Mr. J. Craig Anderson reports

DELOITTE ECONOMIC ASSESSMENT OF BAGPUSS AND BLOFELD PROSPECTS

North Sea Energy Inc. has released 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 on April 30, 2014, utilized the resource and geologic information developed by Senergy (GB) Ltd. 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 per cent, 28 per cent and 51 per cent, 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 10-per-cent discounted net present value of the project. Under this scenario (first production in 2019), a net decrease in the 10-per-cent discounted net present value of 30 per cent, 25 per cent and 22 per cent is estimated for the best, mean, and high cases, respectively.

The attached tables summarize the potential economics of the prospects.

Net present value before tax (NSE)                     0.00%          5.00%

Low      Sum of discounted cash flows (mm $)   $     126.85   $      (8.35)
IRR      Total company share production (mboe)     4,555.13       4,555.13
4.5%     Implied $/boe                         $      27.85   $      (1.83)
Best     Sum of discounted cash flows (mm $)   $   1,406.39   $     647.08
IRR      Total company share production (mboe)    20,816.24      20,816.24
26%      Implied $/boe                         $      67.56   $      31.09
High     Sum of discounted cash flows (mm $)   $   6,536.02   $   3,291.28
IRR      Total company share production (mboe)    90,006.73      90,006.73
67%      Implied $/boe                         $      72.62   $      36.57
Mean     Sum of discounted cash flows (mm $)   $   2,656.38   $   1,296.08
IRR      Total company share production (mboe)    38,148.00      38,148.00
39%      Implied $/boe                         $      69.63   $      33.98

Net present value after tax (NSE)                      0.00%          5.00%

Low      Sum of discounted cash flows (mm $)   $     (14.30)  $     (73.61)
IRR      Total company share production (mboe)     4,555.13       4,555.13
-1%      Implied $/boe                         $      (3.14)  $     (16.16)
Best     Sum of discounted cash flows (mm $)   $     719.47   $     303.83
IRR      Total company share production (mboe)    20,816.24      20,816.24
18%      Implied $/boe                         $      34.56   $      14.60
High     Sum of discounted cash flows (mm $)   $   2,695.08   $   1,401.09
IRR      Total company share production (mboe)    90,006.73      90,006.73
51%      Implied $/boe                         $      29.94   $      15.57
Mean     Sum of discounted cash flows (mm $)   $   1,200.65   $     574.55
IRR      Total company share production (mboe)    38,148.00      38,148.00
28%      Implied $/boe                         $      31.47   $      15.06

Net present value before tax (NSE)                    10.00%         15.00%

Low      Sum of discounted cash flows (mm $)   $     (65.30)  $     (90.33)
IRR      Total company share production (mboe)     4,555.13       4,555.13
4.5%     Implied $/boe                         $     (14.33)  $     (19.83)
Best     Sum of discounted cash flows (mm $)   $     311.70   $     146.23
IRR      Total company share production (mboe)    20,816.24      20,816.24
26%      Implied $/boe                         $      14.97   $       7.02
High     Sum of discounted cash flows (mm $)   $   1,842.35   $   1,112.26
IRR      Total company share production (mboe)    90,006.73      90,006.73
67%      Implied $/boe                         $      20.47   $      12.36
Mean     Sum of discounted cash flows (mm $)   $     689.51   $     385.71
IRR      Total company share production (mboe)    38,148.00      38,148.00
39%      Implied $/boe                         $      18.07   $      10.11

Net present value after tax (NSE)                     10.00%         15.00%

Low      Sum of discounted cash flows (mm $)   $     (99.33)  $    (109.87)
IRR      Total company share production (mboe)     4,555.13       4,555.13
-1%      Implied $/boe                         $     (21.81)  $     (24.12)
Best     Sum of discounted cash flows (mm $)   $     121.28   $      32.01
IRR      Total company share production (mboe)    20,816.24      20,816.24
18%      Implied $/boe                         $       5.83   $       1.54
High     Sum of discounted cash flows (mm $)   $     799.39   $     485.28
IRR      Total company share production (mboe)    90,006.73      90,006.73
51%      Implied $/boe                         $       8.88   $       5.39
Mean     Sum of discounted cash flows (mm $)   $     290.12   $     145.62
IRR      Total company share production (mboe)    38,148.00      38,148.00
28%      Implied $/boe                         $       7.61   $       3.82

Introduction

North Sea Energy holds a 15-per-cent working interest in offshore mineral rights in the Bagpuss and Blofeld prospects of blocks 13/24c and 13/25 (licence P1943). North Sea Energy farmed out a 25-per-cent working interest in the blocks to Maersk Oil, effective August, 2013. Under the farm-in agreement, Maersk Oil is to carry 100 per cent 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 per cent of NSE's costs, subject to a cap, on a Bagpuss appraisal well should one be drilled. Premier Oil PLC, EnCounter Oil and Groliffe Ltd. hold the remaining 37.5-per-cent, 15-per-cent and 7.5-per-cent 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, U.K. 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 feet. 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 2-D seismic survey covering 1,051 line kilometres 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-per-cent 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 in February, 2010. These data were 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 were 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 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 per cent 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 U.K. NBP escalated reference price included in the Deloitte March 31, 2014, price forecast. A 50 cents per thousand cubic feet 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 per cent, with the remaining 35 per cent being allocated as variable costs. A summary of the estimated capital and operating costs is provided in the table.

              CAPITAL AND OPERATING EXPENDITURE ASSUMPTIONS

Exploration and appraisal (mm $)                            57.41    50.79
Predevelopment/feed (mm $)                                  25.39    25.39
Facilities (mm $)                                          545.42   545.42
D, C & T development wells (mm $/well)                      13.20    13.20
Fixed cost per well per year (mm $)                           813      813
Variable cost per barrel ($/bbl)                             3.68     3.68

Predevelopment 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-million per well, for both horizontal producers and vertical injectors. All costs have been inflated at a rate of 2 per cent per year.

Tax rates

The tax/fiscal regime applied to this assessment is based on Deloitte's interpretation of the U.K. government's ultraheavy oil field tax relief program, applicable to crudes of 18 degrees API or heavier. Under this program, a reduced tax rate of 30 per cent is applicable up to 800 million British pounds allowance (to a maximum of 160 million British pounds annually), with the remainder of the income being taxed at 62 per cent. 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).

We seek Safe Harbor.