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.

Bentley Field - PIIP Mean P90 P50 P10

First Phase Development Area MMstb 467.5 387.1 465.2 551.1

Total First and Second Phase Development Area 909.4 768.2 906.6 1052.3
MMstb

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

Bentley Field - Oil Reserves P90 (1P) P50 (2P) P10 (3P)

Reserves MMstb 198.2 250.2 312.1

NPV10 $MM 1,496.1 2,170.2 2,803.3

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.

Bentley Field - Contingent Resources Mean P90 P50 P10

MMstb 47.2 35.1 46.4 60.4

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.

Bentley Field - Gas Mean P90 P50 P10

Reserves bcf - 25.0 31.4 39.7

Contingent Resources bcf 4.7 3.5 4.6 6.0

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.

Prospect Block Mean P90 P50 P10 POS
MMstb MMstb MMstb MMstb

Bunsen 9/3c 4.6 3.1 4.6 6.3 0.73

Bunsen West 9/3c 2.5 1.6 2.5 3.5 0.22

Bunsen East 9/3c 0.6 0.3 0.6 0.9 0.24

Brindley 9/3d 3.6 1.1 2.8 7.0 0.25

Brunel 9/3b 6.0 3.2 5.5 9.5 0.17

Prospect A 9/3b 1.7 1.3 1.7 2.1 0.19

Prospect B 9/3b 2.3 1.9 2.3 2.8 0.17

Prospect C 9/3d 2.0 1.4 1.9 2.6 0.17

Prospect D 9/3c, 9/3d 1.4 1.0 1.4 1.9 0.17

Prospect E 9/3c 1.4 1.0 1.3 1.7 0.19

Clement 9/4a 4.7 0.9 3.1 10.2 0.21

Chadwick 9/4a 30.6 10.5 24.6 57.8 0.21

Cartwright 9/4a 19.3 8.6 16.9 33.2 0.16

Camm 9/8b, 9/9h 15.0 2.6 9.4 34.6 0.18

TOTAL 95.7

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).


Abandon- Future Future
ment Net Net
and Revenue Revenue
Develop- Reclama- before after
Operating ment tion Income Income Income
Reserves Revenue Costs Costs Costs Taxes Taxes Taxes
Category $m $m $m $m $m $m $m

TOTAL 22,300.2 7,644.9 3,416.9 810.4 10,428.0 5,685.1 4,743.0
PROVED
(1P)

TOTAL
PROVED
PLUS
PROBABLE
(2P) 28,228.0 7,760.0 3,416.9 810.4 16,240.6 9,292.0 6,948.7

TOTAL
PROVED
PLUS
PROBABLE
PLUS
POSSIBLE
(3P) 35,300.5 7,760.3 3,416.9 810.4 23,312.9 13,974.0 9,338.9

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 $13.7per
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.

Total Total Proved Total Proved Plus
Proved Plus Probable Probable Plus Possible
Estimated Estimated Estimated

Year ($m) ($m) ($m)

Bentley Field

2013 57.6 57.6 57.6

2014 342.7 342.7 342.7

2015 299.0 299.0 299.0

2016 303.8 303.8 303.8

2017 624.4 624.4 624.4

2018 444.7 444.7 444.7

2019 496.8 496.8 496.8

2020 385.7 385.7 385.7

2021 285.4 285.4 285.4

2022 176.8 176.8 176.8

Thereafter - - -

Total for all 3,416.9 3,416.9 3,416.9
years
undiscounted (1)

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 efficiententry
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 GBP800 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.