Delphi Energy Corp.
TSX : DEE

Delphi Energy Corp.

May 06, 2009 21:39 ET

Delphi Energy Continues Drilling Success at Hythe

CALGARY, ALBERTA--(Marketwire - May 6, 2009) - Delphi Energy Corp. ("Delphi" or "the Company") (TSX:DEE) is pleased to announce its financial and operational results for the quarter ended March 31, 2009.

First Quarter 2009 Highlights

- Achieved record production of 6,762 barrels of oil equivalent per day (boe/d) in the first quarter of 2009, marking the eighth consecutive quarter of production growth.

- Generated funds from operations of $10.0 million ($0.13 per basic share).

- Production volumes at Hythe, Alberta have grown over 400 percent to approximately 2,100 boe/d since acquiring the property in September 2007.

- Drilled 5 (3.8 net) wells with an overall success rate of 100 percent.

- Increased the Company's natural gas hedge position to 52 percent of current production at an average floor price of $7.35 per mcf for the remainder of 2009.



Financial Highlights
($ thousands except per unit amounts)
Three Months Ended March 31
2009 2008 % Change
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Petroleum and natural gas sales 24,205 32,212 (25)
Per boe 39.77 58.45 (32)
Funds from operations 10,017 17,059 (41)
Per boe 16.47 30.95 (47)
Per share - Basic 0.13 0.25 (48)
Per share - Diluted 0.13 0.25 (48)
Net earnings (loss) (3,320) (739) 349
Per boe (5.45) (1.34) 307
Per share - Basic (0.04) (0.01) 300
Per share - Diluted (0.04) (0.01) 300
Capital invested 14,092 26,498 (47)
Disposition of properties (151) - 100
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Net capital invested 13,941 26,498 (47)
Acquisition of properties - - -
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Total capital 13,941 26,498 (47)
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Mar. 31 Dec. 31
2009 2008 % Change
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Debt plus working capital deficiency (1) 113,162 109,237 4
Total assets 363,069 364,538 -
Shares outstanding (000's)
Basic 79,067 79,067 -
Diluted 85,875 83,798 -
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(1) excludes risk management asset and the related current future income tax
liability.


Operational Highlights

Three Months Ended March 31
Production 2009 2008 % Change
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Natural gas (mcf/d) 34,813 31,777 10
Crude oil (bbl/d) 475 387 23
Natural gas liquids (bbl/d) 485 372 30
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Total (boe/d) 6,762 6,056 12
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MESSAGE TO SHAREHOLDERS

Delphi enjoyed a successful first quarter to start 2009, accomplishing operational growth, strong capital efficiencies and continued financial flexibility to ensure the Company remains well positioned for sustainable long-term, organic growth in any business environment. The global recession continues with commodity prices remaining under pressure, however, Delphi believes it can operate effectively in these challenging times and is in a position of relative strength to many of its peer group. Over the past eight quarters, Delphi has delivered 56 percent growth in production, with 75 percent of this growth coming from the drill bit, funded internally through cash flow. The remaining 25 percent of production growth has been derived from strategic acquisitions. In addition, net debt has been reduced by $5.0 million over this time period.

During the first quarter, the Company drilled five gross (3.8 net) gas wells with a drilling success rate of 100 percent. Four of the five wells drilled in the first quarter and one well (0.5 net), which was drilled during the fourth quarter of 2008, were completed and commenced sales prior to the end of the first quarter. The remaining well (0.05 net) drilled in the first quarter will be completed and tied in to sales during the second half of 2009. In total, 14 separate intervals were completed during the first quarter for an average completion rate of 2.8 zones per well resulting in an average first month production rate per well of approximately 325 boe/d net to Delphi. The focus of the first quarter program was directed towards the Hythe and Bigstone properties to take advantage of the multi-zone nature of these assets, low operating costs and quick on-stream capability associated with owned gathering and processing infrastructure. Total net capital associated with the program for the first quarter was $14.0 million.

Production during the first quarter of 2009 averaged 6,762 boe/d, an increase of 12 percent compared to 6,056 boe/d in the first quarter of 2008 and one percent greater than the previous quarter of 6,708 boe/d. First quarter production represented Delphi's eighth consecutive quarter of production growth. Continued growth at Hythe has resulted in production volumes in the area growing by over 400 percent to approximately 2,100 boe/d since acquiring the property in September 2007.

Delphi's production continues to receive a significant premium to the price at AECO due to marketing arrangements, heating content and natural gas hedges. Approximately 44 percent of the Company's natural gas production was hedged at an average price of $7.66 per mcf in the first quarter, resulting in a gain on natural gas contracts of $4.0 million. Delphi's realized natural gas price of $6.55 per mcf in the first quarter represented a premium of 32 percent to the average AECO price in the quarter.

To view the Production Growth chart, please click the following link: http://media3.marketwire.com/docs/506dee1.pdf

Funds from operations in the first quarter of 2009 were $10.0 million ($0.13 per basic share) compared to $17.1 million ($0.25 per basic share) in the first quarter of 2008, primarily as a result of lower average oil and natural gas prices offset by increased production volumes and a five percent reduction in cash operating costs per boe.

At March 31, 2009, the Company had net debt of $113.2 million, an increase from $109.2 million at December 31, 2008. The increase in net debt during the first quarter resulted from Delphi's 's planned capital program that exceeded cash flow to take advantage of attractive farm-in opportunities and the reduced cost of oilfield services. Second quarter capital expenditures are anticipated to be significantly lower than cash flow, thereby reducing the Company's net debt at quarter end to approximately $105.0 to $107.0 million. Net debt includes bank debt plus working capital deficiency excluding the risk management asset and the related current future income taxes liability.

The annual credit review by the Company's lenders is underway and is expected to be completed no later than May 31, 2009. This detailed review utilizes the Company's December 31, 2008 reserves engineering report and will take into consideration current production, including the results of the winter drilling program. The credit review establishes the borrowing base, which is determined using the Company's year-end engineering report, primarily proved producing reserves which increased 21 percent over the previous year, and the outlook for commodity prices.

NORTH WEST ALBERTA

Hythe

At Hythe, the Company drilled, cased and completed two (2.0 net) wells consisting of one vertical multi-zone completion and one horizontal single zone completion during the first quarter. The vertical well was successful in applying existing exploitation techniques, downspacing and multi-zone completions, which maximizes reserve recovery and capital efficiency. The horizontal well was successful in applying two emerging technologies, multi-stage fracture stimulation and liquefied petroleum gas fracturing, to achieve economic success from an interval that historically had only been marginally economic in the area. Current production from the Hythe property is approximately 2,100 boe/d, a significant increase from the 400 boe/d the property was producing when acquired in September 2007. The success of the first quarter program has not only generated direct offset locations, but more importantly, has validated exploitation concepts and technologies that can be applied to Delphi's 95 sections of undeveloped lands which will generate a multi-year program of repeatable and predictable low risk development opportunities.

The Company anticipates drilling up to six wells in the area in the second half of 2009 and the results of this program will be utilized to generate the capital program for winter 2009/10. At Hythe, a typical vertical well would receive a drilling royalty credit of approximately $460,000, a typical horizontal well would receive a drilling royalty credit of approximately $600,000 and both wells would receive a further royalty reduction of up to $300,000 from the New Well Royalty Reduction program.

Delphi continues to take advantage of attractive opportunities resulting from the current business environment through the acquisition of strategic undeveloped land and farming in on low risk development projects in the Company's core areas that other joint venture partners have chosen not to fund. During the first quarter, the Company successfully participated in several Crown land sales acquiring 6,788 gross acres, at a working interest of 100 percent. In addition, two of the most prolific wells Delphi completed in the first quarter were associated with farm-ins that increased Delphi's average working interest per well from 22.5 percent to 75.0 percent.

Bigstone

At Bigstone, Delphi drilled, cased and completed one well (0.75 net) in the first quarter and completed one well (0.5 net) that was drilled and cased in the fourth quarter of 2008. Both wells targeted liquids rich, natural gas in the Cretaceous aged formations at depths ranging from 2,200 to 2,600 metres. The success of these wells continues to demonstrate the consistent and repeatable development nature of this asset. Recent drilling activity has increased current production at Bigstone to approximately 3,000 boe/d (80 percent natural gas).

The Company anticipates drilling up to two wells in this area in the second half of 2009 which will be followed up with increased drilling activity next winter to take advantage of the recently announced royalty credit programs by the Government of Alberta. A typical well at Bigstone would receive a drilling royalty credit of approximately $540,000 and a further royalty reduction of up to $300,000 from the New Well Royalty Reduction program.

OUTLOOK

Natural gas prices have continued to weaken throughout the first part of the year and are at risk of further reduction as a result of natural gas supply in excess of demand, particularly due to reduced industrial demand from the lower economic activity in North America. Delphi will manage its capital spending prudently in light of the fact that potential lower natural gas prices may prevail for the remainder of 2009. As in prior years, the Company's risk management program provides stability to the Company's cash flow for the remainder of the year allowing a minimum level of capital to be incurred. During the second quarter, two of the Company's gas processing facilities have scheduled maintenance downtime which will impact production for the quarter. Assuming the downtime goes as planned, the Company is optimistic that second quarter production will result in a ninth consecutive quarter of production growth based on the strong performance of the winter capital program and field production to date. Delphi expects production to be between 6,750 and 6,850 boe/d for the second quarter. As in the prior year, capital for the second quarter is expected to be considerably less than cash flow for the quarter resulting in an expected reduction in net debt levels over the first six months of the year while potentially growing production volumes in a very low commodity environment.

Delphi is now in the planning phase for the third and fourth quarter capital program following minimal activity scheduled during the second quarter spring break-up. The Company will continue to be disciplined in its capital spending, focusing on the lowest risk development projects in its core areas of Bigstone and Hythe. Drilling to develop the resource potential in the Bluesky, Dunvegan and/or Nikanassin formations from its Hythe property will be considered as part of the second half capital program. Operational risk, capital required and overall capital efficiencies will be the driving factors in pursuing the resource plays in the current and expected low natural gas price environment. The Board of Directors has approved a second half capital program of $18.0 to $23.0 million for a total capital program of $35.0 to $40.0 million in 2009.

Cash flow for 2009 is forecast to be between $38.0 million to $43.0 million on an average natural gas price for AECO of approximately $4.25 per mcf. The Company has hedged approximately 52 percent of its natural gas production at $7.35 per mcf for the remainder of 2009 to achieve this forecasted cash flow. Over the year, Delphi expects an overall reduction in net debt of approximately $2.0-$4.0 million from the amount outstanding at December 31, 2008.

Delphi remains confident in its ability to achieve continued per share growth during these challenging times and is excited about the 2009 drilling program. The expanding inventory of drilling locations and growth prospects being generated gives rise to continued optimism for growth well beyond 2009.

On behalf of the Board of Directors and all the employees of Delphi, I would like to thank our shareholders for their continued support and patience in these very difficult and uncertain economic times. Our team's effort remains focused on sustainable economic growth while maintaining the financial strength and flexibility to take advantage of strategic opportunities which may arise in the coming year.

CONFERENCE CALL

A conference call is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Thursday, May 7, 2009. The conference call number is 1-866-300-4047 or 416-641-6137. A brief presentation by David Reid, President and CEO and Brian Kohlhammer, VP Finance & CFO will be followed by a question and answer period.

If you are unable to participate in the conference call, a taped broadcast will be available until May 14, 2009. To access the replay, dial 1-800-408-3053 or 416-695-5800. The passcode is 5524855. Delphi's first quarter 2009 financial statements and management's discussion and analysis are available on Delphi's website at www.delphienergy.ca and will be available on SEDAR at www.sedar.com within 24 hours.

Delphi Energy is a Calgary-based company that explores, develops and produces oil and natural gas in Western Canada. The Company is managed by a proven technical team. Delphi trades on the Toronto Stock Exchange under the symbol DEE.

Forward-Looking Statements. This release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", may", "will", "should", believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.

More particularly and without limitation, this release contains forward looking statements and information relating to the Company's risk management program, petroleum and natural gas production, future funds from operations, capital programs, commodity prices, costs and debt levels. The forward-looking statements and information are based on certain key expectations and assumptions made by Delphi, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the capital availability to undertake planned activities and the availability and cost of labour and services.

Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect the Company's operations or financial results are included in reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). The forward-looking statements and information contained in this press release are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Basis of Presentation. For the purpose of reporting production information, reserves and calculating unit prices and costs, natural gas volumes have been converted to a barrel of oil equivalent (boe) using six thousand cubic feet equal to one barrel. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with the Canadian Securities Administrators' National Instrument 51-101 when boes are disclosed. Boes may be misleading, particularly if used in isolation.

Non-GAAP Measures. The release contains the terms "funds from operations", "funds from operations per share", "net debt", "cash operating costs" and "netbacks" which are not recognized measures under Canadian generally accepted accounting principles. The Company uses these measures to help evaluate its performance. Management considers netbacks an important measure as it demonstrates its profitability relative to current commodity prices. Management uses funds from operations to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and to repay debt. Funds from operations is a non-GAAP measure and has been defined by the Company as net earnings plus the addback of non-cash items (depletion, depreciation and accretion, stock-based compensation, future income taxes and unrealized gain/(loss) on risk management activities) and excludes the change in non-cash working capital related to operating activities and expenditures on asset retirement obligations and reclamation. The Company also presents funds from operations per share whereby amounts per share are calculated using weighted average shares outstanding consistent with the calculation of earnings per share. Delphi's determination of funds from operations may not be comparable to that reported by other companies nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. The Company has defined net debt as the sum of long term debt plus working capital excluding the current portion of future income taxes and risk management asset/liability. Net debt is used by management to monitor remaining availability under its credit facilities. Cash operating costs have been defined as the sum of operating expenses, transportation expenses, general and administrative expenses and interest costs.

MANAGEMENT DISCUSSION AND ANALYSIS

(All tabular amounts are stated in thousands of dollars, except per unit amounts)

The management discussion and analysis has been prepared by management and reviewed and approved by the Board of Directors of Delphi Energy Corp. ("Delphi" or "the Company"). The discussion and analysis is a review of the financial results of the Company based upon accounting principles generally accepted in Canada. Its focus is primarily a comparison of the financial performance for the three months ended March 31, 2009 and 2008 and should be read in conjunction with the audited financial statements and accompanying notes for the years ended December 31, 2008 and 2007. The discussion and analysis has been prepared as of May 5, 2009.

OPERATIONAL AND FINANCIAL HIGHLIGHTS

Delphi delivered another record quarterly production average of 6,762 barrels of oil equivalent per day (boe/d), representing the eighth consecutive quarter of production growth and a 12 percent increase from the comparable period in 2008. This consistent production growth in varying economic conditions speaks to the quality of the Company's core assets, management and staff and inventory of opportunities. Natural gas production comprised 86 percent of the Company's average production.

Funds flow from operations in the first quarter of 2009 was $10.0 million or $0.13 per basic share, compared to $17.1 million or $0.25 per basic share in 2008, primarily as a result of lower average oil and natural gas prices for the quarter offset by the growth in production volumes and a five percent reduction in cash operating costs per boe to the comparative quarter. Delphi's risk management program continued to contribute to funds from operations providing the Company with $4.0 million in realized gains in the quarter.

Delphi's financial position continues to remain strong in the first quarter of 2009, providing financial flexibility to execute the remainder of its 2009 capital program and reduce debt from current levels. At March 31, 2009, the Company had net debt of $113.2 million on total credit facilities of $140.0 million, providing excess financial capacity of approximately $26.8 million.

The annual credit review by the Company's lenders is underway and is expected to be completed no later than May 31, 2009. This detailed review will be based upon the Company's December 31, 2008 reserves engineering report and will take into consideration current production and the results of the winter drilling program. The borrowing base is determined using the Company's year-end engineering report, primarily proved producing reserves, which increased 21 percent over the previous year and the outlook for commodity prices.



BUSINESS ENVIRONMENT

Benchmark Prices

Three Months Ended March 31
2009 2008 % Change
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Natural Gas
NYMEX (US $/mmbtu) 4.57 8.08 (43)
AECO (CDN $/mcf) 4.95 7.97 (38)
Crude Oil
West Texas Intermediate (US $/bbl) 43.08 97.86 (56)
Edmonton Light (CDN $/bbl) 49.65 97.50 (49)
Foreign Exchange
Canadian to US dollar 1.24 1.00 24
US to Canadian dollar 0.80 1.00 (20)
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Natural Gas

United States natural gas prices are commonly referenced to the New York Mercantile Exchange Henry Hub in Louisiana (NYMEX) while Canadian natural gas prices are typically referenced to the Canadian Alberta Energy Company interconnect with the TransCanada Alberta system (AECO). Natural gas prices are influenced more by North American supply and demand than global fundamentals, however, with the growth in natural gas liquefaction and regasification facilities around the world this North American supply and demand balance has become subject to disruption from time to time. The increase in capacity of natural gas liquefaction and regasification facilities has resulted in natural gas in North America becoming a global commodity with influences from world weather conditions and global supply in the form of liquefied natural gas (LNG) delivered to the United States.

In the first quarter of 2009, the stability of natural gas prices in anticipation of normal withdrawals from storage to meet winter heating demand began to slide. The U.S. Midwest and Central Canada were experiencing continuous cold weather resulting in reasonable winter heating demand, however, the U.S. Northeast, representing the largest proportion of winter heating demand, experienced above average temperatures and industrial demand was significantly reduced due to the current economic slowdown. Downward pressure on natural gas prices began early in 2009 and has continued into the second quarter as natural gas storage numbers continue to grow over the five year average levels. AECO averaged $4.95 per mcf in the first quarter and continues to decline. The drop in natural gas prices has had a significant affect on the active drilling rig count in both Canada and the United States.

For internal forecasting purposes, Delphi is expecting a volatile natural gas market in 2009 and anticipates AECO to average between $4.00 and $6.00 per mcf. Delphi continues to monitor the variables affecting the price of natural gas in order to ensure its capital program is in line with expected funds flow from operations.

Crude Oil

West Texas Intermediate at Cushing, Oklahoma (WTI) is the benchmark reference for North American crude oil prices. Canadian crude oil prices are based upon postings, primarily at Edmonton, Alberta and represent the WTI price adjusted for quality and transportation differentials as well as the US/CDN dollar exchange rate.

Through the first quarter of 2009, the price for crude oil fluctuated between U.S. $35.00 and $50.00 per barrel. WTI averaged U.S. $43.08 per barrel for the quarter compared to U.S. $97.86 per barrel for the same quarter in the prior year, a decrease of 56 percent. Crude oil supplies continued to grow in the quarter as demand was significantly reduced due to the slowdown in global economies and use of energy.

In the first quarter of 2009, the value of the Canadian dollar decreased against its U.S. counterpart as the demand for the United States dollar rose during these uncertain times. This positive effect to the price of oil for Canadian producers was partially offset by a widening basis differential between U.S. and Canadian markets. In the first quarter of 2009, Canadian crude oil prices averaged U.S. $49.65 per barrel compared to U.S. $97.50 per barrel for the same quarter in the prior year, a decrease of 49 percent.

Prices for heavy oil and other lesser quality crude oils trade at a discount or differential to light crude oil due to the additional costs involved in the refining process. The average differential in the first quarter of 2009 was $5.25 per barrel compared to $19.46 per barrel in 2008. The decrease in the average differential and lower light oil prices, resulted in Bow River crude prices averaging $44.41 per barrel compared to $78.04 per barrel in the first quarter of 2008.

For internal forecasting purposes, Delphi anticipates WTI to average between U.S. $40.00 to $60.00 per barrel for 2009 with the Canadian dollar to remain between $1.15 and $1.30 per U.S. dollar.

Industry Cost of Services

The drop in commodity prices in the latter half of 2008 and through 2009 so far in combination with the New Royalty Framework effective January 1, 2009 have had a significant negative effect on cash flow available for capital programs and hence drilling and field activity. Drilling contractors and oilfield service companies have had to reduce the rates charged for equipment and labour in order to remain competitive and as active as possible, but at a much slower pace than in previous years. The overall uncertainty in the credit and capital markets has also led to reduced demand for oilfield services and equipment as companies have been unable to raise external sources of funding to pursue capital programs.

FINANCIAL STRATEGY

The Company maintains an active risk management program as an integral part of its overall financial strategy to mitigate volatility in funds from operations resulting from fluctuating commodity prices. Delphi's program involves executing numerous contracts over a period of time to take advantage of the volatility in the natural gas market. The strategy takes advantage of the upward swings in natural gas prices as a result of a) the changes in demand/supply fundamentals and/or b) the movement of significant financial assets invested in the natural gas market as a pure commodity play. The transactions are generally undertaken for contract terms 12 to 24 months in advance with financially strong counterparties, predominantly executed on a physical basis with the Company's natural gas marketer. Delphi's risk management program consists of fixed price contracts, costless collars, participating swaps and puts and calls which provide downside protection along with the opportunity to share in the upside if market prices increase above the floor price for the costless collar, participating swaps and puts. If market prices are above fixed price contracts or the ceiling price of costless collars and calls, the Company would continue to achieve its downside protection while realizing losses on these hedging contracts.

Delphi has a strategy of hedging approximately 40 to 50 percent of its natural gas production as long as demand/supply fundamentals indicate volatile markets in the future. Currently, Delphi has hedged approximately 52 percent of its before-royalty natural gas production at a predominantly AECO based average floor price of $7.35 per mcf for the remainder of 2009. This compares to the current forward 2009 strip commodity price for AECO of $3.99 per mcf as of April 30, 2009. The following natural gas hedges are in place to support the Company's cash flow.



Apr-Oct Nov-Mar Apr-Dec Apr-Dec Jan-Dec
2009 2009/2010 2010 2009 2010
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Production hedged (mmcf/d) 19.0 13.1 6.6 18.6 7.6
Percentage of production (1) 53% 36% 18% 52% 21%
Price floor (Cdn $/mcf) $7.38 $7.51 $6.39 $7.35 $6.88
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(1) based on 36 mmcf/d


The fair value of the outstanding hedges is estimated to be approximately $18.8 million as of April 30, 2009.

As the Company's financial condition improves and/or natural gas demand/supply fundamentals move toward equilibrium or reduced supply, Delphi will manage its hedging program accordingly to take advantage of exposure to higher natural gas commodity prices.

Delphi continues to direct efforts at maintaining or reducing its controllable costs. Increasing production at its various operating fields through Company owned infrastructure reduces fixed costs on a per boe basis and improves netbacks. Field operators are encouraged to undertake preventative maintenance on field infrastructure and wellsite equipment to minimize production downtime and prevent significant operating costs associated with repairs. The Company strives to achieve improvement in its costs of production and at a minimum maintain current production costs.

Maintaining or improving strong operating netbacks per boe through the risk management program and the control of costs associated with production operations, allows the Company to pursue its planned capital program with greater confidence that financial flexibility will be maintained while incurring capital expenditures to grow production volumes. The Company strives to maintain a minimum operating netback per boe in the $29.00 to $31.00 range as it has in the past four years. The risk management program has been and will continue to be an integral part of maximizing operating netbacks during periods of price volatility and excess natural gas supply.

The annual net capital expenditure program will continue to be slightly less than forecast funds from operations. Additional capital may be approved as a result of opportunistic acquisitions, incremental cash flow from greater than expected production growth, higher than forecast cash netbacks or other sources of financing.

Delphi continues to be focused on reducing its leverage and improving its financial flexibility through net debt reduction or increasing funds flow growth resulting in a lower net debt to annualized quarterly funds from operations ratio. The Company continues to be focused on achieving its internal target range for this ratio of 1.3 to 1.5 times. In a low price environment, the Company's objective would be to reduce or at least maintain the net debt balance by undertaking a capital program within cash flow.




SELECTED INFORMATION

The following table sets forth certain information of the Company for the
past eight consecutive quarters.

Mar. Dec. Sept. Jun. Mar. Dec. Sept. Jun.
31 31 30 30 31 31 30 30
2009 2008 2008 2008 2008 2007 2007 2007
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Production
Natural gas
(mcf/d) 34,813 35,545 33,691 31,898 31,777 30,610 28,196 26,967
Oil (bbl/d) 475 431 372 368 387 346 579 423
Natural gas
liquids (bbl/d) 485 353 421 517 372 420 422 461
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Barrels of oil
equivalent
(boe/d) 6,762 6,708 6,409 6,202 6,056 5,868 5,700 5,379
Financial
($ thousands
except per
unit amounts)
Petroleum and
natural gas
revenue 24,205 30,160 34,461 38,569 32,212 26,632 24,548 24,779
Funds from
operations 10,017 13,473 18,160 19,965 17,059 13,747 12,600 11,469
Per share -
basic 0.13 0.18 0.24 0.29 0.25 0.20 0.19 0.17
Per share -
diluted 0.13 0.18 0.23 0.28 0.25 0.20 0.18 0.17
Net earnings
(loss) (3,320) (959) 6,743 49 (739) 1,732 (1,348) 797
Per share -
basic (0.04) (0.01) 0.09 - (0.01) 0.03 (0.02) 0.01
Per share -
diluted (0.04) (0.01) 0.09 - (0.01) 0.03 (0.02) 0.01
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Production for the last eight consecutive quarters reflects the following events: In 2007, success at Bigstone, Alberta throughout the year and Noel, British Columbia in the third quarter complemented the mid-year start up of production at Tower Creek, Alberta resulting in consistent quarter over quarter production growth. In 2008, the combination of a successful winter and summer capital program and the production increase from the acquisition resulted in continued production growth quarter over quarter. In the first quarter of 2009, production growth was achieved with drilling success at Bigstone and Hythe, Alberta. Revenue and funds from operations reflect the cycle of natural gas prices and production volumes.

Natural gas prices over the past two years have generally reflected the cyclical nature of demand. Higher prices in the winter months, reflecting demand for heating, weaken through the summer months as production is placed in storage for the upcoming heating season demand. Natural gas prices in the second quarter of 2008 did not follow the cyclical trend expected, as prices continued to increase coming out of the winter heating season due to concerns over natural gas supply in storage and the continued increase in crude oil prices. Subsequent to the second quarter, natural gas prices decreased significantly and then stabilized in the fourth quarter. In 2009, reduced heating demand and industrial demand due to the economic crisis caused natural gas prices to decrease further through the winter months as a result of concerns over excess supply. The Company achieved record cash flow of approximately $20.0 million in the second quarter of 2008 at the peak of commodity prices. Delphi continues to mitigate the volatility of commodity prices on its cash flow and capital program by undertaking an active risk management program.



DRILLING RESULTS

Three Months Ended March 31, 2009
Gross Net
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Natural gas wells 5.0 3.8
Oil wells - -
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Total wells 5.0 3.8
Success rate (%) 100 100
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The Company had another successful quarter with the drill bit resulting in a drilling success rate of 100 percent. The Company has in excess of one hundred drilling locations identified within its core areas of operations.



CAPITAL INVESTED

Three Months Ended March 31
2009 2008 % Change
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Land 266 - 100
Seismic 26 3 767
Drilling and completions 11,010 18,496 (40)
Equipping and facilities 1,478 6,927 (79)
Capitalized expenses 1,116 637 75
Other 196 435 (55)
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Capital invested 14,092 26,498 (47)
Disposition of properties (151) - 100
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Net capital invested 13,941 26,498 (47)
Acquisition of properties - - -
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Total capital 13,941 26,498 (47)
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The Company continues to focus its capital program towards its core areas of Bigstone and Hythe to take advantage of the multi-zone nature of these assets, low operating costs and quick on-stream capability associated with owned gathering and processing infrastructure. During the first quarter of 2009, the Company directed the majority of capital to the drilling, completion and tie-in of two wells at Hythe, Alberta, one well at Bigstone, Alberta and one well at Noel, British Columbia. Capital was also incurred for completion and tie-in operations of a well drilled in the fourth quarter of 2008 at Bigstone. Total net capital for the quarter was $14.0 million, representing a 47 percent reduction from the prior year due to lower commodity prices and cash flow. Approximately 79 percent of net capital was directed at drilling and completions to increase the production and reserve base of the Company.



PRODUCTION

Three Months Ended March 31
2009 2008 % Change
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Natural gas (mcf/d) 34,813 31,777 10
Crude oil (bbls/d) 475 387 23
Natural gas liquids (bbls/d) 485 372 30
----------------------------------------------------------------------------
Total (boe/d) 6,762 6,056 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production for the three months ended March 31, 2009 averaged 6,762 boe/d, an increase of 12 percent over the comparative period primarily due to the successful drilling and optimization programs at Bigstone and Hythe and the closing of the acquisition in the Peace River Arch area by the end of July, 2008. First quarter 2009 production volumes represent the eighth consecutive quarter of production growth for the Company.

Delivering consistent results in varying economic environments is a testament to the quality of the Company's core assets. The Bigstone and Hythe areas continue to lead the way in production and growth contributing 65 percent of Delphi's first quarter volumes. Production at Hythe, Alberta has grown from 400 boe/d, at the time of acquisition in September 2007, to approximately 2,100 boe/d. A significant undeveloped land base, multi-zone potential and the successful application of emerging technologies continue to provide material growth opportunities in existing and new play concepts. The Company's production portfolio for the year was weighted 86 percent to natural gas, seven percent to crude oil and seven percent to natural gas liquids.

Crude oil production was 23 percent higher for the three months ended March 31, 2009 due to increased production from Bigstone and Hythe, Alberta.

To view the Production Growth chart, please click the following link: http://media3.marketwire.com/docs/506dee2.pdf

Natural gas liquids were 30 percent higher for the three months ended March 31, 2009, as compared to the comparative period in 2008 due to the liquids production associated with the properties acquired in the Peace River Arch area.



REALIZED SALES PRICES

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
AECO ($/mcf) 4.95 7.97 (38)
Heating content and marketing ($/mcf) 0.32 0.47 (32)
Gain on physical contracts ($/mcf) 0.95 0.42 125
Gain on financial contracts ($/mcf) 0.33 0.05 557
----------------------------------------------------------------------------
Realized natural gas price ($/mcf) 6.55 8.91 (27)

Realized oil price ($/bbl) 46.11 85.05 (46)

Realized natural gas liquids price ($/bbl) 39.04 79.26 (51)
----------------------------------------------------------------------------
Total realized sales price ($/boe) 39.77 58.45 (32)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three months ended March 31, 2009, Delphi's risk management program realized a gain of $4.0 million. The realized gain was $1.28 per mcf with physical contracts contributing a gain of $0.95 per mcf and financial contracts contributing a gain of $0.33 per mcf. For the period ended March 31, 2009, the average realized natural gas price was 27 percent less than the comparative quarter due to a 38 percent decrease in the AECO spot price offset by significant hedging gains realized.

Excluding hedges, the Company continues to receive higher than the AECO spot price on natural gas sales due to the high heating content of its natural gas production and the sale of approximately 3,500 million British thermal units (mmbtu) per day on the Alliance pipeline which is priced at the Chicago Monthly Index.

The following table outlines the premium (discount) Delphi realized on natural gas prices compared to the average quarterly AECO price due to the risk management program, quality of production and gas marketing arrangements. In years of both high and low commodity price environments, Delphi's realized sales price has benefited from a premium to AECO.



Mar. Dec. Sept. Jun. Mar. Dec. Sept. Jun.
31 31 30 30 31 31 30 30
2009 2008 2008 2008 2008 2007 2007 2007
----------------------------------------------------------------------------
Natural Gas Price
Delphi realized
($/mcf) 6.55 8.14 8.28 9.77 8.91 7.61 7.20 8.20
AECO average
($/mcf) 4.95 6.70 7.73 10.22 7.97 6.15 5.14 7.06
Premium
(discount) to
AECO 32% 21% 7% (4%) 12% 24% 40% 16%
Hedging gain (loss)
($000's) 3,991 1,985 (67) (3,153) 1,371 2,996 3,875 1,130
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Delphi's oil production is slightly better than medium grade oil; therefore the Company's average price fluctuates with the change in the benchmark crude oil prices and the quality differential. Increased production of light oil at Bigstone and Hythe continues to high grade the Company's quality of crude oil resulting in pricing more reflective of light oil. In the first quarter, the Company's realized crude oil and natural gas liquids prices were significantly lower than the comparative quarter in the previous year as a result of the significant drop in the benchmark crude oil prices.

To view Natural Gas Prices chart, please click here: http://media3.marketwire.com/docs/506dee3.pdf

RISK MANAGEMENT ACTIVITIES

Delphi enters into both financial and physical commodity contracts as part of its risk management program to manage commodity price fluctuations designed to ensure sufficient cash is generated to fund its capital program particularly when commodity prices are extremely volatile. Delphi makes a concerted effort to hedge production volumes at prices greater than the upper limit of the historical three to five year AECO price range of $5.25 to $8.40 per mcf and is quick to react to price aberrations such as those experienced at the end of 2005 and the summer of 2008. Another component of the risk management program is to layer in contracts over a period of time, as opposed to locking in a significant portion of volumes at any one point in time, to take advantage of unexpected price spikes. For natural gas production, Delphi has hedged approximately 52 percent of its before-royalty natural gas production at a predominately AECO based average floor price of $7.35 per mcf for the last nine months of 2009.

With respect to financial contracts, which are derivative financial instruments, management has elected not to use hedge accounting and consequently records the fair value of its natural gas financial contracts on the balance sheet at each reporting period with the change in the fair value being classified as unrealized gains and losses in the statement of earnings. The changes in the fair value of the United States dollar denominated physical contracts are also classified as unrealized gains and losses in the statement of earnings.

The Company recognized an unrealized non-cash gain on risk management activities of $0.6 million for the three months ended March 31, 2009. The fair values of these contracts are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the contracts outstanding at the end of the period having regard to forward prices and market values provided by independent sources. Due to the inherent volatility in commodity prices, actual amounts realized may differ from these estimates.



The Company has fixed the price applicable to future production through the
following contracts.

Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
April 2009 - Natural
October 2009 Gas Physical 1,000 GJ/d $7.08 fixed

April 2009 - Natural $8.25 floor/$10.00
October 2009 Gas Physical 2,000 GJ/d ceiling

April 2009 - Natural
October 2009 Gas Physical 1,000 mmbtu/d U.S. $8.18 fixed

April 2009 - Natural
October 2009 Gas Physical 2,000 GJ/d $8.59 fixed

April 2009 - Natural $6.70 floor plus 50%
October 2009 Gas Physical 2,000 GJ/d greater than $6.70

April 2009 - Natural
March 2010 Gas Physical 3,000 GJ/d $7.52 fixed

April 2009 - Natural $6.80 floor plus 50%
March 2010 Gas Physical 2,000 GJ/d greater than $6.80

November 2009 - Natural $7.75 floor/$8.70
March 2010 Gas Physical 2,000 GJ/d ceiling

November 2009 - Natural $7.26 floor plus 50%
March 2010 Gas Physical 2,000 GJ/d greater than $7.26

November 2009 - Natural $7.65 floor plus 50%
March 2010 Gas Physical 2,000 GJ/d greater than $7.65

April 2010 - Natural $6.25 floor/$7.47
December 2010 Gas Physical 3,000 GJ/d ceiling

April 2010 - Natural $5.93 floor plus 50%
December 2010 Gas Physical 4,000 GJ/d greater than $5.93

February 2009 - Natural
December 2009(i) Gas Financial 3,500 GJ/d $6.00 Put

March 2009 - Natural
December 2009(i) Gas Physical 3,500 GJ/d $6.00 Put

January 2010 - Natural
December 2010(i) Gas Financial 3,500 GJ/d $7.40 Call

January 2010 - Natural
December 2010(i) Gas Physical 3,500 GJ/d $7.15 Call
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) The Company has acquired two natural gas put contracts at $6.00 per
gigajoule on 3,500 gigajoules per day each for the periods February 1,
2009 through December 31, 2009, and March 1, 2009 through December 31,
2009, respectively. These puts were paid for with the sale of natural
gas calls on 7,000 gigajoules per day at an average price of $7.28 per
gigajoule for the period January 1, 2010 through December 31, 2010.


The Company accounts for its Canadian dollar physical sales contracts, which were entered into and continue to be held for the purpose of delivery of production, in accordance with its expected sale requirements as executory contracts on an accrual basis rather than as non-financial derivatives.



REVENUE

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Natural gas 16,521 24,405 (32)
Natural gas physical contract gains 2,962 1,223 142
Crude oil 1,971 3,002 (34)
Natural gas liquids 1,704 2,918 (42)
Sulphur 18 516 (97)
Realized gain on risk management
contracts 1,029 148 595
----------------------------------------------------------------------------
Total 24,205 32,212 (25)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The 25 percent decrease in revenue for the three months ended March 31, 2009, over the comparative period, is attributed to a 32 percent decrease in the realized sales price per boe offset by the 12 percent increase in production volumes.

Additionally, during the first quarter of 2008, sulphur prices began their rise as demand for fertilizers increased around the world. Delphi received $0.5 million from the sale of sulphur during the first quarter of 2008, primarily associated with production at its Tower Creek well. As a result of the slowing economies around the world, sulphur prices have fallen significantly resulting in minimal sales in the first quarter of 2009 despite ongoing production at Tower Creek.



ROYALTIES

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Total 4,443 5,862 (24)
Per boe 7.30 10.64 (31)
Percent of revenue including
realized hedges 18.4 18.2 1
Percent of revenue excluding
realized hedges 22.0 19.5 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company pays royalties to provincial governments (Crown), freeholders, which can be individuals or companies, and other oil and gas operators that own surface or mineral rights. Crown royalty rates are calculated on a sliding scale based on commodity prices and individual well production rates. Royalty rates can change due to price fluctuations or changes in production volumes on a well by well basis subject to a minimum and maximum rate restriction ascribed by the Crown. For the three months ended March 31, 2009, royalties as a percentage of revenue increased over the comparative period due to the New Royalty Framework (NRF) rates. As expected, the NRF has impacted high production wells negatively and has been cost beneficial to many lower rate producing wells. Overall, Delphi is expecting royalties as a percentage of revenue, before hedging, to be between 19 and 23 percent in 2009.

On October 25, 2007, the Government of Alberta announced the New Royalty Framework. The NRF established new royalties for oil and natural gas which are based on commodity prices, well production volumes and well depths. The NRF rates apply to both new and existing production and became effective on January 1, 2009. In the fourth quarter of 2008, the Government of Alberta announced royalty relief which provided that for new wells drilled after November 19, 2008, the Company could elect to have the pre-NRF royalty regime apply on those wells. On March 3, 2009, the Alberta Government announced further royalty incentives to promote oilfield activity in light of the current economic environment. The incentives provided drilling credits to be applied against royalties based on the depth drilled and a reduced royalty rate of five percent for natural gas production brought on-stream after March 31, 2009.



OPERATING EXPENSES

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Total 6,204 5,153 20
Per boe 10.19 9.35 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Operating costs on a per boe basis for the three months ended March 31, 2009, increased nine percent over the comparative period due to higher costs of fuel and power and contract operating fees primarily associated with the acquisition of properties and facilities in the Peace River Arch area. Delphi is focused on cost reduction and anticipates lower operating costs per boe as volumes increase at core areas and the industry experiences an expected reduction in field costs. The Company has already achieved cost reduction over the 2008 per boe average of 10.37 per boe. Delphi expects operating costs to be $9.75 to $10.25 per boe in 2009.



TRANSPORTATION EXPENSES

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Total 1,461 1,577 (7)
Per boe 2.40 2.86 (16)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In British Columbia, infrastructure is owned by Spectra Energy that enables natural gas producers to avoid facility construction in exchange for regulated gathering, processing and transmission fees. This all-in charge is included in transportation expenses.

On a per boe basis, transportation costs for the three months ended March 31, 2009, decreased by 16 percent over the comparative period due to higher production volumes with fixed firm service fees for production and lower transportation costs at Hythe, Alberta. Effective November 1, 2007 and again on November 1, 2008, Delphi transferred a portion of its excess processing and transmission capacity in North East British Columbia to third parties resulting in further reductions in transportation costs. The transfer will save approximately $2.7 million in transportation costs over the next three years and will result in lower transportation costs on a go forward basis. Delphi expects transportation costs to be between $2.30 and $2.75 per boe in 2009.



GENERAL AND ADMINISTRATIVE

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
General and administrative costs 3,257 2,004 63
Overhead recoveries (259) (368) (30)
Salary allocations (1,876) (662) 183
----------------------------------------------------------------------------
Net 1,122 974 15
Per boe 1.84 1.77 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On a per boe basis, general and administrative (G&A) costs for the three months ended March 31, 2009 increased four percent over the comparative period in 2008. The increase is due to additional technical staff hired year over year and additional rental expense for office space. As a result of high levels of activity for Delphi and for the industry as a whole, the costs associated with hiring, compensating and retaining employees and consultants have risen. Delphi is committed to delivering strong growth and believes a strong technical team is paramount to achieve this goal. For the remainder of 2009, Delphi is expecting G&A per boe to be approximately $1.80 to $2.00 per boe.



STOCK-BASED COMPENSATION

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Stock-based compensation 491 571 (14)
Capitalized costs 280 339 (17)
----------------------------------------------------------------------------
Net 211 232 (9)
Per boe 0.35 0.42 (18)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees, directors and key consultants of the Company. The fair value of all options granted is estimated at the date of grant using the Black-Scholes option pricing model. The stock based non-cash compensation expense for the three months ended March 31, 2009, decreased nine percent. During the three months ended March 31, 2009, Delphi capitalized $0.3 million of stock-based compensation associated with exploration and development activities.



INTEREST

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Total 958 1,587 (40)
Per boe 1.57 2.88 (45)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three months ended March 31, 2009, interest expense on a per boe basis decreased 45 percent over the comparable period due to lower interest costs from reduced interest rates and higher production volumes. Delphi anticipates interest per boe will continue to decrease in 2009 as average debt levels remain relatively consistent with the prior year, interest rates continue to decline in an effort to generate economic growth and additional production is brought on stream. The reduction in interest costs as a result of lower interest rates is expected to be, at least partially, offset by an increase in the Company's credit spread associated with its credit facilities due to the increased cost of funds being incurred by the Company's lenders.

During the first quarter of 2009, the Company converted $80.0 million of its outstanding long term debt from prime-based loans to bankers' acceptances. The bankers' acceptances have terms ranging from 62 to 182 days and a weighted average effective interest rate of 2.9 percent over the term.



DEPLETION, DEPRECIATION AND ACCRETION

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Depletion and depreciation 14,550 15,007 (3)
Accretion expense 243 144 69
----------------------------------------------------------------------------
Total 14,793 15,151 (2)
Per boe 24.31 27.49 (12)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Depletion, depreciation, and accretion per boe for the three months ended March 31, 2009 decreased 12 percent over the comparative period. With continued success at Bigstone and Hythe, Delphi is in an excellent position to continue to add proved reserves at metrics below the Company's current depletion rate. The Company experienced a decrease in depletion per boe during the first quarter of 2009 due to significant reserve additions being recognized in the fourth quarter of 2008 upon completion of the 2008 engineering report and in the first quarter of 2009 from a successful capital program. The decrease in total depletion and depreciation was a result of the depletion costs associated with increased production being more than offset by the improvement in the depletion rate.

Accretion expense of asset retirement obligations relates to the passing of time until the Company estimates it will retire its assets and restore the asset locations to a condition which meets or exceeds environmental standards. Due to the long term nature of certain assets of the Company, this accretion expense is estimated to extend over a term of three to 20 years. The Company uses a credit adjusted risk-free interest rate of 8.0 to 10.0 percent for the purpose of calculating the fair value of its asset retirement obligations and hence the accretion expense. The accretion expense for the three months ended March 31, 2009 increased 69 percent over the comparative period due to the wells acquired in the Peace River Arch acquisition in the third quarter of 2008.



TAXES

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Current - - -
Future (reduction) (1,107) (486) 128
----------------------------------------------------------------------------
Total (1,107) (486) 128
Per boe (1.82) (0.88) 107
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The provision for income taxes in the financial statements for the three months ended March 31, 2009, was a reduction of $1.1 million. Delphi does not anticipate it will be cash taxable before 2011.



FUNDS FROM OPERATIONS

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Net earnings (loss) (3,320) (739) 349
Non-cash items:
Depletion, depreciation and
accretion 14,793 15,151 (2)
Unrealized loss (gain) on risk
management activities (560) 2,901 -
Stock-based compensation
expense 211 232 (9)
Future income taxes
(reduction) (1,107) (486) 128
----------------------------------------------------------------------------
Funds from operations 10,017 17,059 (41)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three months ended March 31, 2009, funds from operations were $10.0 million ($0.13 per basic share) compared to $17.1 million ($0.25 per basic share) in the comparative period. The decrease in funds from operations of 41 percent resulted from a 32 percent reduction in revenue received per boe offset by a 12 percent increase in production per day and a five percent decrease in cash costs per boe.

Funds from operations is a non-GAAP measure and has been defined by the Company as net earnings (loss) plus the add back of non-cash items (depletion, depreciation and accretion, impairment provisions, stock-based compensation, future income taxes and unrealized gain (loss) on risk management activities) and excludes the change in non-cash working capital related to operating activities and expenditures on asset retirement obligations and reclamation. Management uses funds from operations to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and to repay debt.

The following table shows the reconciliation of funds from operations to cash flow from operating activities for the periods noted:



Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Funds from operations: Non-GAAP 10,017 17,059 (41)
Change in non-cash working capital (1,504) (8,153) (82)
----------------------------------------------------------------------------
Cash flow from operating
activities: GAAP 8,513 8,906 (4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NET EARNINGS

For the three months ended March 31, 2009, Delphi recorded a net loss of $3.3 million compared to a loss of $0.7 million in the comparative quarter. Net earnings were affected by non-cash items such as depletion, depreciation and accretion, unrealized gain or loss on risk management activities, stock-based compensation and future income taxes. These non-cash items represent the majority of the significant difference between funds from operations and net earnings.



NETBACK ANALYSIS

Three Months Ended March 31
2009 2008 % Change
----------------------------------------------------------------------------
Barrels of oil equivalent ($/boe)
Realized sales price 39.77 58.45 (32)
Royalties, net of ARTC 7.30 10.64 (31)
Operating expenses 10.19 9.35 9
Transportation 2.40 2.86 (16)
----------------------------------------------------------------------------
Operating netback 19.88 35.60 (44)
G&A 1.84 1.77 4
Interest 1.57 2.88 (45)
----------------------------------------------------------------------------
Cash netback 16.47 30.95 (47)
Unrealized loss (gain) on
financial contracts (0.92) 5.26 -
Stock-based compensation expense 0.35 0.42 (18)
Depletion, depreciation and
accretion 24.31 27.49 (12)
Future income taxes (reduction) (1.82) (0.88) 107
----------------------------------------------------------------------------
Net earnings (loss) (5.45) (1.34) 307
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Approximately 86 percent of Delphi's production is natural gas and therefore Delphi's cash netbacks are primarily driven by the price received for natural gas.



LIQUIDITY AND CAPITAL RESOURCES

Funding

Three Months Ended
March 31, 2009
----------------------------------------------------------------------------
Sources:
Funds from operations 10,017
Disposition of petroleum and natural gas properties 151
Change in non-cash working capital (8,496)
----------------------------------------------------------------------------
1,672
Uses:
Cash and cash equivalents (7,320)
Capital expenditures 14,092
----------------------------------------------------------------------------
6,772
----------------------------------------------------------------------------
Increase in bank debt 5,100
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the period ended March 31, 2009 Delphi funded its capital program through a combination of funds from operations and an increase in its bank debt.

Share Capital

At March 31, 2009, the Company had 79.1 million common shares outstanding (December 31, 2008 - 79.1 million). The common shares of Delphi trade on the TSX under the symbol DEE. The following table summarizes outstanding share data for the three months ended March 31, 2009.



Three Months Ended
March 31, 2009
----------------------------------------------------------------------------
Weighted Average Common Shares
Basic 79,067
Diluted 79,067
Trading Statistics (1)
High 1.05
Low 0.56
Average daily, volume 269,495
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Trading statistics based on closing price


As at May 5, 2009, the Company had 79.1 million common shares outstanding and 6.8 milllion stock options outstanding.

Bank Debt plus Working Capital Deficiency

At March 31, 2009, the Company had $96.5 million outstanding on its credit facility and a working capital deficiency of $16.7 million for total debt plus working capital deficiency of $113.2 million excluding the financial asset of $2.3 million relating to the unrealized gain on financial commodity contracts and the related current future income tax liability of $0.7 million. Delphi anticipates spending less than projected funds from operations on capital expenditures during 2009.

In the first quarter of 2009, the Company converted $80.0 million of its outstanding long term debt from prime-based loans to bankers' acceptances. The bankers' acceptances have terms ranging from 62 to 182 days and a weighted average effective interest rate of 2.9 percent over the term.

The capital intensive nature of the industry will generally result in the Company having a working capital deficiency. As at May 5, 2009, the Company has a revolving facility for $130.0 million with a syndicate of Canadian chartered banks. The facility is a 364 day committed revolving facility which is available until May 31, 2009, the term-out date and is currently under review by the Company's lenders. The term-out date may be extended for an additional 364 days upon approval by the banks. Following the term-out date, the facilities would become non-revolving for a one year term, after which time the balance outstanding would be due and payable. The credit facility bears interest based on a sliding scale tied to the Company's trailing debt to funds from operations ratio: from a minimum of the bank's prime rate plus 0.5 percent to a maximum of the bank's prime rate plus 2.0 percent or from a minimum of bankers' acceptances plus 1.6 percent to a maximum of bankers' acceptances plus 2.5 percent. In addition to the revolving term facility, the Company has a $10.0 million development facility. The pricing grid on the development facility is 0.75 percent higher than the revolving term facility.

Contractual Obligations

The Company is committed to future minimum payments for natural gas transmission and processing and operating leases on compression equipment. The Company also has a lease for office space in Calgary, Alberta.



The future minimum commitments are as follows:

2009 2010 2011 2012 2013
----------------------------------------------------------------------------
Gathering, processing and
transmission 2,739 4,217 3,897 2,833 1,846
Office and equipment
lease 760 1,023 1,029 775 390
----------------------------------------------------------------------------
Total 3,499 5,240 4,926 3,608 2,236
----------------------------------------------------------------------------
----------------------------------------------------------------------------


GUARANTEES AND OFF-BALANCE SHEET ARRANGEMENTS

Delphi has not entered into any guarantees or off-balance sheet arrangements except for certain lease agreements entered into in the normal course of operations. All leases are operating leases with lease payments charged to operating expenses or general and administrative expenses according to the nature of the lease.

CRITICAL ACCOUNTING ESTIMATES

Delphi's financial statements have been prepared in accordance with Canadian general accepted accounting principles. Certain accounting policies require management to make decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Delphi's management reviews its estimates frequently; however, the emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates. Delphi attempts to mitigate this risk by employing individuals with the appropriate skill set and knowledge to make reasonable estimates, developing internal control systems and comparing past estimates to actual results.

The Company's financial and operating results include estimates of the following:

- Depletion, depreciation and accretion and the ceiling test are based on estimates of crude oil and natural gas reserves;

- Revenues, operating expenses and royalties for which accruals have been recorded for actual revenues and costs which have been earned or incurred but have not yet been received;

- Capital expenditures on projects that are in progress;

- Fair value of derivative contracts;

- Asset retirement obligations including estimates of future costs and the timing of the costs.

NEW ACCOUNTING STANDARDS

International Financial Reporting Standards (IFRS)

In March 2009, the Accounting Standards Board of the Canadian Institute of Chartered Accountants reconfirmed that IFRS will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises. Effective January 1, 2011, the Company will be required to prepare its consolidated financial statements in accordance with IFRS, with appropriate comparative figures for the year ended December 31, 2010.

The Company has developed a high level changeover plan to assess in detail all aspects of the changeover to IFRS, including appropriate changes to accounting policies and financial disclosures, effects on information systems and processes, changes to internal controls over financial reporting and business activities, in order to complete the transition to IFRS by January 1, 2011. Delphi will update its IFRS changeover plan to reflect new and amended accounting standards issued by the International Accounting Standards Board. As IFRS is expected to change prior to 2011, the effect on the Company's consolidated financial statements is not reasonably determinable at this time.

The International Accounting Standards Board (IASB) has issued an exposure draft relating to certain amendments to IFRS 1 which addresses first time adoption of IFRS. The IASB is proposing additional optional exemptions, one of which relates to full cost oil and gas accounting, resulting in a reduced administrative transition from the current Canadian full cost accounting for oil and gas activities to IFRS. The exemption would permit the Company to measure exploration and evaluation assets under IFRS at the carrying amount determined under GAAP at the date of transition to IFRS. In addition, the carrying amount under GAAP of production or development assets could be allocated on a pro rata basis to the underlying assets using either reserve volumes or reserve values at the date of transition. The assets to which this exemption is applied would be required to be tested for impairment at the date of transition under IFRS standards.

CORPORATE GOVERNANCE

Overview

The shareholders' interests are a critical factor in the operations and management of Delphi. The Company is committed to maintaining the highest level of investor confidence in the Company through the application of its corporate governance policies. Delphi's Board of Directors consists of five independent directors and two officers of the Company who meet regularly to discuss matters of strategy and execution of the business plan. See Delphi's Management Information Circular and Annual Information Form for a listing of committees that oversee specific aspects of the Company's operating and financial strategy.

Disclosure Controls and Procedures and Internal Controls over Financial Reporting

Disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the issuer's management, including its President and Chief Executive Officer and Vice President, Finance and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Company's President and Chief Executive Officer and Vice President, Finance and Chief Financial Officer have concluded that the Company's disclosure controls and procedures provide a reasonable level of assurance that information required to be disclosed by the Company is recorded, processed, summarized and reported within the time periods specified.

The Company notes that while it believes the disclosure controls and procedures and internal controls over financial reporting provide a reasonable level of assurance that they are effective, it does not expect that the disclosure controls and procedures and internal controls will prevent all errors and fraud. A control system is designed to provide reasonable, not absolute, assurance that the objectives of the control system are met. There were no changes made to the disclosure controls and procedures or internal controls over financial reporting during the quarter.

2009 OUTLOOK

Corporate Strategy

Delphi emphasizes a full-cycle approach to its business and strives for internally generated development opportunities as a means of enhancing its production base and ultimately creating value for shareholders. Delphi's goal is to become a dominant natural gas developer and explorer focused in North West Alberta and North East British Columbia. The objective is to develop an inventory of opportunities and undeveloped land base from which production and reserves can be added independent of acquisition activity. In that regard, the Company's ability to add production through the drill bit creates a competitive advantage over those competitors that rely on acquisitions to build or maintain their production base. Currently, Delphi has identified over one hundred drilling locations, representing three to five years drilling inventory, in its core areas.

Capital Activities

With the current uncertainty in commodity prices and the economy, Delphi will fund its 2009 capital program from internally generated cash flow from operations. First half capital of approximately $17.0 million should allow the company to reduce debt by the end of the second quarter. Delphi's Board of Directors have approved a capital program ranging between $18.0 to $23.0 million for the second half of 2009, with the objective of preserving the Company's financial flexibility in these uncertain economic times and maintaining the flexibility to pursue and capture strategic growth opportunities attractively priced in this environment.

The capital program for the second half of the year includes the drilling of up to 10 wells with the majority of the capital allocated to the Company's two main areas, Bigstone and Hythe including the drilling of a horizontal well at Hythe utilizing multistage fracturing techniques to enhance production and reserves.

Financial Strategy

The Company is well positioned to endure the current weak economic environment with high quality producing assets, a large inventory of economic projects and a 2009 cash flow stream protected with 52 percent of the Company's current natural gas production hedged at an average price of $7.35 per mcf for the remainder of the year. Maintaining operational and financial flexibility, combined with expanding the Company's long-term growth inventory in a low-cost environment, will be key drivers in the capital spending decision process for the remainder of 2009.

ADDITIONAL INFORMATION

Additional information about Delphi is available on the Canadian Securities Administrators' System for Electronic Distribution and Retrieval (SEDAR) at www.sedar.com, at the Company's website at www.delphienergy.ca or by contacting the Company at Delphi Energy Corp. Suite 300, 500 - 4th Avenue S.W., Calgary, Alberta, T2P 2V6 or by e-mail at info@delphienergy.ca.

Forward-Looking Statements. This management discussion and analysis contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", may", "will", "should", believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.

More particularly and without limitation, this management discussion and analysis contains forward looking statements and information relating to the Company's risk management program, petroleum and natural gas production, future funds from operations, capital programs, commodity prices, costs and debt levels. The forward-looking statements and information are based on certain key expectations and assumptions made by Delphi, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the capital availability to undertake planned activities and the availability and cost of labour and services.

Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect the Company's operations or financial results are included in reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). The forward-looking statements and information contained in this press release are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Basis of Presentation. For the purpose of reporting production information, reserves and calculating unit prices and costs, natural gas volumes have been converted to a barrel of oil equivalent (boe) using six thousand cubic feet equal to one barrel. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with the Canadian Securities Administrators' National Instrument 51-101 when boes are disclosed. Boes may be misleading, particularly if used in isolation.

Non-GAAP Measures. The MD&A contains the terms "funds from operations", "funds from operations per share", "net debt", "cash operating costs" and "netbacks" which are not recognized measures under Canadian generally accepted accounting principles. The Company uses these measures to help evaluate its performance. Management considers netbacks an important measure as it demonstrates its profitability relative to current commodity prices. Management uses funds from operations to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and to repay debt. Funds from operations is a non-GAAP measure and has been defined by the Company as net earnings plus the addback of non-cash items (depletion, depreciation and accretion, stock-based compensation, future income taxes and unrealized gain/(loss) on risk management activities) and excludes the change in non-cash working capital related to operating activities and expenditures on asset retirement obligations and reclamation. The Company also presents funds from operations per share whereby amounts per share are calculated using weighted average shares outstanding consistent with the calculation of earnings per share. Delphi's determination of funds from operations may not be comparable to that reported by other companies nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. The Company has defined net debt as the sum of long term debt plus working capital excluding the current portion of future income taxes and risk management asset/liability. Net debt is used by management to monitor remaining availability under its credit facilities. Cash operating costs have been defined as the sum of operating expenses, transportation expenses, general and administrative expenses and interest costs.



DELPHI ENERGY CORP.
Consolidated Balance Sheets (unaudited)

March 31 December 31
(Stated in thousands of dollars) 2009 2008
----------------------------------------------------------------------------
Assets
Current assets
Cash 6 1,029
Accounts receivable 12,661 14,522
Prepaid expenses and deposits 3,947 2,928
Risk management asset (Note 8) 2,281 1,721
----------------------------------------------------------------------------
18,895 20,200

Property, plant and equipment (Note 4) 344,174 344,338
----------------------------------------------------------------------------
Total assets 363,069 364,538
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities
Current liabilities
Outstanding cheques 6,402 105
Future income taxes 640 501
Accounts payable and accrued liabilities 26,873 36,211
----------------------------------------------------------------------------
33,915 36,817

Long term debt (Note 5) 96,500 91,400
Future income taxes 35,615 33,655
Asset retirement obligations (Note 6) 10,040 9,730
----------------------------------------------------------------------------
176,070 171,602

Shareholders' equity
Share capital (Note 7) 171,887 174,995
Contributed surplus (Note 7) 10,096 9,605
Retained earnings 5,016 8,336
----------------------------------------------------------------------------
Total shareholders' equity 186,999 192,936
----------------------------------------------------------------------------
Total liabilities and shareholders' equity 363,069 364,538
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----------------------------------------------------------------------------

Commitments (Note 9)

See accompanying notes to the consolidated financial statements.


DELPHI ENERGY CORP.
Consolidated Statements of Operations, Comprehensive Loss and Retained
Earnings (unaudited)
For the three months ended March 31


(Stated in thousands of dollars, except per
share amounts) 2009 2008
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales 23,176 32,064
Realized gain on risk management activities
(Note 8) 1,029 148
----------------------------------------------------------------------------
24,205 32,212
Royalties (4,443) (5,862)
Unrealized gain (loss) on risk management
activities (Note 8) 560 (2,901)
----------------------------------------------------------------------------
20,322 23,449

Expenses
Operating 6,204 5,153
Transportation 1,461 1,577
General and administrative 1,122 974
Stock-based compensation (Note 7) 211 232
Interest 958 1,587
Depletion, depreciation and accretion 14,793 15,151
----------------------------------------------------------------------------
24,749 24,674

----------------------------------------------------------------------------
Loss before income taxes (4,427) (1,225)

Income taxes
Future (reduction) (1,107) (486)
----------------------------------------------------------------------------
(1,107) (486)

----------------------------------------------------------------------------
Loss and comprehensive loss for the period (3,320) (739)
Retained earnings, beginning of period 8,336 3,242
----------------------------------------------------------------------------
Retained earnings, end of period 5,016 2,503
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Loss per share (Note 7)
Basic and diluted (0.04) (0.01)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


DELPHI ENERGY CORP.
Consolidated Statements of Cash Flows (unaudited)
For the three months ended March 31

(Stated in thousands of dollars) 2009 2008
----------------------------------------------------------------------------

Cash flow from operating activities
Loss for the period (3,320) (739)
Add non-cash items:
Depletion, depreciation and accretion 14,793 15,151
Stock-based compensation 211 232
Unrealized gain on risk management activities (560) 2,901
Future income taxes (reduction) (1,107) (486)
Change in non-cash working capital (1,504) (8,153)
----------------------------------------------------------------------------
8,513 8,906

Cash flow from financing activities
Exercise of stock options - 378
Increase in long term debt 5,100 7,500
----------------------------------------------------------------------------
5,100 7,878

----------------------------------------------------------------------------
Cash flow available for investing activities 13,613 16,784

Cash flow from (used in) investing activities
Capital expenditures (14,092) (26,498)
Disposition of petroleum and natural gas
properties 151 -
Change in non-cash working capital (6,992) 10,789
----------------------------------------------------------------------------
(20,933) (15,709)

----------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents (7,320) 1,075
Cash and cash equivalents, beginning of
period 924 (4,358)
----------------------------------------------------------------------------
Cash and cash equivalents, end of period (6,396) (3,283)
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----------------------------------------------------------------------------
Cash and cash equivalents is comprised of:
Cash 6 102
Outstanding cheques (6,402) (3,385)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Interest paid 1,757 1,587
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See accompanying notes to the consolidated financial statements.


DELPHI ENERGY CORP.
Notes to the Consolidated Financial Statements
As at and for the periods ended March 31, 2009 and 2008 (unaudited)
(All tabular amounts are stated in thousands of dollars, except per share
amounts)


NOTE 1: DESCRIPTION OF BUSINESS

Delphi Energy Corp. ("the Company" or "Delphi") is incorporated under the Business Corporations Act (Alberta) and is a public company listed on the Toronto Stock Exchange. Delphi is primarily engaged in the exploration for and development and production of petroleum and natural gas from properties located in North West Alberta and North East British Columbia.

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

The unaudited interim consolidated financial statements of Delphi have been prepared by management in accordance with accounting principles generally accepted in Canada and following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2008. The disclosures provided below are incremental to those included with the annual financial statements. The unaudited interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto in the Company's Annual Report for the year ended December 31, 2008. The preparation of financial statements in accordance with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results may differ from these estimates.

Certain comparative figures have been reclassified to conform with the current year's presentation.

NOTE 3: NEW ACCOUNTING STANDARDS

International Financial Reporting Standards

Effective January 1, 2011, the Company will be required to prepare its consolidated financial statements in accordance with International Financial Reporting Standards (IFRS), with appropriate comparative figures for the prior year. The Company is currently assessing the differences between Canadian GAAP and IFRS and the effect on the consolidated financial statements.



NOTE 4: PROPERTY, PLANT AND EQUIPMENT
Accumulated
depletion and Net
As at March 31, 2009 Cost depreciation book value
----------------------------------------------------------------------------
Petroleum and natural gas properties 419,317 180,819 238,498
Production equipment 134,366 28,982 105,384
Furniture, fixtures and office
equipment 891 599 292
----------------------------------------------------------------------------
554,574 210,400 344,174
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Accumulated
depletion and
As at December 31, 2008 Cost depreciation Net book value
----------------------------------------------------------------------------
Petroleum and natural gas properties 406,455 168,124 238,331
Production equipment 132,887 27,150 105,737
Furniture, fixtures and office
equipment 846 576 270
----------------------------------------------------------------------------
540,188 195,850 344,338
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three months ended March 31, 2009, the Company capitalized $1.1 million (March 31, 2008 - $0.6 million) of general and administrative costs directly related to exploration and development activities.

As at March 31, 2009, costs in the amount of $2.5 million (December 31, 2008 - $3.4 million) representing unproved properties were excluded from the depletion calculation and estimated future development costs of $44.9 million (December 31, 2008 - $46.7 million) have been included in costs subject to depletion. All costs of unproved properties have been capitalized. Ultimate recoverability of these costs will be dependent upon finding proved oil and natural gas reserves.

NOTE 5: LONG TERM DEBT

The Company has a revolving facility for $130.0 million with a syndicate of Canadian chartered banks. The facility is a 364 day committed revolving facility until May 31, 2009, the term-out date and is currently under review by the Company's lenders. The term-out date may be extended for a further 364 day period upon approval by the banks. Following the term-out date, the facilities would be available on a non-revolving basis for a one year term. The credit facility bears interest based on a sliding scale tied to the Company's trailing debt to cash flow ratio: from a minimum of the bank's prime rate plus 0.5 percent to a maximum of the bank's prime rate plus 2.0 percent or from a minimum of bankers' acceptances plus 1.6 percent to a maximum of bankers' acceptances plus 2.5 percent.

In the first quarter of 2009, the Company converted $80.0 million of its outstanding long term debt from prime-based loans to bankers' acceptances. The bankers' acceptances have terms ranging from 62 to 182 days and a weighted average effective interest rate of 2.9 percent over the term.

In addition to the revolving term facility, the Company has a $10.0 million development facility with its lenders. The pricing grid on the development facility is 0.75 percent higher than the revolving term facility. As at March 31, 2009, there is no amount drawn under this facility.

The two facilities are secured by a $200.0 million demand floating charge debenture and a general security agreement over all assets of the Company.

NOTE 6: ASSET RETIREMENT OBLIGATIONS

The Company's asset retirement obligations result from working interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations, over the next three to 20 years, is approximately $21.6 million (December 31, 2008 - $21.4 million). A credit-adjusted risk-free rate of 8.0 to 10.0 percent and an inflation rate of 2.5 percent were used to calculate the estimated fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below.

March 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Balance, beginning of period 9,730 7,183
Liabilities incurred 67 271
Liabilities disposed - (83)
Liabilities acquired - 2,021
Liabilities settled - (312)
Accretion expense 243 650
----------------------------------------------------------------------------
Balance, end of period 10,040 9,730
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----------------------------------------------------------------------------


NOTE 7: SHARE CAPITAL

(a) Authorized

An unlimited number of common shares.

An unlimited number of preferred shares issuable in series.



(b) Common shares issued

March 31, 2009 December 31, 2008
Outstanding Outstanding
shares (000's) Amount shares (000's) Amount
----------------------------------------------------------------------------
Balance, beginning of period 79,067 174,995 68,070 148,898
Issue of flow-through common
shares - - 3,530 12,002
Issue of common shares - - 6,316 18,001
Exercise of stock options - - 1,151 1,532
Allocated from contributed
surplus - - - 745
Share issue costs - - - (2,010)
Future tax effect of share
issue costs - - - 585
Tax benefit renounced to
shareholders - (3,108) - (4,758)
----------------------------------------------------------------------------
Balance, end of period 79,067 171,887 79,067 174,995
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----------------------------------------------------------------------------


On July 17, 2008, the Company issued 6.32 million common shares at a price of $2.85 per share and 3.53 million flow-through common shares at $3.40 per share for gross proceeds of $30.0 million.

As at March 31, 2009, the Company has incurred the necessary qualifying exploration expenditures to satisfy the terms of the flow-through common shares issued in 2008. Although the Company believes it has incurred the necessary qualifying expenditures, these amounts may be subject to audit and subsequent interpretation by the Canada Revenue Agency.

(c) Stock options

The Company has established a stock option plan under which it has granted options to acquire common shares to certain officers, directors, employees and key consultants. The plan provides for the granting of options up to ten percent of the issued and outstanding common shares of the Company. Options issued under the plan have a term of five years to expiry and vest over a two-year period starting on the date of the grant. The exercise price of each option equals the five day weighted average of the closing market price of the Company's common shares, immediately preceding the date of the grant. As at March 31, 2009 there were 6.8 million options to purchase shares outstanding, of which 2.3 million are subject to shareholder approval.




The following table summarizes the changes in the number of options
outstanding and the weighted average share prices.

March 31, 2009 December 31, 2008
Weighted Weighted
average average
Outstanding exercise Outstanding exercise
options (000's) price options (000's) price
----------------------------------------------------------------------------
Balance, beginning of period 4,731 1.75 5,481 1.60
Granted 2,077 0.65 615 2.23
Cancelled - - (60) 1.55
Forfeited - - (154) 1.56
Exercised - - (1,151) 1.33
----------------------------------------------------------------------------
Balance, end of period 6,808 1.42 4,731 1.75
----------------------------------------------------------------------------
Exercisable at end of period 3,730 1.52 2,938 1.72
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The following table summarizes information about the stock options
outstanding and exercisable at March 31, 2009.

Options outstanding Options exercisable
Weighted
Weighted average Weighted
average remaining average
Range of Outstanding exercise term Exercisable exercise
exercise price options (000's) price (years) (000's) price
----------------------------------------------------------------------------
$ 0.65 - $1.54 2,177 0.68 4.9 742 0.70
$ 1.55 - $1.72 3,751 1.67 3.6 2,489 1.67
$ 1.73 - $2.15 660 1.80 3.6 325 1.79
$ 2.16 - $3.34 220 3.18 4.2 74 3.18
----------------------------------------------------------------------------
Total 6,808 1.42 4.2 3,730 1.52
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(d) Stock-based compensation

The Company accounts for its stock-based compensation using the fair value method for all stock options. For the three months ended March 31, 2009, Delphi recorded non-cash compensation expense of $0.2 million (March 31, 2008 - $0.3 million). The Company capitalized $0.3 million (March 31, 2008 - $0.3 million) of stock-based compensation directly related to exploration and development activities.

During the three month period ended March 31, 2009, the Company granted 2.1 million options. The fair values of all options granted during the period are estimated at the date of grant using the Black-Scholes option pricing model. The weighted average fair value of options granted during the period was $0.35 per option. The assumptions used in the Black-Scholes model to determine fair value were as follows.



March 31, 2009 2007
----------------------------------------------------------------------------
Risk-free interest rate (%) 1.9 5.0
Expected life (years) 5.0 5.0
Expected volatility (%) 61.7 53.0
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(e) Contributed surplus

The following table outlines the changes in the contributed surplus balance.

March 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Balance, beginning of the period 9,605 8,236
Stock-based compensation expensed 211 994
Stock-based compensation capitalized 280 1,120
Reclassification to common shares on
exercise of stock options - (745)
----------------------------------------------------------------------------
Balance, end of the period 10,096 9,605
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----------------------------------------------------------------------------


(f) Net earnings (loss) per share

Net earnings (loss) per share has been based on the following weighted
average common shares.

For the three months ended March 31

2009 2008
----------------------------------------------------------------------------
Basic 79,067 68,268
Diluted 79,067 68,280
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----------------------------------------------------------------------------


In the first three months of 2009, the stock options were anti-dilutive and therefore excluded from diluted weighted average common shares.

NOTE 8: FINANCIAL INSTRUMENTS

(a) Risk management overview

The Company is exposed to market risks related to the volatility of commodity prices, foreign exchange rates and interest rates. Risk management is ultimately established by the Board of Directors and is implemented and monitored by senior management. The Company maintains an active risk management program as an integral part of its overall financial strategy to mitigate volatility in funds from operations resulting from fluctuating commodity prices. The strategy is designed to take advantage of the upward swings in natural gas prices as a result of the changes in demand/supply fundamentals and/or the movement of significant financial assets invested in the natural gas market as a pure commodity investment.

(b) Fair value of financial assets and liabilities

The Company's financial instruments as at March 31, 2009 include cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, long-term debt and risk management asset.

The fair value of financial assets and liabilities that are included in the balance sheet approximate their carrying amounts due to bank debt being at a floating interest rate and all other financial assets and liabilities having a short term maturity.

The fair value of derivative contracts is determined by calculating the present value of the difference between the contracted price and the related published forward price expectations at the balance sheet date, using the remaining contracted volumes.

(c) Market risk

Market risk is the risk that future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk is comprised of foreign currency exchange rate risk, interest rate risk and commodity price risk. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns.

The Company utilizes both financial derivatives and physical delivery contracts to manage market risks.

Foreign currency exchange rate risk

Foreign currency exchange rate risk is the risk that future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company's petroleum and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for petroleum and natural gas are affected by changes in the exchange rate between the Canadian and United States dollar. The exchange rate could affect the values of certain contracts, however, this indirect influence cannot be accurately quantified. The Company had no foreign exchange rate swap or related financial contracts in place as at March 31, 2009.

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in the market interest rates. The Company is exposed to interest rate risk to the extent that bank debt is at a floating rate of interest. The Company had no interest rate swap or related financial contracts in place as at March 31, 2009. If interest rates had been 100 basis points lower with all other variables held constant, net earnings for the three months ended March 31, 2009 would have been $0.1 million (2008 - $0.2 million) higher, due to lower interest expense.

Commodity price risk

Commodity price risk is the risk that the future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are affected not only by the relationship between the Canadian and United States dollar, as outlined above, but also world economic events that dictate the levels of supply and demand. The Company has a commodity price risk management program in place whereby the commodity price associated with a portion of its future production is fixed. The Company sells forward a portion of its future production by entering into a combination of fixed price sale contracts with customers and commodity swap agreements with financial counterparties. The fair values of the forward contracts are subject to market risk from fluctuating commodity prices and foreign exchange rates. The Company's policy is to enter into commodity contracts to a maximum of 40 - 50 percent of current production volumes.

As at March 31, 2009, the Company had the following financial derivative sales contracts which were recorded on the balance sheet at fair value of $2.3 million (December 31, 2008 - $1.7 million) with changes in fair value included in unrealized gain on risk management activities in the statement of earnings.



Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
February 2009 -
December 2009(i) Natural Gas Financial 3,500 GJ/d $6.00 Put
January 2010 -
December 2010(i) Natural Gas Financial 3,500 GJ/d $7.40 Call
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) The Company has acquired a natural gas put contract at $6.00 per
gigajoule on 3,500 gigajoules per day for the period February 1, 2009
through December 31, 2009. This put was paid for with the sale of a
natural gas call on 3,500 gigajoules per day at a price of $7.40 per
gigajoule for the period January 1, 2010 through December 31, 2010.


The Company has both United States and Canadian dollar physical sales contracts. The Canadian dollar physical sales contracts were entered into and continue to be held for the purpose of delivery of non-financial items as executory contracts and have not been recorded at fair value. The fair value of the United States dollar physical sales contracts are recorded on the balance sheet with changes in fair value included in unrealized gain or loss on risk management activities in the statement of earnings. As at March 31, 2009, the Company had the following physical sales contracts.



Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
April 2009 - Natural
October 2009 Gas Physical 1,000 GJ/d $7.08 fixed

April 2009 - Natural $8.25 floor/$10.00
October 2009 Gas Physical 2,000 GJ/d ceiling

April 2009 - Natural
October 2009 Gas Physical 1,000 mmbtu/d U.S. $8.18 fixed

April 2009 - Natural
October 2009 Gas Physical 2,000 GJ/d $8.59 fixed

April 2009 - Natural $6.70 floor plus 50%
October 2009 Gas Physical 2,000 GJ/d greater than $6.70

April 2009 - Natural
March 2010 Gas Physical 3,000 GJ/d $7.52 fixed

April 2009 - Natural $6.80 floor plus 50%
March 2010 Gas Physical 2,000 GJ/d greater than $6.80

November 2009 - Natural Physical $7.65 floor plus 50%
March 2010 Gas 2,000 GJ/d greater than $7.65

November 2009 - Natural $7.75 floor/$8.70
March 2010 Gas Physical 2,000 GJ/d ceiling

November 2009 - Natural $7.26 floor plus 50%
March 2010 Gas Physical 2,000 GJ/d greater than $7.26

April 2010 - Natural $6.25 floor/$7.47
December 2010 Gas Physical 3,000 GJ/d ceiling

April 2010 - Natural $5.93 floor plus 50%
December 2010 Gas Physical 4,000 GJ/d greater than $5.93

March 2009 - Natural
December 2009(ii) Gas Physical 3,500 GJ/d $6.00 Put

January 2010 - Natural
December 2010(ii) Gas Physical 3,500 GJ/d $7.15 Call
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(ii) The Company has acquired a natural gas put contract at $6.00 per
gigajoule on 3,500 gigajoules per day for the period March 1, 2009
through December 31, 2009. This put was paid for with the sale of a
natural gas call on 3,500 gigajoules per day at a price of $7.15 per
gigajoule for the period January 1, 2010 through December 31, 2010.


For the three months ended March 31, 2009, the Canadian dollar physical contracts resulted in settlement gains of $3.0 million (2008 - $1.2 million) that have been included in petroleum and natural gas sales. For the three months ended March 31, 2009, the financial contracts and U.S. dollar based physical contracts resulted in gains of $1.0 million (2008 - gains of $0.1 million) that have been included in the statement of earnings as a realized gain on risk management activities. As at March 31, 2009, if natural gas prices had been +/- $0.10 per mcf, with all other variables held constant, the net change in the unrealized gain or loss on risk management activities in the statement of earnings for the year would have been +/- $0.1 million (2008 - $0.1 million).

d) Credit risk

Credit risk represents the financial loss to the Company if counterparties to a financial instrument fail to meet their contractual obligations and arise principally from the Company's receivables from joint interest partners. All of the Company's accounts receivable are with customers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. With respect to counterparties to financial instruments, the Company partially mitigates associated credit risk by limiting transactions to counterparties with investment grade credit ratings.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. The Company's policy to mitigate credit risk associated with these balances is to establish marketing relationships with large purchasers. The Company attempts to mitigate the risk from joint interest receivables by obtaining partner approval of significant capital expenditures prior to expenditure. However, partners are exposed to various industry and market risks that could result in non-collection. The Company does not typically obtain collateral from natural gas marketers or joint interest partners; however, the Company does have the ability to request pre-payment of certain major capital expenditures and withhold production from joint interest partners in the event of non-payment of amounts owing.

The carrying amount of cash and accounts receivable represents the maximum credit exposure. The Company does not consider an allowance for doubtful accounts is required as at March 31, 2009 and no bad debt expense was recorded during the quarter.



As at March 31, 2009 the Company's aged receivables are as follows.

March 31, 2009
----------------------------------------------------------------------------
Current (less than 30 days) 9,021
Past due (31-90 days) 1,762
Past due (more than 90 days) 1,878
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Total 12,661
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----------------------------------------------------------------------------


(e) Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company's approach to managing liquidity risk is to ensure, to the extent possible, that it will have sufficient cash resources to meet its liabilities when they become due. The Company actively monitors the costs of its operations and capital expenditure program by preparing an annual budget, formally approved by the Board of Directors. On a monthly basis, internal reporting of actual results is compared to the budget in order to modify budget assumptions, if necessary, to ensure liquidity is maintained.

The Company requires sufficient cash to fund its operating costs and capital program that are designed to maintain or increase production and develop reserves, to acquire petroleum and natural gas assets and to satisfy debt obligations. The majority of capital spent will be funded through cash flow from operating activities. The Company enters into risk management contracts designed to improve risk-adjusted returns and to ensure adequate cash flow to fund the Company's capital program and maintain liquidity. The Company uses a combination of both financial and physical commodity price contracts. Contracts are initiated within the guidelines of the Company's risk management program and are not entered into for speculative purposes. The Company also has a 364 day revolving credit facility with a syndicate of Canadian chartered banks with a one year term-out provision.



The following are the contractual maturities of financial liabilities as at
March 31, 2009.

less than 1 - 2 3 - 5
Financial liabilities 1 Year Years Years Thereafter
----------------------------------------------------------------------------
Outstanding cheques 6,402 - - -
Accounts payable and accrued
liabilities 26,873 - - -
Long term debt - principal - 96,500 - -
----------------------------------------------------------------------------
Total 33,275 96,500 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NOTE 9: COMMITMENTS

The Company is committed to future minimum payments for natural gas transmission and processing, operating leases on compression equipment and office space. Payments required under these commitments for each of the next five years are: 2009-$3.5 million; 2010-$5.2 million; 2011-$4.9 million; 2012-$3.6 million; 2013-$2.2 million.

Contact Information

  • Delphi Energy Corp.
    David J. Reid
    President & CEO
    (403) 265-6171
    or
    Delphi Energy Corp.
    Brian Kohlhammer
    V.P. Finance & CFO
    (403) 265-6171
    or
    Delphi Energy Corp.
    300, 500 - 4 Avenue S.W.
    Calgary, Alberta T2P 2V6
    (403) 265-6207 (FAX)
    Email: info@delphienergy.ca
    Website: www.delphienergy.ca