 25.77 24.57
Proved plus probable FD&A costs -- excluding future capital ($/boe) 12.16 9.57 12.13
Notes:
The reserves used in the calculations are company gross reserves
additions, including revisions.
The 2011 capital expenditures used in the calculations are
unaudited as the company's 2011 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's 2011 FD&A activities replaced 839 per cent of production on a proved plus
probable basis and 658 per cent on a proved basis.
Production (Mboe) 719.2
Proved plus probable reserve additions (Mboe) 6,037.6
Proved plus probable reserve replacement 839%
Proved reserve additions (Mboe) 4,734.2
Proved reserve replacement 658%
NET ASSET VALUE SUMMARY
(000s, except per share amounts)
Dec. 31, 2011
Proved plus probable reserves (1) $331,279
Net undeveloped land (2) 32,488
Dilutive proceeds 32,939
Net debt (49,000)
Total net asset value $347,706
Number of fully diluted shares 212,035
Net asset value per share $1.64
Notes:
Before tax, discounted at 10 per cent.
Net undeveloped land has been valued at $250/acre.
No value has been assigned to seismic or intangible assets.
Outlook
Novus's strategic direction remains unchanged. The company is
competitively positioned in the repeatable, low-risk, highly economic
Viking oil resource play in west-central Saskatchewan with 119 net
sections of land and 610 net risked drilling locations. The core of
the company's development program in 2012 and beyond will focus on
further exploitation of its sizable opportunity base.
The company's priorities in 2012 are:
-
Use its strong balance sheet to finance a non-dilutive drilling program
which will maintain the company's impressive annual growth profile;
-
Continue to improve operating efficiencies through further reductions in
its cost structure;
-
Continue to grow the company's production and reserves on a per share
basis;
-
Evaluate opportunities to continually increase its oil resource focus
through further acquisitions.
We seek Safe Harbor.
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