TORONTO, ONTARIO
-- (Marketwired)
-- 05/02/14
North Sea Energy Inc. ("NSE" or the "Company") (TSX VENTURE: NUK) is pleased to announce the results of an independent "Economic Assessment of Blocks 13/24c and 13/25 (Bagpuss and Blofeld), North Sea, United Kingdom". This report issued by Deloitte LLP ("Deloitte") on April 30, 2014, utilized the resource and geologic information developed by Senergy (GB) Limited ("Senergy") on June 25, 2013 with an effective date of May 30, 2013. (Please refer to the Company's press release issued on June 27, 2013 for discussion on the risks and level of uncertainty associated with recovery of the resources, the significant positive and negative factors relevant to the estimate of the resources.)
Conclusions
Deloitte's economic assessment of the Bagpuss and Blofeld prospects indicates that, on a cumulative basis, the Best, Mean, and High case resource estimates are commercial under the assumed development, pricing, and cost scenarios, yielding after-tax internal rates of return of approximately 18, 28, and 51 percent, respectively.
A sensitivity to the economic scenarios discussed above was run to estimate the effect of a three-year delay in the development of the Bagpuss and Blofeld prospects on the NPV10 of the project. Under this scenario (first production in 2019), a net decrease in NPV10 of 30, 25, 22 percent is estimated for the Best, Mean, and High cases, respectively.
The following tables summarise the potential economics of the prospects as follows:
Net Present Value BTAX (NSE) 0.00% 5.00%
Low Sum of Discounted Cash Flows (MM$) $ 126.85 $ (8.35)
IRR Total Company Share Prod. (Mboe) 4,555.13 4,555.13
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4.5% Implied $/boe $ 27.85 $ (1.83)
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Best Sum of Discounted Cash Flows (MM$) $ 1,406.39 $ 647.08
IRR Total Company Share Prod. (Mboe) 20,816.24 20,816.24
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26% Implied $/boe $ 67.56 $ 31.09
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High Sum of Discounted Cash Flows (MM$) $ 6,536.02 $ 3,291.28
IRR Total Company Share Prod. (Mboe) 90,006.73 90,006.73
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67% Implied $/boe $ 72.62 $ 36.57
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Mean Sum of Discounted Cash Flows (MM$) $ 2,656.38 $ 1,296.08
IRR Total Company Share Prod. (Mboe) 38, 148.00 38, 148.00
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39% Implied $/boe $ 69.63 $ 33.98
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Net Present Value ATAX (NSE) 0.00% 5.00%
Low Sum of Discounted Cash Flows (MM$) $ (14.30) $ (73.61)
IRR Total Company Share Prod. (Mboe) 4,555.13 4,555.13
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-1% Implied $/boe $ (3.14) $ (16.16)
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Best Sum of Discounted Cash Flows (MM$) $ 719.47 $ 303.83
IRR Total Company Share Prod. (Mboe) 20,816.24 20,816.24
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18% Implied $/boe $ 34.56 $ 14.60
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High Sum of Discounted Cash Flows (MM$) $ 2,695.08 $ 1,401.09
IRR Total Company Share Prod. (Mboe) 90,006.73 90,006.73
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51% Implied $/boe $ 29.94 $ 15.57
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Mean Sum of Discounted Cash Flows (MM$) $ 1,200.65 $ 574.55
IRR Total Company Share Prod. (Mboe) 38,148.00 38,148.00
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28% Implied $/boe $ 31.47 $ 15.06
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Net Present Value BTAX (NSE) 10.00% 15.00%
Low Sum of Discounted Cash Flows (MM$) $ (65.30) $ (90.33)
IRR Total Company Share Prod. (Mboe) 4,555.13 4,555.13
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4.5% Implied $/boe $ (14.33) $ (19.83)
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Best Sum of Discounted Cash Flows (MM$) $ 311.70 $ 146.23
IRR Total Company Share Prod. (Mboe) 20,816.24 20,816.24
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26% Implied $/boe $ 14.97 $ 7.02
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High Sum of Discounted Cash Flows (MM$) $ 1,842.35 $ 1,112.26
IRR Total Company Share Prod. (Mboe) 90,006.73 90,006.73
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67% Implied $/boe $ 20.47 $ 12.36
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Mean Sum of Discounted Cash Flows (MM$) $ 689.51 $ 385.71
IRR Total Company Share Prod. (Mboe) 38, 148.00 38, 148.00
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39% Implied $/boe $ 18.07 $ 10.11
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Net Present Value ATAX (NSE) 10.00% 15.00%
Low Sum of Discounted Cash Flows (MM$) $ (99.33) $ (109.87)
IRR Total Company Share Prod. (Mboe) 4,555.13 4,555.13
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-1% Implied $/boe $ (21.81) $ (24.12)
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Best Sum of Discounted Cash Flows (MM$) $ 121.28 $ 32.01
IRR Total Company Share Prod. (Mboe) 20,816.24 20,816.24
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18% Implied $/boe $ 5.83 $ 1.54
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High Sum of Discounted Cash Flows (MM$) $ 799.39 $ 485.28
IRR Total Company Share Prod. (Mboe) 90,006.73 90,006.73
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51% Implied $/boe $ 8.88 $ 5.39
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Mean Sum of Discounted Cash Flows (MM$) $ 290.12 $ 145.62
IRR Total Company Share Prod. (Mboe) 38,148.00 38,148.00
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28% Implied $/boe $ 7.61 $ 3.82
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Introduction
North Sea Energy holds a 15 percent working interest in offshore mineral rights in the Bagpuss and Blofeld prospects of Blocks 13/24c and 13/25 (License P1943). North Sea Energy farmed out a 25 percent working interest in the Blocks to Maersk Oil, effective August 2013. Under the farm-in agreement, Maersk Oil is to carry 100 percent of NSE's costs, subject to a cap, to drill the initial Bagpuss Prospect exploration well including a site survey and agreed past costs. In addition, Maersk Oil is to carry 50 percent of NSE's costs, subject to a cap, on a Bagpuss appraisal well should one be drilled. Premier Oil Plc., EnCounter Oil, and Groliffe Limited hold the remaining 37.5, 15.0, and 7.5 percent working interests in the Blocks, respectively. Premier Oil took over as operator of the Blocks from EnCounter Oil in November 2013.
The Bagpuss and Blofeld prospects are located on the central margin of the Halibut Horst, which is a well-defined basement uplift at the eastern extremity of the Inner Moray Firth, in the North Sea, United Kingdom. The Blocks are adjacent to the producing Blake and Captain Fields. The Bagpuss and Blofeld prospects are structural closures with an interpreted Lower Cretaceous reservoir, located at a relatively shallow depth of approximately 1,500 feet subsurface. The joint venture partnership is also targeting the Granite Wash and the Granite zones that sit below the Bagpuss and Blofeld prospects.
Field activity
The acreage containing the Bagpuss and Blofeld prospects was first drilled by Amoco in 1981. Well 13/24a-2A encountered basement at 1,321 feet subsea, significantly higher than anticipated. The well encountered potentially prospective intervals between the Lower Cretaceous sandstones and the underlying Granite Wash interval, as evidenced by oil shows. The obtained bottom-hole core indicated a potential oil column of over 225 ft. However, well 13/24a-2A was plugged and abandoned as a dry well by Amoco. Blocks 13/24c and 13/25 were subsequently owned by a group of companies led by Petro Canada, which further assessed the prospects through the acquisition of a high-resolution 2D seismic survey covering 1,051 line-km of data in July 2007. Petro Canada relinquished the prospects in 2010 after outlining development plans and production scenarios. Petro Canada had characterized the first well at Bagpuss (then known as Fat Cat) as appraisal risk, with a 56 percent chance of success.
Exploration Interest in the area has revived due to the successful development of the heavy oil Captain Field which also lies west along the Halibut Horst.
Available data
The estimates of recoverable petroleum volumes included in the economic projections are based on an independent review of the prospective resources associated with Blocks 13/24c and 13/25 prepared by Senergy according to the standards set out in the Canadian Oil and Gas Evaluation Handbook (COGEH) and in compliance with the requirements of National Instrument 51-101. Oil production forecasts were developed with consideration given to the performance and production history of the offsetting Captain Field, as published by the U.K. Department of Energy and Climate Change. The economic assumptions employed herein are based on data and projections presented by Petro Canada for Blocks 13/24d and 13/25a in a Relinquishment Report submitted to the Department of Energy and Climate Change (DECC) in February 2010. This data was used in conjunction with Deloitte's experience in offshore petroleum evaluations to build cash flow projections over the economic life of the project and draw conclusions on its commerciality going forward.
Resource estimates
The stochastic resource estimates that form the basis of this economic assessment were prepared in independence and compliance with NI 51-101 regulations by Senergy, based on data made available by North Sea Energy and the operator of the Blocks, EnCounter. The data comprised operator information, geological, geophysical, and engineering information and interpretations along with a series of technical reports. Where necessary and applicable, additional data was obtained by the independent evaluator from the public domain. Deloitte has conducted a qualitative review of the methodology employed by Senergy and the available sources of information and concluded that all relevant factors impacting the evaluation of these assets were considered, including interpretation of geological structures and prospective zones, geological risks and historical drilling data from the 13/24a-2A well. As such, the results and interpretation presented by Senergy appear within reason.
Oil pricing
Shallow fields with subsurface depths similar to those expected at Bagpuss and Blofeld are generally associated with the production of heavier crudes. For the purposes of this assessment, an oil quality of 19-21 API has been assumed based on analogy to the offsetting Captain Field. Heavy crudes, such as the Mexican Maya, trade at approximately 90 percent of the Brent Light Crude spot price. This discount was applied to Brent Spot prices, as projected in the Deloitte March 31, 2014 price forecast.
The gas prices forecast in this assessment are based on the UK NBP Escalated reference price included in the Deloitte March 31, 2014 Price Forecast. A $0.50/Mcf deduction was applied to account for gas transportation costs.
Capital and operating expenses
The relinquishment report submitted by Petro Canada was the basis of the capital and operating costs assumptions used in this economic assessment. As the relinquishment report was prepared in 2010, cost estimates have been adjusted for inflation. It is important to note that the production and well operating costs have been assumed to have a fixed component of 65 percent, with the remaining 35 percent being allocated as variable costs. A summary of the estimated capital and operating costs is provided below:
Table 4 - Capital and operating expenditure assumptions
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Exploration & Appraisal(1) (MM$) 57.41 50.79
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Pre-Development/FEED (MM$) 25.39 25.39
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Facilities (MM$) 545.42 545.42
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D, C & T Development Wells (MM$/well)(2) 13.20 13.20
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Fixed cost/ well/ year (MM$) 813 813
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Variable cost / bbl ($/bbl) 3.68 3.68
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Pre-development expenditures are expected to be incurred in 2015, with first oil projected for 2016. All cases assume that the operator will elect to purchase (rather than lease) the FPSO units for the two Blocks. Abandonment and reclamation costs were included at an average cost of 2.5 MM$ per well, for both horizontal producers and vertical injectors. All costs have been inflated at a rate of two percent per year.
Tax rates
The tax/ fiscal regime applied to this assessment is based on Deloitte's interpretation of the UK Government's Ultra Heavy Oilfield tax relief program, applicable to crudes of 18 degrees API or heavier. Under this program, a reduced tax rate of 30 percent is applicable up to GBP 800 MM allowance (to a maximum of GBP 160MM annually), with the remainder of the income being taxed at 62 percent. Tax relief for income is inclusive of operating and capital costs. For the purposes of this assessment, tax payments were offset by one year in the projected cash flows.
Before Tax Cash Flow
Based on the data and assumptions discussed above, Deloitte generated before and after tax cash flows for each level of probability (Low, Best, High, and Mean Cases, respectively). The tables and graphs below illustrate annual and cumulative before and after tax cash flows over the economic life of the Bagpuss and Blofeld prospects.
About North Sea Energy Inc.
North Sea Energy Inc. (TSX VENTURE: NUK) is an oil and gas company that holds a portfolio of high impact interests focused on the Moray Firth in the offshore UK North Sea. These interests include Bagpuss and Blofeld (blocks 13/24c and 13/25), Norfolk (blocks 12/16b and 12/17b), Cloud (block 14/29b), Del Monte (block 19/3) and Golden Phoenix (block 18/10a).
(1)Exploration and Appraisal costs were excluded under the assumption that Maersk Oil will carry 100% of NSE's costs, subject to a cap, to drill the initial Bagpuss Prospect exploration well and perform a site survey.
(2)Average drilling, completion, and tie-in cost for horizontal producer/ vertical injection wells.
As per CSA Staff Notice 51-327 initial production test results should be considered preliminary data and such data is not necessarily indicative of long-term performance or of ultimate recovery.
Although the Company believes that the expectations reflected in such independent economic analysis and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since the report and information addresses future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may 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 production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation.
Certain information included in this material constitutes "forward-looking statements". The words "expect", "will", "intend", "estimate" and similar expressions or statements that certain events or conditions "may" or "will" occur identify forward-looking statements. Forward-looking statements are necessarily based upon a number of estimates and assumptions that, while considered reasonable by management at the date the statements are made, are inherently subject to significant business, economic and competitive uncertainties and contingencies. North Sea Energy Inc. ("NSE" or the "Company") cautions the reader that such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company to be materially different from the Company's estimated future results, performance or achievements expressed or implied by those forward-looking statements and the forward-looking statements are not guarantees of future performance. These risks, uncertainties and other factors include, but are not limited to, risks associated with the oil and gas industry such as government regulation, environmental and reclamation risks, title disputes or claims, success of oil and gas activities, future commodity prices, costs of production, possible variation in oil and gas reserves, oil and gas resources, grade or recovery rates, failure of plant, equipment or processes to operate as anticipated, accidents, labour disputes, the timing of estimated future production, capital expenditures, financial market fluctuations, requirements for additional capital, conclusions of economic evaluations, limitations on insurance coverage, risks associated with using third party contractors and inflation. The Company disclaims any intention or obligation to update or revise any forward-looking statements whether as a result of new information, future events or otherwise, except as required by applicable law.
A prospect is an untested exploration target that is defined sufficiently to be considered drill-ready.
Prospective resources are those quantities of oil and gas estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Resource categories are as defined in the Canadian Oil and Gas Evaluation Handbook (COGEH).
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 resources. "Bagpuss and Blofeld" is a promote licence that expires on January 1, 2014 when a drill or drop commitment has to be made to the Department of Energy and Climate Change ("DECC").
All Blocks are subject to conditions imposed by DECC and may be relinquished if conditions are not met.
Net present value calculations do not represent the fair market value of the prospects.
Contacts:
North Sea Energy Inc.
J. Craig Anderson
(416) 366-4700
canderson@northseaenergy.ca
Auburn Partners Inc.
Wesleigh Carusi
647-430-8760
info@auburnparnters.com
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