Dundee Energy Limited Announces 2013 Financial Results

TORONTO, ONTARIO--(Marketwired - March 17, 2014) - 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 million.
  
• Cash and available credit under the Corporation's credit facilities totalled $3.9 million at December 31, 2013.
  

SOUTHERN ONTARIO ASSETS

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 reserves.

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 Gas			Oil and Liquids			Total			Natural Gas			Oil and 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	)
Production 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 Gas			Oil and Liquids			Total			Natural Gas			Oil and 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	)
Production 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.

CASTOR UNDERGROUND GAS STORAGE PROJECT

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.

INVESTMENT IN EUROGAS INTERNATIONAL INC.

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.

NON-IFRS MEASURES

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 flows.

• "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.

ABOUT THE CORPORATION

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".

FORWARD-LOOKING STATEMENTS

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.