Novus Energy Inc. reports significant 2012 reserves & production growth
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Novus Energy Inc. (TSXV:NVS)
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1 Month : From Mar 2013 to Apr 2013
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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.
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