Xcite Energy Regulatory News (XEL)

NOT FOR RELEASE, PUBLICATION OR DISTRIBUTION IN WHOLE OR IN PART DIRECTLY OR INDIRECTLY IN, INTO OR FROM ANY JURISDICTION WHERE TO DO SO WOULD CONSTITUTE A VIOLATION OF THE RELEVANT LAWS OR REGULATIONS OF SUCH JURISDICTION

LSE-AIM, TSX-V: XEL

8 April 2013

Xcite Energy Limited

("Xcite Energy" or the "Company")

Reserves Assessment on the Bentley Field

and

Statement of Reserves Data and other Oil and Gas Information (Form 51-101F1)

Following the successful completion of the pre-production well test in September 2012 and a new 3D seismic survey, Xcite Energy is pleased to announce the results from its updated reserves assessment report as prepared by TRACS.

Highlights

·; Mean PIIP for the Bentley field of 909 MMstb, increased from 550 MMstb as previously reported in February 2012.

·; 1P, 2P and 3P oil reserves for the Bentley field of 198 MMstb, 250 MMstb and 312 MMstb, respectively, based on an initial 35 year production period.

·; Projected P50 peak production rate of approximately 45,000 stb/d in the first phase development, increasing to approximately 57,000 stb/d in the second phase development.

·; NPV10 (after tax) value of oil reserves for the Bentley field of approximately $1.5 billion, $2.2 billion and $2.8 billion on a 1P, 2P and 3P basis, respectively.

·; An additional 46 MMstb of P50 Contingent Resources assigned to the Bentley field for recoverable volumes beyond the initial 35 years production period.

·; Aggregate, unrisked mean Prospective Resources assigned of approximately 96 MMstb, relating to prospects adjacent to the Bentley field and prospects as awarded in the recent UK Offshore 27th Licence Round.

See "Cautionary Language" below for a general explanation of the method and assumptions used in the above calculations.

Rupert Cole, Chief Executive Officer of Xcite Energy commented:

"I am very pleased to report this significant increase in both reserves and value attributable to our assets, which supports our long-held belief in the potential of the Bentley field. This 2P reserves update, at 250 million barrels, plus considerable upside potential, has exceeded our expectations. 

We have now moved Bentley from being a significant asset to one of the major strategic assets in the North Sea, which will be an important source of future employment and economic contribution to the UK for many years to come.

We shall now continue to move the project forward with on-going studies into the potential for enhanced oil recovery, which has yet to be factored into the reserves assessment. There isalso further scope for field optimisation in order to accelerate delivery of the Contingent Resources, as well as the potential for exploration barrels from our Prospective Resources.

Our next goal is to fund the future development of our assets.  Having put in place the RBL facility last year, we still see this as an important part of our future funding structure. By increasing our reserves so significantly and developing a more balanced phasing of production volumes, with approximately half of the 2P reserves now expected to be delivered from the first phase development wells, we anticipate being in a position to increase the borrowing capacity of the field considerably and we shall be discussing this with our existing and potential new lenders.

Based on this reserves update, it is also the right time to evaluate suitable farm-in partners for Bentley. We have demonstrated the value of the field, materially de-risked it ahead of development and we would expect potential partners to recognise these achievements.

Finally, an updated Field Development Plan will be submitted to DECC in the coming months, which will reflect the results of the successful well test last year and the greater capacity of the first phase of development.

I would like to take this opportunity, once again, to thank the entire Xcite Energy team for their unwavering belief in, and commitment to, this project, and for the application of their expertise to move the Bentley forward to become a strategic, development-ready asset. They should be rightfully proud of this immense achievement." 

Introduction

The Company is pleased to announce the results from the updated reserves assessment report ("RAR") dated 8 April 2013, with an effective date as at 31 December 2012, from AGR TRACS International Limited ("TRACS"), an independent, qualified reserves auditor and a wholly owned subsidiary of AGR Group (Holdings) Limited, incorporating the outcome from the Company's recent pre-production well test and analysis of 3D seismic data acquired in 2012.

In addition, the Company has filed under its profile on SEDAR (www.sedar.com) its annual Statement of Reserves Data and other Oil and Gas Information (Form 51-101F1) under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities and in accordance with the Canadian Oil and Gas Evaluation Handbook, with an effective date as at 31 December 2012.

The Form 51-101F1 is an annual statement required by Canadian regulations to be filed by the Company, which sets out its interests in oil and gas reserves, provides key data with respect to those interests and identifies changes, if any, which have occurred since the previous annual filing. The information contained in the Form 51-101F1 is taken directly from the RAR.

The Form 51-101F1 will be available on SEDAR at www.sedar.com

Oil and Gas Reserves and Resources

The Company's oil and gas reserves are held through its wholly owned subsidiary, Xcite Energy Resources Limited ("XER"), comprising 100% working interests in Blocks 9/3b, 9/3c, 9/3d, 9/4a, 9/8b and 9/9h which contain the Bentley field ("Bentley" or the "Field") and adjoining assets.

Since the TRACS report dated 17 February 2012, the Company has successfully completed a pre-production well test, confirming that the Bentley reservoir is capable of achieving sustained commercial flow rates of oil as well as demonstrating the viability of the Company's multi-lateral well drilling and completion designs.

The Company also acquired a new 3D seismic survey in 2012, providing increased data quality over the Field and resulting in the Bentley East and Bentley South structures now being confirmed as part of the main Bentley field. These additional structures are now incorporated into an updated field development plan for the Field, with the associated recoverable volumes being re-assigned from Prospective Resources to reserves status.

In estimating reserves, only those volumes that are produced within the first 35 years of Field facilities service life are included.

Beyond the 35 years initial facilities service life, an additional 20 years of economic production has currently been classed as Contingent Resources. The nature of the contingency is the design life of the facilities but, it is recognised that with appropriate maintenance and replacement practices, the facilities, infrastructure and wells are capable of service in a North Sea environment beyond 35 years.

At this stage, no additional volumes have been estimated for potential enhanced oil recovery ("EOR") schemes. The Company is currently undertaking further studies and simulations to investigate the potential of EOR schemes based on polymer injection and, subject to the outcome of this work, Contingent Resources may be included in a future RAR, prior to a pilot scheme to operationally validate the studies.

Included in the evaluation are gas reserves derived from solution gas and gas pockets in Bentley East that are planned to be used as fuel for operations during development, as well as Contingent Resources beyond the 35 years initial facilities service life.

The Company has also delineated ten additional Dornoch and four Lower Palaeocene exploration prospects in its acreage surrounding the Field. The Probability of Success ("POS") was estimated for each prospect using an assessment of the reliability of the structure, the presence and effectiveness of seal and reservoir, and the chance that the prospect has been charged with hydrocarbon. These prospects are considered to have a high to moderate probability of success and, in the event of development, would be tied into the existing Bentley facilities.

Total Future Net Revenue - Undiscounted forecast prices and costs for reserves attributable to XER

Set out below are the total forecast, undiscounted net revenue and costs attributable to the Bentley reserves as included in the RAR and Form 51-101F1, which uses a 2% per annum escalation in revenue and costs commencing 1 January 2013. The RAR is based on pricing assumptions for crude oil taken from McDaniel & Associates' 1 October 2012 Brent oil forecast, less a 12% discount for Bentley crude (www.mcdan.com).

Based on the 250 MMstb 2P reserves, the RAR assumes:

·; revenue of approximately $28.2 billion for the life of field development, equating to a weighted average of $113 per barrel of Bentley oil. This weighted average revenue unescalated would be $83 per barrel.

·; operating costs of approximately $7.8 billion, equating to $31.0 per barrel. These operating costs unescalated would be $20.8 per barrel and are assumed to be funded out of oil revenue.

·; development costs of approximately $3.4 billion, equating to $13.7 per barrel. These development costs unescalated would be $12.5 per barrel and are discussed in more detail below.

·; abandonment and reclamation costs of approximately $810 million, equating to $3.2 per barrel. These abandonment and reclamation costs unescalated would be $1.5 per barrel.

·; undiscounted net revenue after income taxes (ie net cash flow generated) of approximately $6.9 billion, which equates to the NPV10 (after tax) value for 2P reserves of approximately $2.2 billion.

The RAR indicates that the P50 reserves production profile remains economic on an NPV10 basis above a Brent oil price of $46.1/bbl.

Future Development Costs Attributable to Reserves (Undiscounted)

Set out below are the future development costs attributable to the Field reserves from the RAR and Form 51-101F1, which uses a 2% per annum escalation in costs commencing 1 January 2013.

Note:

(1) The capital expenditure and construction schedule for the first phase development and the second phase development is assumed to be the same for the Proved (1P), Proved plus Probable (2P) and Proved plus Probable plus Possible (3P) outcomes. Hence the estimated future development costs are assumed to be the same for all three outcomes.

The Bentley Field continues to follow a phased development plan, comprising a first phase development ("FPD") and a second phase development ("SPD or Phase 2"). The plan no longer requires a third phase development platform.

The FPD is planned, subject to the Department of Energy & Climate Change ("DECC") approval, to comprise a permanent, manned production, utilities and quarters platform with approximately 20 well slots for production and water injection wells, together with facilities to de-gas the crude prior to pipeline transfer to a dedicated, in-field floating storage and offloading unit.

The existing 9/3b-7 and 7Z well, drilled in Phase 1A, will occupy one of the slots and will be re-completed once the platform is in place. Two subsea gas production wells and a subsea water injection well are planned as part of the FPD. Peripheral parts of the field to the far west and north will be added as subsea satellites approximately two years after first oil. The projected peak production rate at P50 is approximately 45,000 stb/d during the FPD.

After approximately five years of production from the FPD, the SPD is planned to commence, comprising a second production, utilities and quarters platform to be installed in the southern part of the field and tied back to the FPD platform. The projected combined peak production rate at P50 will increase to approximately 57,000 stb/d during the SPD.

Both of the FPD and SPD facilities will remain in place for the full life of the Field.

Assuming a two year lead time to first oil, the economic projections in the Form 51-101F1 assume that capital expenditure incurred in 2013 to 2015 to take the Field into production in late 2015 will amount to approximately $700 million, representing an economically efficient entry point to the development of the Field. Initial commitments have been made and funds have been expended on certain FPD equipment, comfortably within the existing funding resources available to the Company.

The economic projections in the Form 51-101F1 assume that capital expenditure in 2016 and beyond is funded from income from the sale of crude oil production at that time. This expenditure relates to the drilling of additional wells, followed by the Phase 2 infrastructure and production facilities.

In addition to the reserves already assigned to Bentley, the subject of the future development costs set out above, the Company plans to undertake EOR tests and, if successful, implement an EOR programme for the Field as soon as practicable during the FPD. It is anticipated that the EOR programme will incur additional expenditure, but will give rise to additional recoverable crude oil that, when sold, will generate revenue significantly in excess of the associated expenditure incurred.

As noted above, reserve estimates only include volumes that are currently planned to be produced within an initial facilities service life of 35 years. It is intended that the assigned Contingent Resources assumed to be produced in the 20 years after this period will be the subject of optimisation and either brought forward within the initial facilities service life, accelerated and captured by implementation of the EOR facilities, or produced through life extension methods employed during the later stages of Field life. Funding for such work programmes is assumed to be available from cash flow generated from previous production from the Field. It is expected that these work programmes, if successful, will give rise to additional reserves being assigned to Bentley.

Development of the Bentley Field

The updated development plan has resulted in a more balanced phasing of production volumes, with oil production from the FPD wells projected to be approximately half the reported 2P reserves, which is expected to deliver a significant increase in the borrowing capacity of the project. Having put in place a Reserves Based Lending ("RBL") facility in 2012, which is still regarded as an important component of the Company's future funding structure, the Company intends to hold discussions with a consortium of its existing and additional commercial lending banks to fully utilise this additional borrowing capacity.

With the updated reserves assessment completed, Xcite Energy intends to commence a farm-out process to evaluate suitable business partners for Bentley. The farm-out, together with the extended RBL facility, is intended to provide the funding required to commence the development of the Field.

An updated Field Development Plan will be submitted to the DECC in the coming months, which will reflect the results of the successful pre-production well test and the improvement in the balance between the two development phases.

In accordance with the AIM Rules, the information in this release has been reviewed and signed off by Tom Gunningham (C.Eng. MEI.), an associate at TRACS, who is a Chartered Petroleum Engineer, member of the Energy Institute and an Independent Qualified Reserves Auditor compliant with COGEH requirements.

Cautionary Language

Liberum Capital Limited, which is authorised and regulated in the United Kingdom by the Financial Services Authority, is acting exclusively for Xcite Energy and for no one else in connection with the subject matter of this announcement and will not be responsible to anyone other than Xcite Energy for providing the protections afforded to its clients or for providing advice in connection with the subject matter of this announcement.

Morgan Stanley, which is authorised and regulated in the United Kingdom by the Financial Services Authority, is acting exclusively for Xcite Energy and for no one else in connection with the subject matter of this announcement and will not be responsible to anyone other than Xcite Energy for providing the protections afforded to its clients or for providing advice in connection with the subject matter of this announcement.

The calculation of the NPV10 (after tax) for the Field disclosed above takes into account the following:  (a) UK Corporation Tax is charged at the rate of 30% on net taxable income; (b) UK Supplementary Charge ("SC") is charged at the rate of 32% on net taxable income; and (c) heavy oil allowances of up to £800 million have been applied to offset the SC to the extent possible.

Glossary

"1P" means proved reserves.

"2P" means proved plus probable reserves.

"3P" means proved plus probable plus possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves and there is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

"bcf" means billion cubic feet of gas.

"Contingent Resources" means those quantities of petroleum estimated, as of a given date, 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. There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources.

"DECC" means the UK Department of Energy and Climate Change.

"FPD" means First Phase Development of the Field.

"MMstb" means millions stock tank barrels.

"NPV10" means net present value in money of the day using a 10% forward discount rate, which values do not represent fair market value.

"PIIP" means petroleum initially in place.

"Prospective Resources" means those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. There is no certainty that any portion of the Prospective Resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the Prospective Resources.

"SPD" means Second Phase Development of the Field, or Phase 2.

"stb/d" means stock tank barrels per day.

"$" means United States dollars.

"$MM" means millions of United States dollars.

Forward-Looking Statements

Certain statements contained in this announcement constitute forward-looking information within the meaning of securities laws. Forward-looking information may relate to the Company's future outlook and anticipated events or results and, in some cases, can be identified by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "intend", "estimate", "predict", "target", "potential", "continue" or other similar expressions concerning matters that are not historical facts. These statements are based on certain factors and assumptions including expected growth, results of operations, performance and business prospects and opportunities. While the Company considers these assumptions to be reasonable based on information currently available to us, they may prove to be incorrect. Forward-looking information is also subject to certain factors, including risks and uncertainties that could cause actual results to differ materially from what is currently expected. These factors include risks associated with the oil and gas industry (including operational risks in exploration and development and uncertainties of estimates in oil and gas potential properties), the risk of commodity price and foreign exchange rate fluctuations and the ability of Xcite Energy to secure financing. Additional information identifying risks and uncertainties are contained in the Company's annual information form dated 26 October 2010 and in the annual Management's Discussion and Analysis for Xcite Energy dated 25 March 2013 filed with the Canadian securities regulatory authorities and available at www.sedar.com. 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 under applicable securities regulations.

Statements relating to "reserves" are deemed to be forward-looking statements or information, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitable in the future. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company. The reserve data included herein represents estimates only. In general, estimates of economically recoverable oil reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative and classifications of reserves are only attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil reserves attributable to any particular group of properties and classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. The actual production, revenues, taxes and development and operating expenditures of the Company with respect to these reserves will vary from such estimates, and such variances could be material.

Consistent with the securities disclosure legislation and policies of Canada, the Company has used forecast prices and costs in calculating reserve quantities included herein. Actual future net cash flows also will be affected by other factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. The estimated future net revenue set out herein does not necessarily represent the fair market value of the Company's reserves.

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.