Synenco Energy Initiates Review of Options to Maximize Shareholder Value

    Capital Cost Estimate Released for Northern Lights Downstream

    Conference call for the investment community (media in listen-only mode)
    at 6:30 a.m. Mountain/8:30 a.m. Eastern

    Conference call for media at 9:00 a.m. Mountain/11:00 a.m. Eastern
    (see details at end of release)

    CALGARY, May 1 /CNW/ - The Board of Directors of Synenco Energy Inc.
(TSX: SYN) today announced a plan to assess options for a strategic
repositioning of the company. The plan has a range of possible outcomes
including: restructuring the Northern Lights Partnership's downstream business
to capture economies of scale by including other partners, alternative
downstream commercial ventures, and other corporate-level options that enhance
shareholder value.
    Synenco Energy today also released an updated capital cost estimate of
$6.3 billion for the downstream (upgrader) portion of the Northern Lights oil
sands project planned for Sturgeon County, Alberta.
    The upgrader capital cost estimate is based on a thorough examination by
the company of a wide range of design and technology options, including coker
and hydro-processing technologies. The upgrader estimates range from
$4.4 billion to $6.3 billion, while the real internal rates of return range
from 8.5 percent to 9.5 percent (based on a long-term oil price assumption of
US$55 per barrel). The option with the highest capital cost, which includes
gasification, produces the greatest real rate of return. However, Synenco's
management and Board of Directors have determined that the expected rates of
return for any of the examined upgrader options are incompatible with
Synenco's weighted average cost of capital, which is higher.
    "We have world-class assets in our Northern Lights resource and, as
operator, our outstanding and experienced workforce," said Synenco Chairman
and Chief Executive Officer, Mike Supple. "We remain very optimistic about the
long-term potential of these assets and are committed to maximizing the
shareholder value inherent in them. At the same time, however, we recognize
that our current path needs to be adjusted to achieve this goal."
    "The fundamentals of a capital-intensive business are straightforward,"
said President and Chief Operating Officer Todd Newton. "Every company has a
cost of capital, and value is created when the company invests its capital in
assets that provide a return that exceeds this cost of capital. Synenco
Energy's cost of capital is greater than that of more established companies,
which are producing operating cash flow, and our investment criteria will
naturally be higher as well. We will review all options including those that
reduce our cost of capital or increase project returns."
    In conjunction with the announced options review and downstream capital
cost guidance, Synenco Energy is also updating other previously disclosed
guidance pending the outcome of the options review.
    - The development schedule for Northern Lights, announced in
      December 2006, and which anticipated first oil by mid-2011, is
    - The company's 2007 cash expenditure level is estimated to be
      approximately $100 million after re-prioritization of Northern Lights
      and corporate activities. The previously announced 2007 cash
      expenditure budget was $235 million.

    "The combination of our strong cash position of more than $300 million,
oil sands lease expiration dates that are more than a decade away, and our low
level of contractual commitments support the timing of today's decision to
formally seek and assess all available alternatives," said Newton.
    Design and engineering activities in support of the Northern Lights
Upgrader will be put on hold during the assessment period and Synenco will
meet with Alberta regulators to discuss how best to implement a time-out in
their regulatory reviews for the upgrader application while strategic options
for the company are being assessed.
    Work in support of Northern Lights Upstream development will be
re-prioritized to initiatives that reduce execution and operational risk.
These initiatives include progressing the Northern Lights Mining and
Extraction Application, which is now well into the regulatory review process;
mine planning; and the pilot testing of extraction technology. The company
also will continue to develop its overseas modularized construction strategy
for Upstream.
    TD Securities Inc. and Merrill Lynch Canada Inc. have been retained as
financial advisors to Synenco as the company conducts its options review.
There can be no assurances that any transaction will occur or, if one is
undertaken, its terms or timing. Synenco Energy does not expect to update its
progress or disclose developments with respect to the exploration of options
until the Board of Directors authorizes any transaction or when required by

    About Synenco Energy and Northern Lights
    Synenco Energy is a Calgary-based oil sands company which, with a
60-percent interest, is the managing partner of the Northern Lights
Partnership and operator of the Northern Lights oil sands project. Synenco
Energy also holds a 100-percent interest in the McClelland oil sands lease
adjacent to Northern Lights project lands.
    The Northern Lights project consists of an oil sands mining and bitumen
extraction project to be established about 100 kilometres northeast of Fort
McMurray, Alberta, and a heavy oil upgrader proposed for Sturgeon County near
Edmonton. Separate regulatory applications for each segment of the project
were filed with the Alberta Energy and Utilities Board and Alberta Environment
during 2006. The independent best estimate of Northern Lights bitumen, based
on all drilling up to and including the 2005/2006 program, is 1.67 billion
barrels of Discovered Resources.
    SinoCanada Petroleum Corporation, an indirect wholly-owned subsidiary of
China-based Sinopec, owns the remaining 40 percent of the Northern Lights
Partnership and project.
    See attached backgrounders for more details.

    Conference call for the investment community (media in listen-only mode)

      Date:            May 1, 2007
      Time:            6:30 a.m. Mountain (8:30 a.m. Eastern)

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    Conference call for media

      Date:            May 1, 2007
      Time:            9:00 a.m. Mountain (11:00 a.m. Eastern)

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call to one of the following:

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    Cautionary note regarding forward-looking statements:
    This news release contains "forward-looking statements" relating to
Synenco Energy and NLP which are expressly qualified by this cautionary note.
Estimates of NLP's in-place bitumen "Discovered Resources" are made as of
December 2006 and are forward-looking statements. (The term "Discovered
Resources" is defined in the COGE Handbook and in CSA Staff Notice 51-321.)
Further classification into contingent resources or reserves is not expected
to be possible until a feasibility study has been completed. Resource
estimates are inherently uncertain and are generally considered more uncertain
than estimates of reserves. Future estimates of recoverable resources and
actual recoverable resources will differ and may differ materially from the
estimate of NLP's in-place bitumen Discovered Resources. Statements with
respect to the project's estimated capital costs, operating costs, netbacks,
yields and cash flow, Synenco's estimated rates of return, oil price
assumptions, natural gas and power requirements, costs of capital of Synenco
or other entities, the project's proposed development schedule, and the
anticipated cash expenditures and commitments of Synenco and NLP are all
forward-looking statements. All other statements suggesting future plans and
outcomes, including without limitation statements regarding possible
transactions are forward-looking statements. Readers are strongly cautioned
that forward-looking statements are inherently uncertain and based on a number
of estimates and assumptions and subject to known and unknown risks and
uncertainties. Undue reliance must not be placed on them. Actual results will
differ and may differ materially. Factors which could cause actual results to
differ materially from those expressed or implied include but are not limited
to: availability and fluctuating price of oil and energy commodities;
heavy/light crude oil differentials; operating conditions and costs; interest
rate fluctuations; costs of construction materials, labour and transportation;
the level of engineering data available for estimations; changes or
refinements in project design and engineering; ability to finalize a binding
agreement with Agrium or others for the sale of by-products from the upgrader;
changes in law or government policy such as changes in the oil sands royalty
regime and/or tax regime, the regulatory environment and federal and
provincial environmental legislation; public opinion with respect to water
usage, environmental issues and socio-economic impacts of oil sands and energy
projects; the ability to obtain regulatory and governmental approvals and
licenses on a timely basis or at all; the ability to identify and successfully
negotiate a commercially advantageous transaction; and the availability and
the cost of debt and equity financing. Refer also to the risk factors in
Synenco's annual information form dated March 9, 2007. Forward-looking
statements are made as at the date of this news release and are not guarantees
of future performance. Synenco expressly disclaims any obligation to update
publicly or revise any of the forward-looking statements except as required by


    The company performed detailed evaluations on three cases for a nominal
100,000 barrels per calendar day upgrader to be located in Sturgeon County,
near Edmonton:

    -  "Base" Case (as described in the Northern Lights regulatory
       application filed September 2006) - which includes fixed-bed
       hydro-processing combined with asphaltene gasification to produce a
       45-degree to 49-degree API synthetic crude oil (SCO) product. The
       Base Case is supported by design basis engineering studies and capital
       costs. Capital costs are in late 2006 dollars, and management
       estimates the costs to have a precision of +/- 25 percent.

    -  "Coker" Case - which uses coking technologies most often applied by
       existing SCO producers to increase the value of bitumen. The Coker
       Case does not include asphaltene gasification and therefore sources
       hydrogen from natural gas through steam methane reforming. The Coker
       Case costs have been capacity-factored from the Base Case studies and
       other industry and published data. Accordingly, the estimates carry
       less precision than the Base Case.

    -  "LCF" Case - which uses an ebullated bed hydro-processing technology
       also in current operation by SCO producers, combined with
       fit-for-purpose asphaltene gasification units. The LCF Case costs have
       been capacity-factored from the Base Case studies and other industry
       and published data. Accordingly, the estimates carry less precision
       than the Base Case.

    Economics include recently announced taxation changes in Canada with
regards to the accelerated capital cost allowance, but do not reflect recent
federal greenhouse gas emission announcements or possible changes to the
current provincial oil sands royalty regime.
    Economics are based on a US$55/bbl price for West Texas Intermediate
(WTI) and all other commodity price and exchange rate assumptions are
correlated thereto.
    All barrels are expressed as barrels per calendar day unless otherwise
noted. All dollars are Canadian unless otherwise noted.

    Downstream - 100% Project

                                     "Base" Case  "Coker" Case    "LCF" Case
    Bitumen feedstock                    113,400       113,400       113,400
    SCO production                       103,300       100,500       107,100
    SCO equivalent production(1)         113,600       100,500       109,300
    Yield as a percentage of
     bitumen feed                           100%           89%           96%
    Quality of SCO (based on gravity) 45 degrees  34.6 degrees  38.8 degrees
    WTI pricing differential
     per barrel                         US $0.32     US ($2.11)    US ($1.47)
    Non-energy operating cost per
     SCO equivalent bbl                    $4.71         $4.07         $5.05
    Natural gas requirements (mmcf/d)         14            58            18
    Power requirements (MW)                  235            33           185
    Total operating cost per SCO
     equivalent barrel                     $9.81         $9.55         $9.76
    Netback per SCO equivalent barrel     $20.90        $14.86        $18.24
    Capital cost (in billions)              $6.3          $4.4          $5.5
    Capital cost per daily equivalent
     SCO barrel                          $55,458       $43,781       $50,320
    Internal Rate of Return (IRR)
     after tax                              9.6%          8.9%          9.3%

    (1) After converting other saleable products as determined under the
        current MOU between Northern Lights and Agrium into SCO equivalents,
        based on revenue contribution.

    Integrated - 100% Project, based on Base Case for Downstream

    Costs Per Barrel
                                                    Downstream    Integrated
                                                      (per SCO      (per SCO
                                        Upstream    equivalent    equivalent
                                (per Bitumen bbl)          bbl)          bbl)
    Operating Cost - non-energy           $12.92         $4.71        $17.60
    Bitumen feedstock                          -        $32.42             -
    Total transportation                   $1.14             -         $1.35
    Natural Gas                            $3.58         $1.03         $4.61
    Power                                      -         $4.07         $4.07
    Total Operating Costs                 $17.65        $42.23      $27.63(2)
    (2) Summing results for Upstream and Downstream will not equal the
    Integrated results as Upstream is calculated on bitumen barrels while
    Downstream is calculated on SCO equivalent barrels.

    Net Cash Flow Per Barrel
                                                    Downstream    Integrated
                                                      (per SCO      (per SCO
                                        Upstream    equivalent    equivalent
                                (per Bitumen bbl)          bbl)          bbl)
    Revenue                               $30.77        $63.13        $61.64
    Operating Costs                      -$17.65       -$42.23       -$27.63
    Pre-tax cash flow                     $13.12        $20.90        $34.01
    Taxes                                 -$1.96        -$3.28        -$5.22
    After tax cash flow                   $11.16        $17.62      $28.79(2)
    (2) Summing results for Upstream and Downstream will not equal the
    Integrated results as Upstream is calculated on bitumen barrels while
    Downstream is calculated on SCO equivalent barrels.

    Capital Costs Per Barrel and Rate of Return
                                        Upstream    Downstream    Integrated
    Capital Cost (in billions)            $4.4(3)         $6.3         $10.7
    Capital Cost per daily barrel                    $/bbl SCO     $/bbl SCO
                                   $/bbl bitumen    equivalent    equivalent
                                         $38,800       $55,458       $94,190
    Internal Rate of Return (IRR)
     after tax                              8.8%          9.6%          9.3%
    (3) As per Capital Markets Day, December 6, 2006

    For all tables: All per barrel costs and revenues are calculated over the
    full life of the project (present value).

                          SYNENCO ENERGY MILESTONES

    Synenco Energy Inc. was incorporated in 1999 to acquire and develop oil
sands resources in the Athabasca Oil Sands region northeast of Fort McMurray,
Alberta. By 2004, delineation of the company's resources showed them to be of
sufficient size with physical attributes to support a major oil sands
development effort.
    Today, Synenco Energy is in the midst of project design and development
for the Northern Lights Project. The project includes an upstream mining and
extraction facility on the three Northern Lights leases northeast of Fort
McMurray, and a downstream upgrading component planned to be located in
Sturgeon County, Alberta. Synenco Energy has filed separate regulatory
applications for both components of the project. These have each been declared
administratively complete by regulatory authorities, with the review and
approval processes for each application now well underway. In addition to
bitumen resources, the Northern Lights assets also include extensive coal
leases, which currently are being evaluated to determine the magnitude of the
coal resource and commercial opportunities.
    In addition to its 60-percent interest in the Northern Lights Project,
Synenco Energy has 100 percent ownership of an oil sands lease (the McClelland
lease), which has undergone an initial two-year exploration program. Results
of this exploration should be ready in the Fall.

    Past Milestones

    May 2005: Synenco Energy and China-based Sinopec, the world's seventh
largest integrated oil and gas company, form the Northern Lights Partnership
to further develop the Northern Lights Project (SinoCanada, a Sinopec
subsidiary, owns 40 percent of the partnership and project).

    September 2005: Synenco Energy acquires the McClelland lease.

    November 2005: Synenco Energy conducts an Initial Public Offering and
lists on the Toronto Stock Exchange (symbol: SYN), issuing 15,750,000 common
shares at $17.50 per share.

    December 2005: The company announces it plans to build the Northern
Lights upgrader in Sturgeon County outside of Edmonton, Alberta rather than at
the Northern Lights mine site northeast of Fort McMurray, Alberta.

    June 2006: The Northern Lights Partnership announces Citibank as the
Northern Lights Partnership's debt capitalization advisor to explore global
sources of Project financing, evaluate various structures, and plan for debt
capitalization that would leverage both partners' equity.

    June 2006: The first portion of the sequenced Upstream (mining and
bitumen extraction) regulatory application for Northern Lights is filed.

    June, July and November 2006: Synenco Energy signs technology licensing
agreements related to the Northern Lights upgrader, including with GE Energy
to use GE's gasification technology; with UOP Management Services Inc. to use
its Unicracking(TM) and RCD Unionfining(TM) hydro-treating technologies; with
Kellogg Brown & Root International to use its ROSE(TM) solvent de-asphalting
technology; and with UOP Management Services, a Honeywell company, to use its
Selexol(TM) solvent process for acid gas recovery.

    July 2006: Synenco Energy signs a Memorandum of Understanding with Agrium
for the supply of hydrogen, nitrogen, sulphur and carbon dioxide from the
Northern Lights upgrader to Agrium's neighbouring Redwater nitrogen fertilizer

    August 2006: The Northern Lights Partnership's northern permit is
converted to a primary oil sands lease with a 15-year term.

    September 2006: The Northern Lights Downstream (upgrader and related
facilities) application is filed.

    October 2006: The independent resource estimates for the Northern Lights
oil sands leases reflected a 12-percent increase in the Best Estimate of
Discovered Resources to 1.67 billion barrels (Synenco Energy's share: 1.00
billion barrels) after analysis of the 2006 winter drilling program.

    November 2006: Remaining portions of the sequenced Upstream regulatory
application for Northern Lights are filed.

    December 2006: Synenco Energy updates its capital cost estimate and
construction strategy for the Northern Lights Upstream facilities. The capital
cost is estimated in 2006 dollars at $4.4 billion (Synenco Energy share:
$2.6 billion, +30%/-10%) in relation to 114,500 barrels per calendar day of
bitumen production. This includes anticipated savings ($1.2 billion for
Northern Lights or $0.7 billion for Synenco Energy) from the announced
construction strategy, which will see modules of up to 2,000 tonnes built
overseas and shipped to site via a 'Northern Route'.

For further information:

For further information: Media: Scott Ranson, General Manager, Public
Affairs, Telephone: (403) 451-5212,; Kelli Stevens,
Public Affairs Coordinator, Telephone: (403) 451-5240,; Investment community: Idar Eikrem, Executive Vice
President and Chief Financial Officer, Telephone: (403) 451-4612,

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