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Dundee Energy Limited Announces Financial Results for the Three Months Ended March 31, 2012

April 30, 2012

TORONTO, ONTARIO--(Marketwire - April 30, 2012) - Dundee Energy Limited ("Dundee Energy" or the "Corporation") (TSX:DEN) today announced its financial results for the three months ended March 31, 2012. The Corporation's unaudited condensed interim 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 or the Corporation's website at

  • Cash flow from operating activities, before changes in non-cash working capital items, increased to $3.2 million in the first quarter of 2012 compared with $2.5 million in the first quarter of the prior year.

  • Production volumes for the first quarter of 2012 averaged 10,123 Mcf/d of natural gas and 763 bbls/d of oil and liquids.

  • Revenues, before royalty interests earned from oil and natural gas sales during the first quarter of 2012 were $9.4 million, representing an average price of $3.12/Mcf on sales of natural gas and an average price of $95.89/bbl on sales of crude oil.

  • Field netbacks were $2.14/Mcf from sales of natural gas and $56.07/bbl from sales of oil and liquids.

  • Capital expenditures during the first quarter of 2012 were $1.4 million.

  • Cash and available credit under the Corporation's credit facilities totalled $17.9 million at March 31, 2012.

  • Net loss attributable to owners of the parent for the quarter ended March 31, 2012 was $0.4 million compared with a net loss attributable to owners of the parent of $2.0 million incurred in the first quarter of 2011. Current quarter results include a mark-to-market gain of $1.3 million in respect of the Corporation's risk management strategies, while results in the first quarter of the prior year included a loss of $1.4 million as a result of these strategies.


Production Volumes
Average daily volume during the three months ended March 31, 2012 2011
Natural gas (Mcf/d) 10,123 10,164
Oil (bbls/d) 733 635
Liquids (bbls/d) 30 16
Total (boe/d) 2,450 2,345

Natural gas sales currently represent 69% (three months ended March 31, 2011 - 72%) of the Corporation's overall production volume on a boe basis, with oil production representing the remaining 31% (three months ended March 31, 2011 - 28%).

Average daily production volumes for natural gas in the first quarter of 2012 were consistent with average daily natural gas production volumes in the same period of the previous year. The natural decline in gas reserves of 5% to 8% annually was partially offset by the drilling of two offshore wells in the fourth quarter of 2011 that, on a combined basis, contributed production volumes of approximately 450 Mcf/d. The acquisition of Torque Energy Inc. in the third quarter of 2011 added another 300 Mcf/d to gas production.

The historical decline rate of 15% in the Corporation's oil reserves was offset by drilling and workover programs undertaken in the third and fourth quarters of 2011, including a new oil well drilled in December 2011 that came on production at 40 bbls/d. The acquisition of Torque further benefitted oil production, adding volumes of approximately 85 bbls/d.

Revenue from Oil and Gas Sales

For the three months ended March 31,
2012 2011
Sales Realized
($ / unit)
Sales Realized
($ / unit)
Natural gas $ 2,875 3.12 $ 4,290 4.69
Oil 6,398 95.89 5,211 91.18
Liquids 173 63.37 68 47.22
9,446 9,569
Less: Royalties at 15% (2011 - 16%) (1,372 ) (1,497 )
Net sales $ 8,074 $ 8,072

During the three months ended March 31, 2012, the Corporation realized an average price of $3.12/Mcf on sales of natural gas before royalty interests, a decrease of over 33% from the average price of $4.69/Mcf realized in the same period of the prior year. In March 2012, natural gas prices in Canada fell below US$2.00/Mcf, as relatively warmer winter weather diminished demand, at the same time as new discoveries and technological changes resulted in a surplus of supply. However, due to the proximity of the Corporation's operations to the Dawn Hub, a leading provider of natural gas supply to the greater Toronto market area, the Corporation's realized price from sales of natural gas continues to include a positive basis differential from the average industry benchmarks.

Global economic uncertainties continue to cause substantial volatility in the price of oil. Concerns that a recession is possible in the European Union and expectations for slower economic growth in emerging countries, contrast with concerns over possible supply disruptions from certain areas of the Middle East. These concerns are reflected in the substantial volatility of the West Texas Intermediate ("WTI") Crude Oil Price, which reached a high of US$109.39/bbl and a low of US$96.36/bbl in the first quarter of 2012, closing at US$103.03/bbl on March 31, 2012.

While international benchmarks for oil continued to climb in the first quarter of 2012, oil prices fell in western Canada. Given quality differentials, the Edmonton Par Oil Price ("Edmonton Par") normally trades at a price discount to the WTI oil price. However, the magnitude of the discount was unusually wide in the latter part of the first quarter. With the advent of improved technology, compounded by the growth of oil shale plays, production of oil in western Canada has now exceeded its export pipeline capacity, exerting downward pressure on the Edmonton Par.

During the first quarter of 2012, the Corporation realized an average price of $95.89/bbl of oil, a 5% increase over the $91.18/bbl realized in the same period of the prior year.

Price Risk Management

The Corporation has entered into fixed price derivative contracts for the purpose of protecting its oil and natural gas revenue from the volatility of oil and natural gas prices and the volatility in Canadian to US foreign exchange rates. During the first quarter of 2012, the Corporation realized a gain of $1.3 million (three months ended March 31, 2011 - loss of $1.4 million) from these arrangements.

At March 31, 2012, the Corporation had locked in pricing for 500 bbls/d of oil production through to December 31, 2012 at a weighted average rate of Cdn$101.20/bbl. It had also locked in pricing on 7.0 million btu/day of natural gas from March 1, 2012 to December 31, 2012 at Cdn$3.84/MMbtu. These risk management contracts protect pricing on approximately 68% of the Corporation's oil and natural gas production.

Field Level Cash Flows

For the three months ended March 31,
2012 2011
Oil and
Total Natural
Oil and
Total sales $ 2,875 $ 6,571 $ 9,446 $ 4,290 $ 5,279 $ 9,569
Realized risk management gain (loss) 979 (137 ) 842 - (93 ) (93 )
Royalties (433 ) (939 ) (1,372 ) (634 ) (863 ) (1,497 )
Production expenditures (1,444 ) (1,601 ) (3,045 ) (1,770 ) (1,128 ) (2,898 )
Field level cash flows $ 1,977 $ 3,894 $ 5,871 $ 1,886 $ 3,195 $ 5,081

Field Netbacks

For the three months ended March 31,
2012 2011
Oil and
Total Natural
Oil and
$/Mcf $/bbl $/boe $/Mcf $/bbl $/boe
Total sales $ 3.12 $ 94.61 $ 42.36 $ 4.69 $ 90.10 $ 45.34
Realized risk management gain (loss) 1.06 (1.97 ) 3.78 - (1.59 ) (0.44 )
Royalties (0.47 ) (13.52 ) (6.15 ) (0.69 ) (14.74 ) (7.09 )
Production expenditures (1.57 ) (23.05 ) (13.65 ) (1.94 ) (19.26 ) (13.73 )
Field netbacks $ 2.14 $ 56.07 $ 26.34 $ 2.06 $ 54.51 $ 24.08

Capital Expenditures

During the three months ended March 31, 2012, the Corporation incurred capital expenditures of $1.4 million on oil and gas properties in southern Ontario. Planned capital expenditures for the remainder of 2012 are estimated at $10.6 million on a net basis, including approximately $8.6 million for onshore projects and $2.0 million for offshore projects. These capital initiatives are aimed at upgrading and improving productivity.

In addition to its planned capital work program, the Corporation has purchased an onshore drilling rig at a cost of approximately $3.1 million. The rig will augment the offshore drilling and completion barge operation in Lake Erie as the equipment and personnel will be interchangeable. The acquisition will enhance drilling efficiencies significantly, and will provide the Corporation with better control over the timing and safety aspects of its operations. The acquisition will also provide the Corporation with a monetization opportunity as the rig may be leased to third parties.


The Castor Project continues to progress on schedule and substantially within the approved engineering, procurement and construction budget. The construction of the Castor Project is substantially complete, and is now subject to testing and subsequent commissioning into the Spanish gas system. The 13-well drilling program was completed and all 14 wells have been tied in to the wellhead platform. The offshore processing platform, which was manufactured in the United States and then shipped and received at the project site in November 2011, was installed and connected to the offshore wellhead platform by way of an interconnecting bridge. The subsea pipeline, which connects the processing platform to the onshore pipeline, has been laid on the ocean floor and subsequently tested.

Construction of the onshore gas treatment plant is also substantially complete, with many of the operating systems already transferred to the operations and maintenance contractors. The pipeline connecting the Castor Project to the Spanish national high-pressure grid was completed, as was the associated metering system.

In early April 2012, gas was introduced into the onshore system as the first stage in the commissioning of the Castor Project, a process that will be carried out systematically in order to satisfy the integrity and functionality of each onshore and offshore system.

The first phase of the commissioning process will be completed with the granting of a provisional start-up certificate, which will allow Escal to commence the injection of cushion gas. Total gas to be injected for this purpose is approximately one million cubic meters. Escal has targeted the initiation of the injection of cushion gas for mid-June 2012, with completion expected in September. At that time, Escal will apply for a definitive start-up certificate. Once granted, the definitive start-up certificate will allow Escal to apply for inclusion of the Castor Project into the Spanish gas system. Actual inclusion of the Castor Project into the Spanish gas system is subject to an independent technical review and an audit of the total investment in the project, which will provide the definitive basis for remuneration.

On March 30, 2012, the Spanish government issued a royal decree, changing the terms of provisional remuneration available prior to final commissioning certification for initiatives similar to the Castor Project. The royal decree also imposed additional commissioning requirements that need to be met prior to acceptance of an underground gas storage project into the Spanish gas system. In addition, on April 27, 2012, a Spanish ministerial order was issued, increasing the term of the remuneration period for invested cost related to underground gas storage from 10 years to 20 years. The fees payable for gas storage investment remain unchanged. This modification may have an effect on Escal's current project financing arrangements. The Corporation is actively working with Escal, and with the majority shareholder of Escal, to obtain further clarification of the potential impact of these changes to the Castor Project.


The Corporation believes that important measures of operating performance include certain measures that are not defined under 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 price management contracts.

  • "Field Netbacks" refers to field level cash flows expressed on a measurement unit or barrel of oil equivalent basis.


Dundee Energy Limited (formerly "Eurogas Corporation") 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, 2011.

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.

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