TORONTO, ONTARIO--(Marketwire - Feb 15, 2013) - Dundee Energy Limited ("Dundee Energy" or the "Corporation") (DEN.TO) today announced its financial results for the year ended December 31, 2012. 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 16.4 MMboe at December 31, 2012, a 2% increase from 16.1 MMboe at December 31, 2011.
- Impairment Provision - Despite an increase in net reserves, and as required pursuant to current international financial reporting standards ("IFRS"), the Corporation completed an impairment analysis based on a reserves report issued by a qualified reserve evaluator at December 31, 2012. Based on this report, and as a result of decreases in the forecasted natural gas prices as provided for in the reserves report, the Corporation has determined that the carrying value of certain of its natural gas assets exceeded their net recoverable amount by $15.5 million. The recoverable amount was determined using cash flow models, discounted at a rate of eight percent. Accordingly, during the year ended December 31, 2012, the Corporation recognized an impairment loss of $15.5 million in respect of these natural gas assets. In accordance with IFRS, the impairment loss may be reversed in subsequent periods if there is a positive change in the forecast of future gas prices.
- Net loss attributable to owners of the parent for the year ended December 31, 2012 was $16.6 million compared with a net loss attributable to owners of the parent of $1.2 million incurred in 2011. The net loss in 2012 included the $15.5 million impairment on natural gas assets.
- Cash flow from operating activities, before changes in non-cash working capital items, decreased to $9.6 million in 2012 compared with $12.0 million in the prior year, reflecting lower realized prices on sales of oil and natural gas.
- Production volumes for the year ended December 31, 2012 averaged 10,081 Mcf/d of natural gas and 748 bbls/d of oil and liquids.
- Revenues, before royalty interests earned from oil and natural gas sales during the year ended December 31, 2012 were $35.9 million, representing an average price of $3.18/Mcf on sales of natural gas and an average price of $88.19/bbl on sales of crude oil and liquids.
- Field netbacks for the year ended December 31, 2012 were $1.60/Mcf from sales of natural gas and $54.83/bbl from sales of oil and liquids.
- Capital expenditures during the year ended December 31, 2012 were $12.8 million.
- Cash and available credit under the Corporation''s credit facilities totalled $3.7 million at December 31, 2012.
SOUTHERN ONTARIO ASSETS
|Average daily volume during the year ended December 31,||2012||2011|
|Natural gas (Mcf/d)||10,081||10,538|
In 2012, oil production volumes increased to 721 bbl/d compared with an average of 692 bbl/d in 2011, with the natural decline rate being offset primarily by workover programs and the impact of the Torque acquisition. In response to declining natural gas prices, the Corporation reduced offshore capital expenditures, impacting average production volumes for natural gas in 2012.
Field Level Cash Flows
|For the year ended December 31,||2012||2011|
|Natural Gas||Oil and Liquids||Total||Natural Gas||Oil and Liquids||Total|
|Realized risk management gain (loss)||2,963||965||3,928||1,065||(62||)||1,003|
|Field level cash flows||$||5,927||$||15,001||$||20,928||$||8,535||$||15,329||$||23,864|
Oil and gas sales, net of associated royalties, were $30.5 million during 2012, compared with revenues of $35.8 million earned in the prior year. Sales in 2012 were adversely impacted by a substantial decrease in the realized price of oil and natural gas.
Natural gas sales in 2012 represented 69% (2011 - 71%) of total production volume on a boe basis, and 33% (2011 - 41%) of total revenues from oil and gas sales. The Corporation realized an average price on sales of natural gas of $3.18/Mcf during 2012, a decrease of 29% from the average price of $4.50/Mcf realized in the prior year.
Sales of crude oil in 2012 represented 31% (2011 - 29%) of total production volume on a boe basis, and 67% (2011 - 59%) of total revenues from oil and gas sales. During 2012, the Corporation realized an average price on sales of crude oil of $89.44/bbl (2011 - $96.15/bbl), representing a premium of approximately 3% (2011 - 1%) over the average price of the Edmonton Par. The Corporation is exploring alternative marketing options to realign the price received for its Ontario oil production to the WTI benchmark for crude oil.
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 of Canadian to US foreign exchange rates. During the year ended December 31, 2012, the Corporation recognized a gain of $2.5 million (2011 - $3.1 million) from these arrangements. Subsequent to December 31, 2012, the Corporation entered into a commodity swap on an additional 500 bbls per day of oil from February 1, 2013 to December 31, 2013, at a fixed price in Canadian dollars of $98.22/bbl.
|For the year ended December 31,||2012||2011|
|Natural Gas||Oil and Liquids||Total||Natural Gas||Oil and Liquids||Total|
|Realized risk management gain (loss)||0.80||3.53||4.42||0.28||(0.24||)||1.11|
During 2012, the Corporation incurred capital expenditures of $12.8 million (2011 - $11.1 million) on oil and gas properties in southern Ontario.
In response to low natural gas prices, the Corporation limited its offshore capital expenditure activities to $0.1 million during 2012, compared with $4.1 million in the prior year. Offshore activities were limited to pipeline repairs and the Corporation''s abandonment activities. Onshore, the Corporation expended $2.2 million on drilling and completion activities and $1.5 million to stimulate four vertical wells and one horizontal well. As a result of these workovers, production increased by approximately 15 bbls/d.
In addition to its planned capital work program, during 2012, the Corporation purchased the Dundee Discovery, a new onshore drilling rig, for approximately $3.5 million. The Dundee Discovery was purchased in order to drill more efficiently than using rigs provided by local service providers, to lower the cost of drilling, and to increase the safety involved in drilling operations. The Dundee Discovery was used to drill two wells in late 2012 confirming the efficiency and safety objectives of the new equipment. The Corporation intends to offer the Dundee Discovery to the industry on a third-party basis.
The Corporation''s drill targets in late 2012 were in anticipation of extending the producing area of an oilfield. Each vertical well encountered dolomitic pay, but the quantity of recoverable oil was deemed uneconomic. The Corporation plans to re-enter the second well in the first quarter of 2013, and deviate the wellbore to a more prospective part of the reservoir.
The Corporation expended a further $3.6 million on the acquisition and processing of 2-D and 3-D seismic data, which will be critical in identifying drill candidates.
The Corporation''s current cash flows generated from ongoing operating activities, as well as amounts available pursuant to its credit facility, provide the Corporation with sufficient cash flow to support its planned capital expenditures. In the event that the Corporation determines that it wants to augment its currently planned capital expenditure and drilling program, the Corporation may consider alternative sources of capital, including potential debt or equity issuances.
CASTOR UNDERGROUND GAS STORAGE PROJECT
The construction of the Castor Project is complete and, in July 2012, the Castor Project was granted the provisional commissioning certificate, a prerequisite for the injection of cushion gas. The facilities will then be subject to testing and subsequent commissioning into the Spanish gas system. In December 2012, the Spanish authorities finalized amendments to the remuneration of underground natural gas storage projects, which Escal UGS S.L. and its lenders view as being an acceptable solution. However, final inclusion of the Castor Project into the Spanish gas system remains contingent on the injection of cushion gas, which is expected to be completed in the first half of 2013, followed by the subsequent completion of the necessary performance and control testing, and the conclusion of the audit by the Spanish authorities of the expenditures forming the remuneration basis.
INVESTMENT IN EUROGAS INTERNATIONAL INC.
At December 31, 2012, the Corporation held 32.2 million Series A Preference Shares of Eurogas International Inc. ("Eurogas International") at a nominal value. Eurogas International holds a 45% participating 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 November 2012, the Tunisian authorities approved a renewal of the Sfax Permit to December 8, 2015 (the "First Renewal Period"). Eurogas International is committed to drilling two exploration wells prior to expiry of the First Renewal Period. The actual cost of drilling these wells will depend on the selection of the prospect and location within the Sfax Permit. Eurogas International is currently exploring options to raise the necessary funding to complete these commitments.
The Corporation believes that important measures of 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 price management contracts.
- "Field Netbacks" refers 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".
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, 2012.
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.