Dundee Energy Limited Announces 2013 Financial Results

Dundee Energy Limited Announces 2013 Financial Results 
TORONTO, ONTARIO -- (Marketwired) -- 03/17/14 --   Dundee Energy
Limited (TSX: DEN) ("Dundee Energy" or the "Corporation") today
announced its financial results for the year ended December 31, 2013.
The Corporation's annual audited consolidated financial statements,
along with management's discussion and analysis, have been filed on
the System for Electronic Document Analysis and Retrieval ("SEDAR")
and may be viewed under the Corporation's profile at www.sedar.com or
the Corporation's website at www.dundee-energy.com. 

--  Proved plus probable reserves increased to 19.4 MMboe at December 31,
    2013, an 18% increase from 16.4 MMboe at December 31, 2012.
--  Net loss attributable to owners of the parent for the year ended
    December 31, 2013 was $6.2 million, compared with $16.6 million incurred
    in the prior year. Current year losses include an impairment of $3.5
    million against an oil-based property, reflecting a decrease in
    estimated reserves. In the prior year, the Corporation recognized an
    impairment provision of $15.5 million against certain natural gas
    properties, consistent with substantial decreases in forecasted natural
    gas prices.
--  Production volumes during the year ended December 31, 2013 averaged
    10,196 Mcf/d (2012 - 10,081 Mcf/d) of natural gas and 634 bbls/d (2012 -
    748 bbls/d) of oil and liquids.
--  Revenues, before royalty interests, earned from oil and gas sales during
    the year ended December 31, 2013 were $39.2 million, compared with
    revenues of $35.9 million earned in 2012. The increase in revenues
    resulted primarily from improvements in commodity prices, partially
    offset by lower production volumes.
--  Field netbacks for the year ended December 31, 2013, before realized
    amounts related to risk management contracts, were $1.67/Mcf (2012 -
    $0.80/Mcf) from natural gas and $51.90/bbl (2012 - $51.30/bbl) from oil
    and liquids.
--  Capital expenditures during the year ended December 31, 2013 were $12.1
--  Cash and available credit under the Corporation's credit facilities
    totalled $3.9 million at December 31, 2013.

During 2013, production volumes were 2,333 boe/d, compared with an
average of 2,428 boe/d in 2012. The Corporation's acquisition of
additional working interests in natural gas properties completed in
July 2013 improved production volumes, however, this was offset by
the natural decline in the Corporation's oil and natural gas assets.
The Corporation's drilling program throughout 2013 did not adequately
replace the natural decline rate in the Corporation's oil

Average daily volume during the years ended December 31,       2013     2012
Natural gas (Mcf/d)                                          10,196   10,081
Oil (bbls/d)                                                    615      721
Liquids (bbls/d)                                                 19       27
Total (boe/d)                                                 2,333    2,428
Field Level Cash Flows and Field Netbacks                                   
(in thousands)                                                              
For the years ended                                                         
 December 31,                              2013                        2012 
                     Natural  Oil and            Natural  Oil and           
                         Gas  Liquids     Total      Gas  Liquids     Total 
Total sales          $16,711  $22,463  $ 39,174  $11,746  $24,128  $ 35,874 
Royalties             (2,508)  (3,458)   (5,966)  (1,741)  (3,650)   (5,391)
 expenditures         (8,007)  (6,983)  (14,990)  (7,041)  (6,442)  (13,483)
                       6,196   12,022    18,218    2,964   14,036    17,000 
Realized risk                                                               
 management (loss)                                                          
 gain                    (12)    (262)     (274)   2,963      965     3,928 
Field level cash                                                            
 flows               $ 6,184  $11,760  $ 17,944  $ 5,927  $15,001  $ 20,928 
For the years ended                                                         
December 31,                               2013                        2012 
                     Natural  Oil and            Natural  Oil and           
                         Gas  Liquids     Total      Gas  Liquids     Total 
                       $/Mcf    $/bbl     $/boe    $/Mcf    $/bbl     $/boe 
Total sales          $  4.49  $ 97.00  $  45.99  $  3.18  $ 88.19  $  40.37 
Royalties              (0.67)  (14.94)    (7.00)   (0.47)  (13.34)    (6.07)
 expenditures          (2.15)  (30.16)   (17.60)   (1.91)  (23.55)   (15.18)
                        1.67    51.90     21.39     0.80    51.30     19.12 
Realized risk                                                               
 management (loss)                                                          
 gain                      -    (1.13)    (0.32)    0.80     3.53      4.42 
Field netbacks       $  1.67  $ 50.77  $  21.07  $  1.60  $ 54.83  $  23.54 

Capital Expenditures 
During 2013, the Corporation expended $12.1 million on capital
expenditures, net of $1.4 million received on the disposition of
certain property, plant and equipment. This compares with capital
expenditures of $12.8 million incurred during 2012. 
Onshore, the Corporation incurred capital expenditures of $5.0
million, including $4.1 million incurred on drilling and completion
costs on four wells, which included a horizontal re-entry of a well
initially drilled in 2012. After acid stimulation, the well came on
production at 10 bbl/d in December 2013. The Corporation has
determined that the other three wells drilled were uneconomic. The
Corporation also expended $0.9 million in late 2013 to stimulate a
further six wells, increasing production by approximately 20 bbl/d. 
Exploration and evaluation expenditures were $7.4 million in 2013,
including $4.7 million incurred on the acquisition and processing of
2-D and 3-D seismic data, which will be used to identify future drill
locations. Another $2.7 million of costs were incurred on undeveloped
properties, including $1.6 million of costs incurred on a horizontal
natural gas well from a new geological formation. Further work on
this exploration well will be considered if gas production rates
remain economic. The remaining $0.9 million of exploration and
evaluation costs were incurred on maintenance costs associated with
undeveloped land, including leasing costs. 
In addition, as part of its offshore capital program, the Corporation
incurred costs of $1.0 million to complete an extensive pipeline
replacement and rerouting project. 
2014 Work Program 
The Corporation anticipates spending $7.3 million on its 2014 work
program of which $4.8 million will be directed towards development of
its oil fields in southern Ontario; a further $1.4 million will be
directed towards the Corporation's offshore natural gas assets; and,
approximately $1.1 million will be incurred to acquire or maintain
mineral rights for both producing and undeveloped properties. 
The 2014 onshore capital work program includes a three-well drilling
and completion program estimated to cost $2.5 million. In addition,
the Corporation intends to spend $1.5 million on three workovers and
it has budgeted approximately $0.8 million for the shooting and
processing of both 2-D and 3-D seismic, covering 50 to 60 kilometres. 
On July 26, 2013, Escal UGS S.L. ("Escal"), the owner of the Castor
Project, announced that it had arranged for the issuance of
euro-denominated senior secured bonds (the "Euro Bonds") totalling
EUR1.40 billion. The Euro Bonds are subject to an annual interest
rate of 5.756%, payable semi-annually, and are repayable in equal
semi-annual installments over a period of 21 and a half years, with
the last payment due in December 2034. The Euro Bonds are listed on
the Luxembourg stock exchange. 
Cushion Gas 
In early 2013, Escal reached an agreement with Enagas, S.A.
("Enagas") to provide the 600 million cubic metres of cushion gas
required for the Castor Project. Enagas subsequently completed the
acquisition of approximately 125 million cubic metres, and injection
of the cushion gas into the reservoir began in June 2013.
Approximately 85% of the acquired cushion gas was injected by
September 16, 2013. 
In mid September, seismic activity was detected in the area
surrounding the Castor Project. While the seismic activity did not
affect the integrity of the facility and the underground reservoir,
nor cause any damage, the Spanish authorities have implemented a
suspension to the injection of further volumes of cushion gas until
an independent assessment of the source of seismic activity is
completed. Independent assessments were subsequently undertaken and
are currently under review and consideration by the Spanish
authorities. The assessments put forward that the seismicity observed
appears to be related to a secondary fault present in the area.
Importantly, gas to liquid levels in the reservoir remained stable
throughout, significantly reducing concerns over the leakage of
cushion gas. 
The technical and economic audits that are required for inclusion of
the Castor Project to the Spanish gas system commenced in July 2013,
were completed in late December 2013 and were delivered to the
Spanish authorities in January 2014. On a preliminary basis, these
audits have concluded that the Castor Project is technically fit to
store and deliver gas; it has an appropriate process design and
configuration and it has sufficient safety engineering for operation.
The audits have also concluded that the capital cost employed for the
construction of the Castor Project are reasonable. These findings are
now subject to the review and concurrence by the Spanish authorities. 
At December 31, 2013, the Corporation held 32.2 million Series A
Preference Shares of Eurogas International Inc. ("Eurogas
International"). Eurogas International held a 45% working interest,
and is the non-operating partner in the Sfax Permit, encompassing
approximately 800,000 acres located within a prolific hydrocarbon
fairway extending from offshore Libya, through the Gulf of Gabes, to
onshore Tunisia, southeast of the city of Sfax. 
In June 2013, Eurogas International, along with its partner (the
"Original Contractors") entered into negotiations to complete a
farmout agreement with a third party with respect to the Sfax Permit
and the associated Ras El Besh development concession. The agreement
provides that the third party will acquire an 87.5% working interest
in the Sfax Permit in exchange for a US$6 million cash payment to the
Original Contractors, and the carrying of 100% of all future costs
associated with the Sfax Permit, including the Original Contractors'
drilling commitments pursuant to the Sfax Permit. The agreement was
completed in January 2014. 
The Corporation believes that important measures of its operating
performance include certain measures that are not defined under
International Financial Reporting Standards ("IFRS") and as such, may
not be comparable to similar measures used by other companies. While
these measures are non-IFRS, they are common benchmarks in the oil
and natural gas industry, and are used by the Corporation in
assessing its operating results, including net earnings and cash

--  "Field Level Cash Flows" are calculated as revenues from oil and gas
    sales, less royalties and production expenditures, adjusted for realized
    gains or losses on risk management contracts. 
--  "Field Netbacks" refer to field level cash flows expressed on a
    measurement unit or barrel of oil equivalent basis. 

Dundee Energy Limited is a Canadian-based oil and natural gas company
with a mandate to create long-term value for its shareholders through
the exploration, development, production and marketing of oil and
natural gas, and through other high impact energy projects. Dundee
Energy holds interests, both directly and indirectly, in the largest
accumulation of producing oil and gas assets in Ontario, in the
development of an offshore underground natural gas storage facility
in Spain and, through a preferred share investment, in certain
exploration and evaluation programs for oil and natural gas offshore
Tunisia. The 
Corporation's common shares trade on the Toronto Stock Exchange under
the symbol "DEN". 
Certain information set forth in these documents, including
management's assessment of each of the Corporation's future plans and
operations, contains forward-looking statements. Forward-looking
statements are statements that are predictive in nature, depend upon
or refer to future events or conditions or include words such as
"expects", "anticipates", "intends", "plans", "believes", "estimates"
or similar expressions. By their nature, forward-looking statements
are subject to numerous risks and uncertainties, some of which are
beyond the Corporation's control, including: exploration, development
and production risks; uncertainty of reserve estimates; reliance on
operators, management and key personnel; cyclical nature of the
business; economic dependence on a small number of customers;
additional funding that may be required to execute on exploration and
development work; the ability to obtain, sustain or renew licenses
and permits; risks inherent to operating and investing in foreign
countries; availability of drilling equipment and access; industry
competition; environmental concerns; climate change regulations;
volatility of commodity prices; hedging activities; potential defects
in title to properties; potential conflicts of interest; changes in
taxation legislation; insurance, health, safety and litigation risk;
labour costs and labour relations; geo-political risks; risks
relating to management of growth; aboriginal claims; volatility of
the Corporation's share price; royalty rates and incentives;
regulatory risks relating to oil and natural gas exploration;
marketability and price of oil and natural gas; failure to realize
anticipated benefits of acquisitions and dispositions; information
system risk; and other risk factors discussed or referred to in the
section entitled "Risk Factors" in the Corporation's Annual
Information Form for the year ended December 31, 2013. 
Readers are cautioned that the assumptions used in the preparation of
such information, although considered reasonable at the time of
preparation, may prove to be imprecise and, as such, undue reliance
should not be placed on forward-looking statements. 
The Corporation's actual results, performance or achievement could
differ materially from those expressed in, or implied by, these
forward-looking statements and, accordingly, no assurance can be
given that any of the events anticipated by the forward- looking
statements will transpire or occur, or if any of them do so, what
benefits the Corporation will derive from them. The Corporation
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 law. 
Dundee Energy Limited
c/o Dundee Corporation
1 Adelaide Street East, 21st Floor
Toronto, ON M5C 2V9 
Dundee Energy Limited
Jaffar Khan
President & CEO
(403) 264-4985
(403) 262-8299 (FAX)
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