Delphi Energy Corp.
TSX : DEE

Delphi Energy Corp.

May 05, 2010 18:03 ET

Delphi Energy Reports Strong Financial and Operational Results for First Quarter 2010

CALGARY, ALBERTA--(Marketwire - May 5, 2010) - Delphi Energy Corp. ("Delphi" or the "Company") (TSX:DEE) is pleased to announce its financial and operational results for the quarter ended March 31, 2010.

First Quarter 2010 Highlights

- achieved record quarterly production in the first quarter of 2010 with average daily volumes of 7,645 barrels of oil equivalent per day (boe/d), an increase of 13 percent compared to the first quarter of 2009 and up 11 percent from the fourth quarter of 2009;

- generated funds from operations (cash flow) of $15.2 million, an increase of 51 percent from the comparative quarter of 2009;

- generated net earnings of $3.3 million compared to a net loss of $3.3 million in first quarter of 2009, partly due to a 17 percent decrease in the depletion and depreciation rate to $19.85 per boe resulting from capital efficient proved reserve additions;

- increased oil production by 57 percent, changing the production mix to approximately 16 percent crude oil and natural gas liquids in the first quarter of 2010, contributing to a cash netback of $22.04 per boe, 34 percent greater than the first quarter of 2009;

- reduced operating costs by 15 percent to approximately $8.71 per boe in the first quarter of 2010 from $10.19 per boe in the first quarter of 2009;

- realized $2.9 million in hedging gains on commodity contracts compared to $4.0 million in hedging gains in the first quarter of 2009, providing stability to cash flow and the ability to pursue the Company's planned capital program;

- drilled 16 (10.7 net) wells with an overall success rate of 94 percent; and

- increased the Company's total undeveloped land holdings by 24 percent to 213,000 net acres as compared to December 31, 2009.



Operational Highlights

Three Months Ended March 31
Production 2010 2009 % Change
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Natural gas (mcf/d) 38,349 34,813 10
Crude oil (bbl/d) 745 475 57
Natural gas liquids (bbl/d) 508 485 5
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Total (boe/d) 7,645 6,762 13
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Financial Highlights ($ thousands except per unit amounts)

Three Months Ended March 31
2010 2009 % Change
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Petroleum and natural gas sales 29,519 24,205 22
Per boe 42.91 39.77 8
Funds from operations 15,157 10,017 51
Per boe 22.04 16.47 34
Per share - Basic 0.15 0.13 15
Per share - Diluted 0.15 0.13 15
Net earnings (loss) 3,260 (3,320) -
Per boe 4.75 (5.45) -
Per share - Basic 0.03 (0.04) -
Per share - Diluted 0.03 (0.04) -
Capital invested 35,504 14,092 152
Disposition of properties - (151) (100)
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Net capital invested 35,504 13,941 155
Acquisition of properties 692 - 100
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Total capital invested 36,196 13,941 160
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March 31, December 31,
2010 2009 % Change
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Debt plus working capital
deficiency (1) 113,239 92,538 22
Total assets 396,444 361,968 10
Shares outstanding (000's)
Basic 101,455 101,166 -
Diluted 108,704 108,594 -
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(1) excludes risk management asset/liability and the related current future
income taxes.


MESSAGE TO SHAREHOLDERS

2010 has already been a very active year with a field capital program in the first quarter of $35.5 million, exceeding the full year 2009 field capital program. The successful winter program has resulted in 11 percent production growth over the fourth quarter of 2009, with approximately 800 to 1,000 boe/d of additional volumes to come on-stream in the second and third quarters of 2010.

Production during the first quarter of 2010 averaged 7,645 boe/d, an increase of 13 percent compared to 6,762 boe/d in the first quarter of 2009. The increased light oil production at Hythe and Bigstone changed the production mix in the quarter to 16 percent liquids (84 percent natural gas) from 14 percent liquids (86 percent natural gas) in the first quarter of 2009. The change in production mix to higher netback oil and NGLs contributed to first quarter cash flow.

Delphi's natural gas production continues to receive a premium to AECO pricing due to marketing arrangements, heating content and natural gas hedges. In the first quarter of 2010, the premium for heating content and marketing arrangements was $0.47 per mcf. Approximately 48 percent of the Company's natural gas production was hedged at an average price of $6.84 per mcf in the first quarter, resulting in a gain on natural gas contracts of $2.9 million. These pricing premiums resulted in a realized natural gas price of $6.26 per mcf representing a premium of 26 percent to average AECO pricing.

Cash flow in the first quarter of 2010 was $15.2 million or $0.15 per basic share, compared to $10.0 million or $0.13 per basic share in the first quarter of 2009. Cash flow was 51 percent higher as a result of higher production volumes, higher crude oil prices, lower royalties and lower operating costs.

Delphi's financial position continues to remain strong at the end of the first quarter of 2010 relative to the significant growth in production and first quarter reserve additions. At March 31, 2010, the Company had net debt of $113.2 million on total credit facilities of $125.0 million after a very busy first quarter capital program. On a first quarter annualized funds from operations basis, Delphi's net debt to cash flow ratio was 1.9:1. As in prior years, Delphi anticipates a reduction in net debt through the second quarter as cash flow is expected to be greater than the capital program due to spring break-up. Net debt includes bank debt plus working capital deficiency excluding the risk management asset/liability and the related current future income taxes. The Company's credit facilities are currently under annual review by its lenders. Based on the growth in reserves across all reserve categories in 2009 and the very successful capital program in the first quarter of 2010, we expect an increase to the credit facilities of $5.0 to $10.0 million, resulting in total credit facilities of $130.0 to $135.0 million.

We believe our fundamental strategies will continue to provide the Company with a competitive advantage.

- We continue to focus the technical and operational expertise of our staff on synergistic play-types within our core areas mitigating exploration and operational risks while driving down capital on-stream costs and maximizing reserve additions.

- The continued application of technological advancements throughout 2010 and beyond is unlocking an even larger scale low-cost growth platform for the Company than previously envisioned.

- We maintain direct control over our core assets, operating over 85 percent of our production and 95 percent of our capital programs.

- The large contiguous land positions complete with strategic infrastructure in each of our core areas provides repeatable and scalable project inventory with capital and production cost structure advantages.

- Natural gas price volatility and weakness continues to be successfully mitigated with an active hedging program maintaining a forward looking 12 to 24 month hedge position.

- Increasing Delphi's light oil and natural gas liquids production as a result of greater capital spending towards light oil exploration and development on Company lands within three of our core areas.

- Maintaining financial stability and strength through the use of internally generated cash flow for the capital program to ensure prudent debt to cash flow and debt to equity ratios.

On March 16, 2010, it was announced that Mr. David Sandmeyer and Mr. Stephen Mulherin had joined the Board of Directors of Delphi and that Mr. Mulherin would eventually be appointed to the Audit & Reserves Committee to fill the vacancy, as an independent director, created as a result of the resignation of a director in 2009. In the meantime, Mr. David Reid, President & CEO of Delphi, has temporarily held a position on the Audit & Reserves Committee.

The Board of Directors have recently divided the Audit & Reserves Committee into two committees and reconstituted the committees of the Board in the following manner:

Audit Committee - Mr. Stephen Mulherin - Chairman, Mr. Lamont Tolley and Mr. Andrew Osis

Reserves Committee - Mr. David Sandmeyer - Chairman, Mr. Lamont Tolley and Mr. Robert Lehodey

Corporate Governance & Compensation Committee - Mr. Robert Lehodey - Chairman and Mr. Harry Campbell

Operations

Over the past several months the Company has provided several operational updates on its winter drilling program. Current field operations are focused on the final tie-in and commissioning of the remaining wells drilled and completed in the first quarter of 2010.

The Company's first Falher horizontal well (1.0 net) at Hythe has been brought on-stream at a restricted production rate of approximately 4,000 mcf/d while the remaining frac load fluid is recovered. The well was drilled with a 1,200 metre horizontal leg and then completed utilizing a ten stage fracture stimulation program. During a 48 hour post frac clean-up flow test, the production rate was held constant at 5,300 mcf/d with a final flowing casing pressure of 765 pounds per square inch. Delphi controls approximately 45 gross sections (26 net) of prospective Falher acreage in the Hythe area.

At Wapiti/Gold Creek, Delphi drilled and completed three vertical wells (2.1 net) during the first quarter. In total, the three wells had a combined production test rate of 9,800 mcf/d with an average natural gas liquids ratio of approximately 85 bbls/mmcf. The first well (0.60 net), completed in the Nikanassin and two additional uphole zones, has recently been placed on production through existing infrastructure and now has an initial seven day restricted production rate of 1,800 mcf/d and 110 bbls/d of NGLs or 365 boe/d (220 boe/d net). The highlight of the three well program is the third well (0.84 net) which was completed in a single Nikanassin interval and had a 48 hour test rate of 4,500 mcf/d with a second Nikanassin interval scheduled to be completed after spring break-up. The Company continues to successfully advance the Nikanassin resource play in the Wapiti/Gold Creek and Hythe areas where it has an undeveloped land position totaling approximately 166 gross sections (113 net) and has regulatory approval to drill up to four wells per section. Delphi will commence construction of a thirteen kilometre pipeline out of the area to accommodate this new production and increase the take-away capacity for future development in the immediate area. The new pipeline will connect to existing infrastructure and deep-cut processing facilities where the Company already has an ownership interest. The remaining two wells are expected to commence production late in the second quarter and reach full production capability early in the third quarter upon completion of the new pipeline.

Delphi also added to its future growth potential with the acquisition of 108 gross sections (79 net) of Duvernay shale rights at attractive entry costs targeting natural gas and/or light oil. The Company anticipates a two to three year initial development timeline for this potential large scale development and will leverage off industry expertise and technology progression. Delphi's total inventory of undeveloped land has increased to approximately 213,000 net acres, up 24 percent from December 31, 2009.

Outlook

The capital program has resulted in record production levels and has successfully advanced numerous development projects, further increasing the Company's drill-ready inventory. Delphi continues to be well positioned for long term growth even in a low natural gas price environment. The Company's recycle ratio will continue to be a reliable measure of economic success with cost structure, commodity mix and reserve life being key drivers in yielding higher netbacks and lower on-stream capital costs on a per unit basis.

The Company expects to spend an estimated $60.0 to $65.0 million in 2010, with field capital directed towards drilling opportunities in the Bigstone, Hythe and Wapiti/Gold Creek core areas. The planned capital program, funded from cash flow, is now expected to result in average 2010 production volumes of 7,700 to 8,200 boe/d.

We are forecasting moderate improvement in natural gas prices through the second half of 2010 and into 2011. Delphi is assuming 2010 AECO natural gas prices will average between Cdn $4.50 and $5.50 per mcf for forecast purposes and has successfully mitigated downside commodity price risk with an active natural gas hedging program. During 2010, the Company is again hedged with approximately 54 percent of its natural gas production protected at an average floor price of $6.05 per mcf for the remainder of the year. This represents a 46 percent premium to the 2010 strip price of $4.14 per mcf. In addition, we have 200 bbls/d of light oil production hedged at approximately current market prices. The slightly higher production guidance offset by lower natural gas prices and reduced royalty rates is expected to still result in cash flow for 2010 of $60.0 to $65.0 million.

Bank debt including working capital is estimated to be between $95.0 million and $100.0 million at December 31, 2010 resulting in a debt to cash flow ratio of approximately 1.5:1.

On behalf of the Board of Directors and all the employees of Delphi, we would like to thank our shareholders for their continued support as we remain focussed on sustainable, capital efficient growth of the Company's production and reserve base while maintaining the financial strength and flexibility to take advantage of strategic opportunities.

CONFERENCE CALL

A conference call is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Thursday, May 6, 2010. The conference call number is 1-800-952-4972 or 416-695-7848. 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 13, 2010. To access the replay, dial 1-800-408-3053 or 416-695-5800. The passcode is 8458868. Delphi's first quarter 2010 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 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" 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.

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, 2010 and 2009 and should be read in conjunction with the audited consolidated financial statements and accompanying notes for the years ended December 31, 2009 and 2008. The discussion and analysis has been prepared as of May 3, 2010.

DELPHI'S BUSINESS

What is the nature of Delphi's business and where are its operations?

Delphi Energy Corp. is a publicly-traded company, listed on the Toronto Stock Exchange, primarily engaged in the acquisition, exploration for and development and production of crude oil, natural gas and natural gas liquids from properties located in Western Canada. Delphi's operations are principally concentrated in North West Alberta, representing 76 percent of its production in 2009 and growing to 85 percent in the first three months of 2010. The Company has four primary core areas in the deep basin of North West Alberta located at Bigstone, Hythe, Wapiti/Gold Creek and Tower Creek.

OPERATIONAL AND FINANCIAL HIGHLIGHTS

What were the highlights of Delphi's operational and financial results in the first quarter of 2010?

Even though Canadian natural gas prices remained weak during the quarter, Delphi Energy Corp. enjoyed a very successful first quarter of 2010, including a significant capital program, increasing both production and reserves toward continued growth in long-term value for its shareholders.

The accomplishments of the first quarter of 2010 are highlighted as follows:

- achieved record quarterly production in the first quarter of 2010 with average daily volumes of 7,645 barrels of oil equivalent per day (boe/d), an increase of 13 percent compared to the first quarter of 2009 and up 11 percent from the fourth quarter of 2009;

- increased oil production by 57 percent, changing the production mix to approximately 16 percent crude oil and natural gas liquids in the first quarter of 2010, contributing to a 34 percent increase in cash flow netback compared to the first quarter of 2009;

- generated funds from operations (cash flow) of $15.2 million, an increase of 51 percent from the comparative quarter of 2009;

- reduced operating costs by 15 percent to approximately $8.71 per boe in the first quarter of 2010 from $10.19 per boe in the first quarter of 2009;

- realized $2.9 million in hedging gains on natural gas commodity contracts, providing stability to cash flow and providing the ability to pursue the Company's planned capital program;

- drilled 16 (10.7 net) wells with an overall success rate of 94 percent;

- increased the Company's total undeveloped land holdings by 24 percent to 213,000 net acres as compared to December 31, 2009.

Cash flow in the first quarter of 2010 was $15.2 million or $0.15 per basic share, compared to $10.0 million or $0.13 per basic share in the first quarter of 2009. Cash flow was 51 percent higher as a result of higher production volumes, higher crude oil prices, lower royalties and lower operating costs.

Delphi's financial position continues to remain strong at the end of the first quarter of 2010 relative to the significant growth in production and first quarter reserve additions. At March 31, 2010, the Company had net debt of $113.2 million on total credit facilities of $125.0 million after a very busy first quarter capital program. On a first quarter annualized funds from operations basis, Delphi's net debt to cash flow ratio was 1.9:1. As in prior years, Delphi anticipates a reduction in net debt through the second quarter as cash flow is expected to be greater than the capital program due to spring break-up. Net debt includes bank debt plus working capital deficiency excluding the risk management asset/liability and the related current future income taxes. The Company's credit facilities are currently under annual review by its lenders. Based on the growth in reserves across all categories in 2009 and the very successful capital program in the first quarter of 2010, we expect an increase to the credit facilities of $5.0 to $10.0 million, resulting in total credit facilities of $130.0 to $135.0 million.

BUSINESS ENVIRONMENT

How has the benchmark pricing of Delphi's production and economic parameters changed from the previous year?

The Company is exposed to the volatility in commodity price markets and the change in the foreign exchange rate between the Canadian and United States dollar for pricing of all its production volumes. The table below outlines the changes in the various benchmark commodity prices and economic parameters which affect the prices received for the Company's production.



Benchmark Prices and Economic Parameters

Three Months Ended March 31
2010 2009 % Change
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Natural Gas
NYMEX (US $/mmbtu) 5.14 4.57 12
AECO (CDN $/mcf) 4.96 4.95 -
Crude Oil
West Texas Intermediate (US $/bbl) 78.79 43.08 83
Edmonton Light (CDN $/bbl) 80.07 49.65 61
Foreign Exchange
Canadian to US dollar 1.04 1.24 (16)
US to Canadian dollar 0.96 0.80 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 over the past several years have been influenced more by North American supply and demand than global natural gas fundamentals. The increase in capacity of natural gas liquefaction and regasification facilities for LNG deliveries to the U.S. can influence North America natural gas prices but primarily in periods of short supply in the U.S.; not over supply as has been the situation the past several years.

In January, 2010, natural gas prices were range bound between Cdn $5.25 and $5.75 per mcf for AECO in anticipation of normal withdrawals of natural gas from storage to meet winter heating demand. In late January, however, natural gas prices began to decrease and continued to do so through the remainder of the quarter as natural gas drilling activity was increasing and the primary geographical areas for natural gas demand during the winter began experiencing above average temperatures. In addition, industrial demand continued to be reduced due to the current economic slowdown. Canadian natural gas prices in the first quarter varied from a high of Cdn $5.88 per mcf to a low of Cdn $3.60 per mcf. For the quarter, the average price for AECO was Cdn $4.96 per mcf, $0.01 per mcf more than the average for the same quarter in 2009.

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 Cdn/US dollar exchange rate. The fundamental supply/demand equation for crude oil is more balanced on a daily basis than natural gas due to consistent demand for crude oil of approximately 85 million barrels per day to meet the global requirement for energy.

Through the first quarter of 2010, the price for crude oil traded between U.S. $75.00 and U.S. $85.00 per barrel as the global demand for oil continued to stabilize around the world. The U.S. based price for crude oil was also affected by the decline in the value of the U.S. dollar compared to the currency of most of its major trading partners. In the first quarter of 2010, WTI averaged U.S. $78.79 per barrel, 83 percent higher than the same quarter of the previous year.

In 2010 so far, the general trend for the value of the Canadian dollar against its U.S. counterpart was that of a stronger Canadian dollar. As a producer of crude oil, a stronger Canadian dollar has a negative effect on the price received for production. The Cdn/US exchange rate varied from $1.07 to $1.03 in the quarter. In the first quarter of 2010, Canadian crude oil prices averaged $80.07 per barrel compared to $49.65 per barrel in the first quarter of 2009, a 61 percent increase over the comparative quarter.

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 2010 was $7.79 per barrel compared to $8.25 per barrel in 2009. The decrease in the average differential and higher light oil prices resulted in Bow River crude prices averaging $70.92 per barrel in the first quarter of 2010 compared to $35.60 per barrel in the comparative quarter of 2009.

What does the Company expect in 2010 as it relates to these external factors?

For forecasting purposes, Delphi continues to expect a challenging natural gas market for 2010 as the industrial demand in the United States returns at a slow pace and the U.S. rig count increases, particularly horizontal drilling into the shale gas plays. The Company currently anticipates AECO will average between Cdn $4.50 and $5.50 per mcf in 2010.

While crude oil suffers from a similar concern of oversupply in the short term, the demand for crude oil is still relatively strong as the world's largest source of energy required on a daily basis. Delphi anticipates WTI to average between U.S. $70.00 and $80.00 per barrel for 2010.

The strength or weakness of the Canadian dollar versus the U.S. dollar will largely reflect the global demand for raw materials, particularly metals, minerals and crude oil. The financial markets tolerance for risk and need for financial security in the form of holding U.S dollars will also have a significant effect on the value of the Canadian dollar against the U.S. dollar. Delphi believes the Canadian dollar will remain quite strong in 2010 as global economies recover from the recent slowdown. The Canadian dollar is expected to trade in the $0.95 to $1.05 range against the U.S. dollar.

Delphi continues to monitor the variables affecting the price of natural gas and crude oil in order to ensure its capital program is in line with expected funds from operations.

FINANCIAL STRATEGY

From a financial point of view, what strategies does the Company employ to achieve its results and meet forecast expectations?

The Company maintains an active risk management program as an integral part of its overall financial strategy to mitigate volatility in cash flow resulting from fluctuating commodity prices. Delphi's risk management program consists of fixed price contracts, costless collars, participating swaps and puts and calls which provide downside protection. Costless collars, participating swaps and puts also provide the opportunity to share in the upside if market prices increase above the floor price. 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 54 percent of its before-royalty natural gas production at a predominantly AECO based average floor price of $6.05 per mcf for the remainder of 2010. This compares to the forward strip commodity price for AECO of $4.30 per mcf for the remainder of 2010 as of April 28, 2010. The following natural gas hedges are in place to support the Company's cash flow.



Apr-Oct Nov-Mar Apr - Oct
2010 2010/11 2011
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Production hedged (mmcf/d) 20.9 11.2 2.0
Percentage of natural gas
production (i) 58% 31% 5%
Price floor (Cdn $/mcf) $6.00 $6.23 $5.97
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(i) based on 36 mmcf/d


The fair value of outstanding contracts is estimated to be approximately $12.8 million as of March 31, 2010.

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 operating netbacks per boe through the risk management program, production mix 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 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.

As a result of the significant difference in netbacks between crude oil and natural gas, the Company's capital program will continue to be geared more towards oil and liquids-rich natural gas opportunities. By altering the Company's production mix, there is greater certainty of achieving the Company's cash flow expectations due to the higher netback crude oil and liquids production.

The net capital expenditure program in the field will continue to approximate forecast cash flow. 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 cash flow growth resulting in a lower net debt to funds from operations ratio. The Company continues to be focused on achieving its internal target range for this ratio of 1.5 times. In a low price environment, the Company's objective would be to reduce or at least not increase the net debt balance by undertaking a capital program within cash flow.

SELECTED INFORMATION

Over the past two years, how has Delphi performed and what significant factors contributed to the results?

Over the last eight quarters production has grown from 6,202 boe/d to 7,645 boe/d. Production for the last eight quarters reflects the following events. In 2008, the combination of a successful winter and summer capital program and the production increase from the Peace River Arch acquisition resulted in continued production growth quarter over quarter. In 2009, the Company changed its product focus due to the commodity price environment. In the first six months of 2009, production growth was achieved with drilling success at Bigstone and Hythe, Alberta, primarily focused on natural gas opportunities. With crude oil and natural gas prices going in opposite directions through 2009, the capital program in the second half of 2009 was geared toward drilling for crude oil while acquiring strategic natural gas properties and infrastructure. The Company completed four natural gas property and infrastructure acquisitions in the deep basin of North West Alberta in the latter half of 2009. With a successful winter drilling program, first quarter 2010 production volumes of 7,645 boe per day is record quarterly production for the Company.

Over the past two years, the changes in revenue and cash flow from quarter to quarter primarily reflect the production volumes achieved and the volatility of commodity prices over the past two years with the second quarter of 2008 experiencing peak prices for both crude oil and natural gas.

Natural gas prices over the past two years have generally reflected the cyclical nature of demand. With higher prices in the winter months, reflecting demand for heating and with lower prices 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 and industrial demand due to the economic crisis caused natural gas prices to decrease further as a result of concerns over excess supply relative to demand. The average spot price for AECO in 2009 was $3.96 per mcf, the lowest average price in 10 years. Crude oil prices had recovered to over U.S. $80.00 per barrel by the end of 2009 from a low earlier in the year of U.S. $33.98 per barrel. In the first quarter of 2010, crude oil averaged U.S. $78.79 which was an 83 percent increase over the comparative period in 2009.

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.

Net earnings of the Company are primarily driven by the difference between the cash flow netback realized per boe of production versus the Company's depletion, depreciation and amortization (DD&A) rate of $20.21 per boe. The Company continues to reduce its DD&A rate by finding and developing reserves at a cost less than the average DD&A rate. Overall F&D costs of $12.06 per proved boe in 2009 contributed to reduce the overall DD&A rate of the Company.

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



Mar. 31 Dec. 31 Sept. 30 Jun. 30
2010 2009 2009 2009
----------------------------------------------------------------------------
Production
Natural gas (mcf/d) 38,349 34,626 33,628 35,641
Oil (bbl/d) 745 630 624 371
Natural gas liquids (bbl/d) 508 487 544 498
----------------------------------------------------------------------------
Barrels of oil equivalent (boe/d) 7,645 6,888 6,773 6,809
Financial
($ thousands except per unit
amounts)
Petroleum and natural gas revenue 29,519 26,297 24,433 23,229
Funds from operations (cash flow) 15,157 14,218 12,635 12,371
Per share - basic 0.15 0.14 0.16 0.16
Per share - diluted 0.15 0.14 0.16 0.16
Net earnings (loss) 3,260 1,386 (3,278) (2,817)
Per share - basic 0.03 0.02 (0.04) (0.04)
Per share - diluted 0.03 0.02 (0.04) (0.04)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Mar. 31 Dec. 31 Sept. 30 Jun. 30
2009 2008 2008 2008
----------------------------------------------------------------------------
Production
Natural gas (mcf/d) 34,813 35,545 33,691 31,898
Oil (bbl/d) 475 431 372 368
Natural gas liquids (bbl/d) 485 353 421 517
----------------------------------------------------------------------------
Barrels of oil equivalent (boe/d) 6,762 6,708 6,409 6,202
Financial
($ thousands except per unit
amounts)
Petroleum and natural gas revenue 24,205 30,160 34,461 38,569
Funds from operations (cash flow) 10,017 13,473 18,160 19,965
Per share - basic 0.13 0.18 0.24 0.29
Per share - diluted 0.13 0.18 0.23 0.28
Net earnings (loss) (3,320) (959) 6,743 49
Per share - basic (0.04) (0.01) 0.09 -
Per share - diluted (0.04) (0.01) 0.09 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On annual basis, how has Delphi performed?

The decrease in revenue and net earnings from 2008 to 2009 was primarily due to the significant drop in natural gas prices. The increase in revenue and net earnings from 2007 to 2008 was due to a combination of higher production volumes and much higher commodity prices.



2009 2008 2007
----------------------------------------------------------------------------
Revenue 98,164 135,402 97,933
Net earnings/(loss) (8,029) 5,094 (10,472)
Total assets 361,698 364,538 311,740
Bank debt plus working capital 92,538 109,237 100,658
----------------------------------------------------------------------------
----------------------------------------------------------------------------


DRILLING OPERATIONS

How active was Delphi in its drilling program in the first quarter and where was the drilling focused?

The Company had a successful first quarter of 2010, drilling 16 gross (10.7 net) wells with a success rate of 94 percent. The drilling was primarily focused on the core properties of Bigstone, Wapiti/Gold Creek and Hythe in North West Alberta.



Three Months Ended March 31, 2010
Gross Net
----------------------------------------------------------------------------
Natural gas wells 9.0 6.5
Oil wells 6.0 3.9
Dry wells 1.0 0.3
----------------------------------------------------------------------------
Total wells 16.0 10.7
Success rate (%) 94 97
----------------------------------------------------------------------------
----------------------------------------------------------------------------


What are the Company's drilling plans for the remainder of 2010?

The capital program for the remainder of 2010 consists of a broad range of projects including the drilling of up to 8.0 wells. The focus of the program will continue to be on light oil and natural gas opportunities in Bigstone and Hythe with several wells being drilled in the Company's newly acquired Wapiti/Gold Creek area pursuing liquids-rich natural gas opportunities. The program will consist of both vertical and horizontal drilling using multi-stage fracturing technology in horizontal wells and multiple completions for commingled production in vertical wells.

CAPITAL INVESTED

How much did the Company spend in the first quarter of 2010 and where were the capital expenditures incurred?

The Company continued to direct its capital program at its core areas of Bigstone, Hythe, and Wapiti/Gold Creek to take advantage of the multi-zone nature of these assets, low production operating costs and quick on-stream capability associated with owned gathering and processing infrastructure. Total capital invested in the field was $35.5 million, net of drilling credits of $4.5 million earned in the quarter, with approximately 76 percent directed at drilling and completion operations and 15 percent incurred on equipping and facility projects.

Delphi also added to its growth potential with the acquisition of 79 net sections of Duvernay shale rights at attractive entry costs targeting natural gas and/or light oil. Delphi's inventory of undeveloped land has increased to approximately 213,000 net acres, up 24 percent from December 31, 2009.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Land 2,099 266 689
Seismic 123 26 373
Drilling and completions 27,135 11,010 146
Equipping and facilities 5,345 1,478 262
Capitalized expenses 795 1,116 (29)
Other 7 196 (96)
----------------------------------------------------------------------------
Capital invested 35,504 14,092 152
Disposition of properties - (151) (100)
----------------------------------------------------------------------------
Net capital invested 35,504 13,941 155
Acquisition of properties 692 - 100
----------------------------------------------------------------------------
Total capital invested 36,196 13,941 160
----------------------------------------------------------------------------
----------------------------------------------------------------------------


PRODUCTION

In a challenging environment for natural gas producers, how was Delphi successful in achieving such a significant increase in production volumes?

For the three months ended March 31, 2010, Delphi achieved record quarterly production of 7,645 boe/d, an increase of 13 percent over the comparative period in 2009. The increase in production is attributed to a successful winter drilling program in the Company's core areas as well as the closing of strategic acquisitions during the latter half of 2009. With the near term weakness in natural gas pricing, Delphi is well positioned for future growth with a large inventory of liquids rich natural gas and crude oil opportunities. 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 quarter was weighted 84 percent to natural gas, 10 percent to crude oil and six percent to natural gas liquids. Delphi has been focused on increasing crude oil and liquids-rich natural gas production to maximize netbacks and has achieved a 57 percent increase in crude oil production over the first quarter of 2009. The Doe Creek and Cardium plays will provide Delphi with the opportunity to significantly increase the production mix of light oil.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Natural gas (mcf/d) 38,349 34,813 10
Crude oil (bbls/d) 745 475 57
Natural gas liquids (bbls/d) 508 485 5
----------------------------------------------------------------------------
Total (boe/d) 7,645 6,762 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three months ended March 31, 2010, natural gas liquids were 5 percent higher than the comparative period primarily due to the increased natural gas liquids production at Wapiti, Alberta.

REALIZED SALES PRICES

What were the sales prices realized by the Company for each of its products?

For the three months ended March 31, 2010, Delphi's risk management program realized a gain of $2.9 million. For the quarter, the realized gain was $0.83 per mcf with physical contracts contributing a gain of $0.83 per mcf and financial contracts contributing a gain of $nil per mcf. The average realized natural gas price was four percent less than the comparative period due to a decrease in hedge gains offset by higher heat content on natural gas volumes.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
AECO ($/mcf) 4.96 4.95 -
Heating content and marketing ($/mcf) 0.47 0.32 47
Gain on physical contracts ($/mcf) 0.83 0.95 (13)
Gain on financial contracts ($/mcf) - 0.33 (100)
----------------------------------------------------------------------------
Realized natural gas price ($/mcf) 6.26 6.55 (4)

Edmonton Light ($/bbl) 80.07 49.65 61
Quality differential ($/bbl) (4.49) (3.54) (27)
Gain on financial contracts ($/bbl) 0.70 - 100
----------------------------------------------------------------------------
Realized oil price ($/bbl) 76.28 46.11 65

Realized natural gas liquids
price ($/bbl) 61.53 39.04 58
----------------------------------------------------------------------------
Total realized sales price
($/boe) 42.91 39.77 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Delphi's oil production is a mix of light and medium 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. The Company's realized crude oil and natural gas liquids prices were significantly higher than the comparative quarter in the previous year as a result of the significant increase in benchmark prices.

How do the realized natural gas prices compare to the benchmark AECO pricing?

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 5,500 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. 31 Dec. 31 Sept. 30 Jun. 30
2010 2009 2009 2009
----------------------------------------------------------------------------
Natural Gas Price
Delphi realized ($/mcf) 6.26 6.15 5.77 5.81
AECO average ($/mcf) 4.96 4.49 2.94 3.47
Premium (discount) to AECO 26% 37% 96% 67%
Hedging gain (loss) ($000's) 2,941 4,498 7,973 6,997
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Mar. 31 Dec. 31 Sept.30 Jun. 30
2009 2008 2008 2008
----------------------------------------------------------------------------
Natural Gas Price
Delphi realized ($/mcf) 6.55 8.14 8.28 9.66
AECO average ($/mcf) 4.95 6.70 7.73 10.22
Premium (discount) to AECO 32% 21% 7% (5%)
Hedging gain (loss) ($000's) 3,991 1,985 (67) (3,153)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


RISK MANAGEMENT ACTIVITIES

What is Delphi's risk management strategy and what contracts are in place to mitigate the risk of volatility?

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. For natural gas production, Delphi has hedged approximately 54 percent of its before-royalty natural gas production at a predominately AECO based average floor price of $6.05 per mcf for the remainder of 2010.

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 operations. Physical commodity sale contracts based in U.S. dollars include an embedded derivative associated with the foreign exchange rate. Due to this derivative, the changes in the fair value of these contracts are included in the statement of earnings. As at March 31, 2010, the Company did not hold any physical commodity sales contracts based in U.S. dollars.



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)
----------------------------------------------------------------------------
January 2010 -
March 2011 Natural Gas Financial 2,000 GJ/d $5.72 fixed
January 2010 -
December 2010(i) Natural Gas Financial 3,500 GJ/d $7.40 Call
January 2010 -
December 2010(i) Natural Gas Physical 3,500 GJ/d $7.15 Call
January 2010 -
December 2010 Crude Oil Financial 100 bbls/d $86.40 fixed
January 2010 - $72.20 floor/
December 2010 Crude Oil Financial 100 bbls/d $100.00 ceiling
January 2010 -
March 2011 Natural Gas Physical 1,500 GJ/d $5.74 fixed
April 2010 -
October 2010(ii) Natural Gas Financial 2,500 GJ/d $4.75 Put
April 2010 -
October 2010 Natural Gas Financial 2,000 GJ/d $5.53 fixed
April 2010 - $4.80 floor plus 50%
October 2010 Natural Gas Financial 1,500 GJ/d greater than $4.80
April 2010 - $6.25 floor/
December 2010 Natural Gas Physical 3,000 GJ/d $7.47 ceiling
April 2010 - $5.93 floor plus 50%
December 2010 Natural Gas Physical 4,000 GJ/d greater than $5.93
April 2010 -
March 2011 Natural Gas Physical 3,000 GJ/d $6.12 fixed
April 2010 -
March 2011 Natural Gas Physical 2,500 GJ/d $5.73 fixed
January 2011 -
December 2011(ii) Natural Gas Financial 2,500 GJ/d $7.14 Call
April 2011 -
October 2011 Natural Gas Physical 2,000 GJ/d $5.66 fixed
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) The 2010 call contracts were executed in 2009 to obtain a $6.00 put in
2009 on a costless basis.
(ii) The Company has acquired a natural gas put contract at $4.75 per
gigajoule on 2,500 gigajoules per day for the period April 1, 2010
through October 31, 2010. This put was paid for with the sale of a
natural gas call on 2,500 gigajoules per day at a price of $7.14 per
gigajoule for the period January 1, 2011 through December 31, 2011.


The Company recognized an unrealized non-cash gain on its financial contracts of $3.4 million for the three months ended March 31, 2010. 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 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

How do revenues in 2010 compare to the same period in 2009 and what factors contributed to the change?

For the three months ended March 31, 2010, Delphi generated revenue of $29.5 million, representing an increase of 22 percent over the comparative period in 2009 of $24.2 million. The increase in revenue is a result of a 13 percent increase in production volumes and an eight percent increase in the realized price per boe. Contributing to the increased price per boe is the production increase of crude oil and natural gas liquids.

The risk management program associated with natural gas pricing generated revenue of $2.9 million in the first quarter of 2010. For seven consecutive quarters, Delphi has received a premium to AECO pricing due to the success of the risk management program.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Natural gas 18,650 16,521 13
Natural gas physical contract
gains 2,878 2,962 (3)
Crude oil 5,068 1,971 157
Natural gas liquids 2,813 1,704 65
Sulphur 47 18 161
Natural gas financial contract
gains 16 1,029 (98)
Crude oil financial contract
gains 47 - 100
----------------------------------------------------------------------------
Total 29,519 24,205 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------


ROYALTIES

What are the types of royalties the Company pays to produce oil and gas?

The Company pays royalties to provincial governments, individuals and companies that own surface and/or mineral rights. These payments take the form of Crown, freehold and overriding royalties. Crown royalty rates for crude oil and natural gas are generally calculated on a sliding scale based on commodity prices and production rates whereas freehold and overriding royalty rates are generally a fixed percentage of revenue. Crown royalty rates can change due to price fluctuations or changes in production volumes on a well by well basis subject to minimum and maximum rates. For natural gas liquids, Crown royalty rates are a fixed percentage of revenue with the rate varying according to the nature of the product. Crown royalty credits are credits received from the Crown and represent the fee earned by the owners of natural gas processing infrastructure to process the Crown's royalty share of natural gas. Royalties are not affected by gains or losses realized through the Company's risk management program.

What were royalty costs in the first quarter of 2010 and how did they compare to the same period in 2009?

Crown royalties of $4.7 million were partially offset by $2.1 million of royalty credits with the net amount of $2.6 million representing 68 percent of the total royalties paid in the first quarter of 2010 compared to 95 percent in 2009. The net Crown royalties were significantly lower than the $4.2 million paid in the first three months of 2009 primarily as a result of the impact of the New Royalty Framework (NRF) royalty rates and royalty incentive programs on new production post March 31, 2009.

Gross overriding royalties represent 30 percent of total royalties in the first quarter of 2010 compared to three percent in the comparative period of 2009. The increase in gross overriding royalties is a result of the five percent gross overriding royalty granted on the Bigstone property in exchange for cash proceeds of $10.5 million late in 2009 as well as various farm-in transactions undertaken by the Company.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Crown royalties 4,732 5,434 (13)
Royalty credits (2,124) (1,200) 77
----------------------------------------------------------------------------
Crown royalties - net 2,608 4,234 (38)
Freehold royalties 71 86 (17)
Gross overriding royalties 1,135 123 823
----------------------------------------------------------------------------
Total 3,814 4,443 (14)
Per boe 5.54 7.30 (24)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


What were the average royalty rates paid on production in 2010?

For the three months ended March 31, 2010, the Crown royalty rate decreased 52 percent over the comparative period. The lower Crown royalty rate was primarily due to the low royalty rates under the NRF. The gross overriding royalty rate increased to four percent in 2010 from one percent in the prior year.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Crown rate - net of royalty
credits 10% 21% (52)
Gross overriding rate 4% 1% 300
----------------------------------------------------------------------------
Average rate 14% 22% (36)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The royalty rate calculations above exclude gains or losses on risk
management activities from revenue as the denominator.


What are the Company's expectations for royalty rates in 2010?

Delphi's average royalty rate for 2010 will ultimately be determined by the production rate of individual wells and commodity prices. Based on the Company's forecast of U.S. $75.00 per barrel of crude oil and an AECO spot price of Cdn $5.00 per mcf, Delphi anticipates its average royalty rate in 2010 to average between 13 and 15 percent. Similar to 2009, for 2010 the Company expects to receive the royalty credits for processing the Crown share of natural gas and natural gas liquids production and the credits received may be greater in 2010 as a result of the acquisition of additional working interests in natural gas processing facilities as part of the Company's property acquisitions throughout 2009. The five percent royalty rate on new production in 2010 also is expected to continue to have a positive effect on royalty rates.

OPERATING EXPENSES

How has the Company been able to reduce its operating expenses in 2010 as compared to 2009?

Operating costs on a per boe basis for the three months ended March 31, 2010, decreased 15 percent over the comparative period. The significant decrease in operating costs is attributed to higher production volumes from cost efficient core areas. In addition, the infrastructure acquisitions completed in 2009 benefit the Company through increased processing income from third party production volumes going through facilities owned by Delphi. Processing income in the first quarter of 2009 included $0.5 million of income from prior periods received in 2009. With continued growth in production volumes from core areas, the Company's operating cost per boe are expected to continue decreasing.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Production costs 6,568 7,264 (10)
Processing income (577) (1,060) (46)
----------------------------------------------------------------------------
Total 5,991 6,204 (3)
Per boe 8.71 10.19 (15)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


What are the Company's expectations for operating costs in 2010?

Delphi continues to focus on cost reduction and continues to direct staff to look for potential cost efficiencies. The corporate strategy to improve cost structure is working as the Company anticipates 2010 operating costs in the $8.25 to $8.75 per boe range.

TRANSPORTATION EXPENSES

How are transportation costs different from operating costs?

Transportation expenses are costs incurred by the Company to transport its production volumes from the wellhead to the point of sales. 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.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Total 2,196 1,461 50
Per boe 3.19 2.40 33
----------------------------------------------------------------------------
----------------------------------------------------------------------------


What factors contributed to the increase in transportation costs in the first quarter of 2010 and what are the Company's expectations for the remainder of 2010?

On a per boe basis, transportation costs for the three months ended March 31, 2010, increased by 33 percent over the comparative period. The increase in transportation costs is attributed to additional transportation capacity acquired in the latter half of 2009 which will be utilized as production volumes grow in core areas. Delphi expects transportation costs to be between $2.50 and $3.00 per boe for 2010.



GENERAL AND ADMINISTRATIVE

Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
General and administrative costs 2,433 3,257 (25)
Overhead recoveries (555) (259) 114
Salary allocations (859) (1,876) (54)
----------------------------------------------------------------------------
Net 1,019 1,122 (9)
Per boe 1.48 1.84 (20)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


How do the costs of general and administrative costs in 2010 compare to 2009?

On a per boe basis, general and administrative (G&A) costs for the three months ended March 31, 2010 decreased 20 percent over the comparative period in 2009 due in part to an increase in production volumes. In 2009, annual compensation adjustments were recorded in the first quarter. Delphi is committed to delivering strong growth and believes a strong team is paramount to achieve this goal. For 2010, Delphi is expecting G&A per boe to be approximately $2.00 per boe.

STOCK-BASED COMPENSATION

What is stock-based compensation expense?

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.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Stock-based compensation 216 491 (56)
Capitalized costs (111) (280) (60)
----------------------------------------------------------------------------
Net 105 211 (50)
Per boe 0.15 0.35 (57)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The stock based non-cash compensation expense for the three months ended March 31, 2010, decreased 50 percent over the comparative period. During the three months ended March 31, 2010, Delphi capitalized $0.1 million of stock-based compensation associated with exploration and development activities.

INTEREST

How do the costs of borrowing in the first quarter of 2010 compare against the same period in 2009?

For the three months ended March 31, 2010, interest expense on a per boe basis increased 24 percent over the comparative period. The increase over the comparative quarter was due to the increased pricing on the Company's credit agreement established late in the second quarter of 2009, reflective of higher market credit spreads.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Total 1,342 958 40
Per boe 1.95 1.57 24
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During 2009, the Company converted $80.0 million of its outstanding long term debt from prime-based loans to bankers' acceptances. At March 31, 2010, the bankers' acceptances have terms ranging from 90 to 181 days and a weighted average effective interest rate of 4.23 percent over the term.

What has the Company done to protect itself against an increase in interest rates?

The Company has entered into an interest rate swap transaction on borrowings through bankers' acceptances in the amount of $40.0 million maturing on May 4, 2011. The bankers' acceptance rate on the transaction will increase in fixed monthly increments of 4.55 basis points for an average fixed rate over two years of 0.94 percent. The effective interest rate over the two year term on $40.0 million of bankers' acceptances will be 0.94 percent plus the applicable stamping fee.

DEPLETION, DEPRECIATION AND ACCRETION

How has the Company's depletion and depreciation rate and expense changed in 2010 as compared to the same period in 2009?

Depletion and depreciation per boe for the three months ended March 31, 2010 decreased 17 percent over the comparative period. With continued drilling success at Bigstone, Hythe and Wapiti/Gold Creek, Delphi has been able to add proved reserves at a cost below the Company's current depletion rate. 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.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Depletion and depreciation 13,655 14,550 (6)
Accretion expense 247 243 2
----------------------------------------------------------------------------
Total 13,902 14,793 (6)
----------------------------------------------------------------------------
Depletion and depreciation per boe 19.85 23.91 (17)
Accretion per boe 0.36 0.40 (10)
----------------------------------------------------------------------------
Total per boe 20.21 24.31 (17)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


What is accretion expense and how did this expense for the first three months of 2010 compare to 2009?

The accretion of asset retirement obligations is an expense that 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 eight to ten 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, 2010 increased one percent over the comparative period.

INCOME TAXES

What was the affect on future income taxes during the first quarter?

The provision for future income taxes in the financial statements for the three months ended March 31, 2010, was $1.3 million due to earnings in the first quarter of 2010 versus a loss in the comparative period. Delphi does not anticipate it will be cash taxable before 2012.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Current - - -
Future (reduction) 1,327 (1,107) -
----------------------------------------------------------------------------
Total 1,327 (1,107) -
Per boe 1.93 (1.82) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


FUNDS FROM OPERATIONS

What are funds from operations and why is it a key performance measure?

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, 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. Delphi uses funds from operations (cash flow) 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 to grow the Company's value for the shareholders and to repay debt.

What were the funds from operations for the first quarter?

For the three months ended March 31, 2010, funds from operations were $15.2 million ($0.15 per basic share) compared to $10.0 million ($0.13 per basic share) in the comparative period. The 51 percent increase in funds from operations is a result of an increase in realized prices per boe and production volumes, reduced royalty rates and a reduction in operating costs per boe.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Net earnings (loss) 3,260 (3,320) -
Non-cash items:
Depletion, depreciation and
accretion 13,902 14,793 (6)
Unrealized loss (gain) on risk
management activities (3,437) (560) 514
Stock-based compensation
expense 105 211 (50)
Future income taxes (reduction) 1,327 (1,107) -
----------------------------------------------------------------------------
Funds from operations 15,157 10,017 51
----------------------------------------------------------------------------
----------------------------------------------------------------------------


How do funds from operations compare to cash flow from operating activities in the financial statements?

Funds from operations reflect two primary differences from the GAAP term cash flow from operating activities shown on the financial statements. These differences are expenditures incurred for asset retirement obligations and reclamation and changes in non-cash working capital. The following table is a reconciliation of funds from operations to cash flow from operating activities for the periods noted.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Funds from operations: Non-GAAP 15,157 10,017 51
Settlement of asset retirement
obligations - - -
Change in non-cash working
capital (4,028) (1,504) 168
----------------------------------------------------------------------------
Cash flow from operating
activities: GAAP 11,129 8,513 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NET EARNINGS

Was Delphi able to generate earnings during the first quarter?

For the three months ended March 31, 2010, Delphi recorded net earnings of $3.3 million ($0.03 per basic share) compared to a net loss of $3.3 million ($0.04 per basic share) in the comparative period. Net earnings were affected by non-cash items such as depletion, depreciation and accretion, unrealized gains 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

How was Delphi able to improve the netbacks in the first quarter of 2010 compared to the prior year?

The Company's netbacks were higher than the comparative quarter due to a higher realized price per boe, a reduction in operating costs and royalties per boe, lower general and administrative cost per boe and a significant improvement in the depletion rate per boe. The operating netback and cash netback were higher than the cost of finding and developing reserves resulting in a positive recycle ratio.

Delphi's production is predominantly natural gas and therefore Delphi's operating and cash netbacks are primarily driven by the price received for natural gas.



Three Months Ended March 31
2010 2009 % Change
----------------------------------------------------------------------------
Barrels of oil equivalent ($/boe)
Realized sales price 42.91 39.77 8
Royalties 5.54 7.30 (24)
Operating expenses 8.71 10.19 (15)
Transportation 3.19 2.40 33
----------------------------------------------------------------------------
Operating netback 25.47 19.88 28
General and administrative
expenses 1.48 1.84 (20)
Interest 1.95 1.57 24
----------------------------------------------------------------------------
Cash netback 22.04 16.47 34
Unrealized gain on financial
contracts (5.00) (0.92) 443
Stock-based compensation
expense 0.15 0.35 (57)
Depletion, depreciation and
accretion 20.21 24.31 (17)
Future income taxes (reduction) 1.93 (1.82) -
----------------------------------------------------------------------------
Net earnings (loss) 4.75 (5.45) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Share Capital

What has been the market activity in the Company's common shares?

At March 31, 2010, the Company had 101.5 million common shares outstanding (December 31, 2009 - 101.2 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, 2010.



Three Months Ended
March 31, 2010
----------------------------------------------------------------------------
Weighted Average Common Shares (000's)
Basic 101,247
Diluted 104,234
Trading Statistics (1)
High 3.18
Low 1.70
Average daily, volume 779,939
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Trading statistics based on closing price


How many common shares and stock options are currently outstanding?

As at May 3, 2010, the Company had 101.5 million common shares outstanding and 7.9 milllion stock options outstanding. The stock options have an average exercise price of $1.53 per share.



Sources and Uses of Funds

Three Months Ended
March 31, 2010
----------------------------------------------------------------------------
Sources:
Funds from operations 15,157
Exercise of stock options 338
Cash and cash equivalents 5,131
Change in non-cash working capital 16,670
----------------------------------------------------------------------------
37,296
Uses:
Capital expenditures 35,504
Acquisition of petroleum and natural gas properties 692
----------------------------------------------------------------------------
36,196

----------------------------------------------------------------------------
Decrease in bank debt (1,100)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Bank Debt plus Working Capital Deficiency (Net Debt)

How much net debt was outstanding at March 31, 2010?

At March 31, 2010, the Company had $80.0 million outstanding in the form of bankers' acceptances and a working capital deficiency of $33.2 million for total net debt of $113.2 million excluding the financial asset of $3.1 million relating to the unrealized gain on financial commodity contracts and the associated future income tax liability.

What are the Company's credit facilities and when is the next scheduled review of the borrowing base?

The Company has a $5.0 million operating facility and a $120.0 million revolving credit facility for a total of $125.0 million in credit. Upon completion of the semi-annual review and syndication undertaken by Delphi in the fall of 2009, the revolving credit facility of $125.0 million remains unchanged from the prior year. The next scheduled renewal of the Company's credit facilities is currently underway and will be determined based on the Company's year-end engineering report, the results of the winter drilling program and the lenders' view of future commodity prices and other factors.

What are the Company's forecast debt levels for the end of 2010?

In 2010, Delphi anticipates a field capital expenditure program equivalent to projected funds from operations with acquisitions being funded by equity and proceeds on the disposition of assets resulting in net debt levels between $95.0 and $100.0 million by the end of 2010. Growth in cash flow to approximately $60.0 to $65.0 million is expected to result in a net debt to cash flow ratio of approximately 1.5:1 by the end of 2010.

As in prior years, net debt was expected to increase in the first quarter of 2010 as a result of a winter capital program greater than cash flow with net debt being reduced in the second quarter as capital expenditures are expected to be minimal due to spring breakup. The significant excess cash flow generated in the second quarter will be applied against net debt. Capital expenditures for the second half of the year will be planned according to the cash flow generated and achieving net debt targets.

Contractual Obligations

What are the contractual obligations as of March 31, 2010 that will require funding in future years?

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 over the next five years are as follows:

2010 2011 2012 2013 2014
----------------------------------------------------------------------------
Gathering, processing and
transmission 3,499 4,063 3,073 2,605 2,472
Office and equipment
lease 1,417 1,029 775 390 -
----------------------------------------------------------------------------
Total 4,916 5,092 3,848 2,995 2,472
----------------------------------------------------------------------------
----------------------------------------------------------------------------


GUARANTEES AND OFF-BALANCE SHEET ARRANGEMENTS

Does Delphi have any outstanding guarantees on behalf of third parties or any off-balance sheet arrangements which could lead to liabilities in the future?

Delphi has not entered into any guarantees or off-balance sheet arrangements. Certain lease agreements entered into in the normal course of operations could be considered off-balance sheet arrangements, however, all leases are operating leases with lease payments charged to operating expenses or general and administrative expenses on a monthly basis according to the lease.

CRITICAL ACCOUNTING ESTIMATES

In preparing the Company's financial statements, is Delphi required to make estimates or assumptions about future events?

Delphi's financial statements have been prepared in accordance with Canadian generally 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 February 2008, the Canadian Accounting Standards Board ("AcSB") confirmed that Canadian publicly accountable entities will be required to report under International Financial Reporting Standards ("IFRS"), which will replace Canadian generally accepted accounting principles ("GAAP") for years beginning on or after January 1, 2011. Thus, 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.

In July 2009, the International Accounting Standards Board ("IASB") approved IFRS transitional exemptions that will allow entities to allocate their oil and gas asset balance as determined under full cost accounting to the IFRS categories of exploration and evaluation assets and development and producing properties. Under the exemption, exploration and evaluation assets are measured at the amount determined under an entity's previous GAAP. For assets in the development or production phases, the amount is also measured at the amount determined under an entity's previous GAAP; however, such values must be allocated to the underlying IFRS transitional assets on a pro-rata basis using either reserve values or reserve volumes as of the entity's IFRS transition date. This exemption will relieve entities from significant adjustments resulting from retrospective adoption of IFRS. The Company intends to utilize this exemption. The Company is also evaluating other first-time adoption exemptions and elections available upon initial transition that provide relief from retrospective application of IFRS.

The Company continues to assess the Canadian GAAP and IFRS differences as well as the effects of adoption and finalizing its conversion plan. The Company has determined that accounting for property, plant and equipment will be impacted by the conversion to IFRS. The Company currently follows full cost accounting as prescribed in Accounting Guideline ("AcG") 16, "Oil and Gas Accounting - Full Cost." Conversion from Canadian GAAP to IFRS may have an impact on how the Company accounts for costs pertaining to oil and gas activities, in particular those related to the pre-exploration and development phases. The conversion to IFRS will also result in other impacts, some of which may be significant in nature.

Ongoing assessments of other affects include provisions, stock-based compensation and asset retirement obligations. The Company also continues to perform assessments on less critical IFRS transition issues and has commenced analysis of IFRS financial statement presentation and disclosure requirements. These assessments will need to be further analyzed and evaluated throughout the implementation phase of the Company's project. At this time, the impact on the Company's financial position and results of operations is not reliably determinable or estimable.

The Company will continue to monitor any changes in the adoption of IFRS and will update its plan as necessary.

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 its corporate governance policies. Delphi's Board of Directors consists of six 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 are effective and 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 first quarter of 2010.

2010 OUTLOOK

What is the Company's overall strategy and plans for 2010 and beyond?

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 the deep basin of North West Alberta with approximately 25 percent of its production being crude oil and natural gas liquids. 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. Currently, Delphi has identified over one hundred and fifty drilling locations, representing three to five years drilling inventory, in its core areas.

Capital Activities

With the continuing uncertainty in commodity prices and the economy, Delphi will fund its 2010 field capital program from internally generated cash flow from operations. Delphi has a planned 2010 field capital program ranging between $60.0 to $65.0 million with the objective of preserving the Company's financial flexibility and maintaining the flexibility to pursue and capture strategic growth opportunities attractively priced in this transaction-oriented environment.

The capital program for 2010 includes the drilling of up to 24 (17.6 net) wells with the majority of the capital allocated to the Company's three main areas, Bigstone, Hythe and Wapiti/Gold Creek.

Financial Strategy

The Company is well positioned to endure the current weak economic environment with high quality producing assets, increased exposure to light oil and liquids-rich natural gas opportunities, a large inventory of economic projects in numerous play types and a 2010 cash flow stream protected with 54 percent of the Company's current natural gas production hedged at an average price of $6.05 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 transaction-oriented environment, will be key drivers in the capital spending decision process for 2010 and beyond.

ADDITIONAL INFORMATION

Where is additional information about Delphi available?

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) 2010 2009
----------------------------------------------------------------------------
Assets
Current assets
Accounts receivable 25,448 15,630
Prepaid expenses and deposits 5,183 6,004
Future income taxes - 112
Risk management asset (Note 7) 3,056 -
----------------------------------------------------------------------------
33,687 21,746

Property, plant and equipment (Note 3) 362,757 339,952
----------------------------------------------------------------------------
Total assets 396,444 361,698
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities
Current liabilities
Outstanding cheques 5,270 139
Future income taxes 889 -
Accounts payable and accrued liabilities 58,600 32,933
Risk management liability (Note 7) - 381
----------------------------------------------------------------------------
64,759 33,453

Long term debt (Note 4) 80,000 81,100
Future income taxes 25,895 23,917
Asset retirement obligations (Note 5) 12,181 11,818
----------------------------------------------------------------------------
182,835 150,288

Shareholders' equity
Share capital (Note 6) 198,955 200,055
Contributed surplus (Note 6) 11,087 11,048
Retained earnings 3,567 307
----------------------------------------------------------------------------
Total shareholders' equity 213,609 211,410
----------------------------------------------------------------------------
Total liabilities and shareholders' equity 396,444 361,698
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Commitments (Note 8)

See accompanying notes to the consolidated financial statements.


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

(Stated in thousands of dollars, except per
share amounts) 2010 2009
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales 29,456 23,176
Realized gain on risk management activities
(Note 7) 63 1,029
----------------------------------------------------------------------------
29,519 24,205
Royalties (3,814) (4,443)
Unrealized gain on risk management activities
(Note 7) 3,437 560
----------------------------------------------------------------------------
29,142 20,322

Expenses
Operating 5,991 6,204
Transportation 2,196 1,461
General and administrative 1,019 1,122
Stock-based compensation (Note 6) 105 211
Interest 1,342 958
Depletion, depreciation and accretion 13,902 14,793
----------------------------------------------------------------------------
24,555 24,749

----------------------------------------------------------------------------
Earnings (loss) before income taxes 4,587 (4,427)

Taxes
Future income taxes (reduction) 1,327 (1,107)
----------------------------------------------------------------------------
1,327 (1,107)

----------------------------------------------------------------------------
Net earnings (loss) and comprehensive income
(loss) 3,260 (3,320)
Retained earnings, beginning of period 307 8,336
----------------------------------------------------------------------------
Retained earnings, end of period 3,567 5,016
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Earnings (loss) per share (Note 6)
Basic and diluted 0.03 (0.04)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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) 2010 2009
----------------------------------------------------------------------------

Cash flow from operating activities
Net earnings (loss) 3,260 (3,320)
Add non-cash items:
Depletion, depreciation and accretion 13,902 14,793
Stock-based compensation 105 211
Unrealized gain on risk management activities (3,437) (560)
Future income taxes (reduction) 1,327 (1,107)
Change in non-cash working capital (Note 9) (4,028) (1,504)
----------------------------------------------------------------------------
11,129 8,513
Cash flow from (used in) financing activities
Exercise of stock options 338 -
Increase (decrease) in long term debt (1,100) 5,100
----------------------------------------------------------------------------
(762) 5,100

----------------------------------------------------------------------------
Cash flow available for investing activities 10,367 13,613

Cash flow from (used in) investing activities
Capital expenditures (35,504) (14,092)
Disposition of petroleum and natural gas
properties - 151
Acquisition of petroleum and natural gas
properties (692) -
Change in non-cash working capital (Note 9) 20,698 (6,992)
----------------------------------------------------------------------------
(15,498) (20,933)

----------------------------------------------------------------------------
Decrease in cash and cash equivalents (5,131) (7,320)
Cash and cash equivalents, beginning of period (139) 924
----------------------------------------------------------------------------
Cash and cash equivalents, end of period (5,270) (6,396)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash and cash equivalents is comprised of:
Cash - 6
Outstanding cheques (5,270) (6,402)
----------------------------------------------------------------------------
(5,270) (6,396)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Interest paid 1,396 1,757
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


DELPHI ENERGY CORP.
Notes to the Consolidated Financial Statements (unaudited)
As at and for the periods ended March 31, 2010 and 2009
(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 publicly-traded company listed on the Toronto Stock Exchange. Delphi is primarily engaged in the acquisition, exploration for and development and production of crude oil, natural gas and natural gas liquids from properties located in North West Alberta.

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, 2009. 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, 2009. 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.



NOTE 3: PROPERTY, PLANT AND EQUIPMENT

Accumulated
depletion and Net
As at March 31, 2010 Cost depreciation book value
----------------------------------------------------------------------------
Petroleum and natural gas properties 477,852 230,381 247,471
Production equipment 151,039 36,291 114,748
Furniture, fixtures and office
equipment 1,278 740 538
----------------------------------------------------------------------------
630,169 267,412 362,757
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated
depletion and Net
As at December 31, 2009 Cost depreciation book value
----------------------------------------------------------------------------
Petroleum and natural gas properties 448,619 218,505 230,114
Production equipment 143,813 34,547 109,266
Furniture, fixtures and office
equipment 1,277 705 572
----------------------------------------------------------------------------
593,709 253,757 339,952
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three months ended March 31, 2010, the Company capitalized $0.8 million (March 31, 2009 - $1.1 million) of general and administrative costs directly related to exploration and development activities.

As at March 31, 2010, costs in the amount of $6.1 million (March 31, 2009 - $2.5 million) representing unproved properties were excluded from the depletion calculation and estimated future development costs of $48.6 million (March 31, 2009 - $44.9 million) have been included in costs subject to depletion. Ultimate recoverability of these costs will be dependent upon finding proved oil and natural gas reserves.



NOTE 4: LONG TERM DEBT

March 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Prime-based loans - 1,100
Bankers' acceptances 80,000 80,000
----------------------------------------------------------------------------
Total debt 80,000 81,100
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company has a revolving facility for $125.0 million with a syndicate of Canadian chartered banks. The facility is a 364 day committed revolving facility until May 31, 2010, the term-out date. 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 pricing grid tied to the Company's trailing debt to cash flow ratio: from a minimum of the bank's prime rate plus 2.0 percent to a maximum of the bank's prime rate plus 5.0 percent or from a minimum of bankers' acceptances rate plus a stamping fee of 3.0 percent to a maximum of bankers' acceptances rate plus a stamping fee of 5.0 percent.

The Company has converted $80.0 million of its outstanding long term debt from prime-based loans to bankers' acceptances. The bankers' acceptances have terms ranging from 90 to 181 days and a weighted average effective interest rate of 4.23 percent over the term.

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

NOTE 5: 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 $25.5 million (March 31, 2009 - $21.6 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, 2010 December 31, 2009
----------------------------------------------------------------------------
Balance, beginning of period 11,818 9,730
Liabilities incurred 175 132
Liabilities disposed (59) (487)
Liabilities acquired - 1,793
Liabilities settled - (167)
Accretion expense 247 817
----------------------------------------------------------------------------
Balance, end of period 12,181 11,818
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NOTE 6: 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, 2010 December 31, 2009
Outstanding Outstanding
shares shares
(000's) Amount (000's) Amount
----------------------------------------------------------------------------
Balance, beginning of period 101,166 200,055 79,067 174,995
Issue of common shares - - 13,200 16,500
Issue of common shares
- Fairmount - - 5,835 6,360
Issue of flow-through common
shares - - 3,000 6,360
Exercise of stock options 289 338 64 43
Allocated from contributed
surplus - 177 - 23
Share issue costs - - - (1,523)
Future tax effect of share
issue costs - - - 405
Tax benefit renounced to
shareholders - (1,615) - (3,108)
----------------------------------------------------------------------------
Balance, end of period 101,455 198,955 101,166 200,055
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On November 16, 2009, the Company issued 3.0 million flow-through common shares at a price of $2.12 per share for gross proceeds of $6.4 million. The Company has an obligation to incur qualifying exploration expenditures by December 31, 2010 to satisfy the terms of the flow-through common shares issued in 2009.

(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. Options granted prior to September 1, 2009 vested over a two-year period starting on the date of grant. Options granted on September 1, 2009 or later vest over a two-year period with one-third vesting six months after the date of grant and one-third on each of the first and second anniversary of the grant date. The exercise price of each option equals the five day weighted average of the market price of the Company's common shares, immediately preceding the date of the grant. As at March 31, 2010, there were 7.3 million options to purchase shares outstanding.

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



March 31, 2010 December 31, 2009
Weighted Weighted
Outstanding average Outstanding average
options exercise options exercise
(000's) price (000's) price
----------------------------------------------------------------------------
Balance, beginning of period 7,428 1.40 4,731 1.75
Granted 110 2.71 3,017 0.83
Forfeited - - (256) 1.31
Exercised (288) 1.17 (64) 0.67
----------------------------------------------------------------------------
Balance, end of period 7,250 1.43 7,428 1.40
----------------------------------------------------------------------------
Exercisable, end of period 5,714 1.49 5,245 1.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The following table summarizes information about the stock options
outstanding and exercisable at March 31, 2010.

Options outstanding Options exercisable

Weighted
Weighted average Weighted
Outstanding average remaining average
Range of exercise options exercise term Exercisable exercise
price (000's) price (years) (000's) price
----------------------------------------------------------------------------
$0.65 - $0.97 1,859 0.66 3.91 1,203 0.66
$0.98 - $1.54 835 1.20 4.20 228 1.25
$1.55 - $1.72 3,786 1.67 2.67 3,711 1.67
$1.73 - $2.15 440 1.82 2.55 425 1.80
$2.16 - $3.34 330 3.02 3.80 147 3.18
----------------------------------------------------------------------------
Total 7,250 1.43 3.21 5,714 1.49
----------------------------------------------------------------------------


(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, 2010, Delphi recorded non-cash compensation expense of $0.1 million (March 31, 2009 - $0.2 million). The Company capitalized $0.1 million (March 31, 2009 - $0.3 million) of stock-based compensation directly related to exploration and development activities. The future income tax liability associated with the capitalized stock-based compensation in the amount of $nil (2009 - $0.1 million) has also been capitalized for the year.

During the three months ended March 31, 2010, the Company granted 0.1 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 $1.54 per option (March 31, 2009 - $0.35 per option). The assumptions used in the Black-Scholes model to determine fair value were as follows.



For the three months ended March 31 2010 2009
----------------------------------------------------------------------------
Risk-free interest rate (%) 2.6 1.9
Expected life (years) 5.0 5.0
Expected volatility (%) 65.8 61.7
----------------------------------------------------------------------------


(e) Contributed surplus

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



March 31, December 31,
2010 2009
----------------------------------------------------------------------------
Balance, beginning of period 11,048 9,605
Stock-based compensation expensed 105 615
Stock-based compensation capitalized 111 851
Reclassification to common shares on exercise
of stock options (177) (23)
----------------------------------------------------------------------------
Balance, end of period 11,087 11,048
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(f) Net earnings (loss) per share

For the three months ended March 31 2010 2009
----------------------------------------------------------------------------
Basic (000's) 101,247 79,067
Diluted (000's) 104,234 79,067
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The reconciling item between the basic and diluted weighted average common shares outstanding is stock options.

(g) Capital management

The Company considers share capital and net debt, being the sum of long term debt and current liabilities less current assets, as the components of capital to be managed.

The Company's objective in managing its capital is to ensure adequate and appropriate sources of capital are available to execute a capital investment program while maintaining a flexible overall capital structure. Maintaining a flexible capital structure is important due to the inherent risks in oil and gas operations and the volatility of commodity prices.

The Company manages its capital structure by keeping abreast of current and forecast economic conditions and commodity prices, particularly natural gas prices and the cost of oilfield services. Additionally, the Company establishes internal processes to monitor and estimate planned capital expenditures, forecast funds from operations and current and forecast debt levels.

The key measure used by the Company to evaluate its capital structure is the ratio of net debt to funds from operations, defined as cash flow from operating activities before expenditures on asset retirement obligations and change in non-cash working capital from operating activities. This ratio represents the time period required to repay the Company's net debt from funds generated from operations on the assumption there are no further capital expenditures incurred and funds from operations remain constant. The measure is often calculated on a historic annual basis and on an annualized most recent quarter basis to provide a more current view of the Company's capital structure.

At March 31, 2010 net debt, excluding risk management assets or liabilities and the associated future income taxes, was $113.2 million and funds from operations was $15.2 million resulting in a net debt to funds from operations ratio of 1.9:1. The Company is focused on achieving its internal target range for this ratio of approximately 1.5 times.

The Company maintains an active risk management program as an integral part of its capital management strategy to mitigate the volatility in funds from operations resulting from fluctuating commodity prices. The net debt to funds from operations ratio is the key driver in determining whether to maintain or alter the capital structure. To alter the capital structure of the Company, consideration is given to the level of credit available under current banking facilities, the proceeds on disposition of properties, the amount of the planned capital expenditure program and the offering of new common share equity if available on acceptable terms.

NOTE 7: 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 recognized on the balance sheet include cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, long-term debt and the risk management asset or liability. The fair value of financial assets and liabilities that are included on the balance sheet, other than the risk management asset or liability, approximate their carrying amounts due to long-term debt being at a floating interest rate and all other financial assets and liabilities having a short term maturity.

(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, 2010.

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate risk to the extent that bank debt is at a floating rate of interest. If interest rates on prime-based loans had been 100 basis points lower with all other variables held constant, net earnings for the three months ended March 31, 2010 would have been higher by $nil million (March 31, 2009 - $0.1 million), due to lower interest expense.

Interest rate risk is partially mitigated through short-term fixed rate borrowings using bankers' acceptances.

The Company has also entered into an interest rate swap transaction on borrowings through bankers' acceptances in the amount of $40.0 million maturing on May 4, 2011. The bankers' acceptance rate on the transaction will increase in fixed monthly increments of 4.55 basis points for an average fixed rate over two years of 0.94 percent. The effective interest rate over the two year term on $40.0 million of bankers' acceptances will be 0.94 percent plus the applicable stamping fee according to the pricing grid for bankers' acceptances. The fair value of this contract at March 31, 2010 is a loss of $42,000.

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, 2010, the Company had the following financial derivative contracts which were recorded at fair value on the balance sheet at an asset of $3.1 million (December 31, 2009 - loss of $0.4 million) with changes in fair value included in unrealized gain on risk management activities in the statement of earnings.



Contract
Type of Quantity Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
January 2010 - December 2010 (1) Natural Financial 3,500 GJ/d $7.40 Call
Gas
January 2010 - March 2011 Natural Financial 2,000 GJ/d $5.72 fixed
Gas
January 2010 - December 2010 Crude Oil Financial 100 bbls/d $86.40 fixed
January 2010 - December 2010 Crude Oil Financial 100 bbls/d $72.20
floor/$100.00
ceiling
April 2010 - October 2010 Natural Financial 2,000 GJ/d $5.53 fixed
Gas
April 2010 - October 2010 Natural Financial 1,500 GJ/d $4.80 floor
Gas plus 50%
greater than
$4.80
April 2010 - October 2010 (ii) Natural Financial 2,500 GJ/d $4.75 Put
Gas
January 2011 - December 2011 (ii) Natural Financial 2,500 GJ/d $7.14 Call
Gas
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) The 2010 call contract was executed in 2009 to obtain a $6.00 put in
2009 on a costless basis.
(ii) The Company has acquired a natural gas put contract at $4.75 per
gigajoule on 2,500 gigajoules per day for the period April 1, 2010
through October 31, 2010. This put was paid for with the sale of a
natural gas call on 2,500 gigajoules per day at a price of $7.14 per
gigajoule for the period January 1, 2011 through December 31, 2011.


The Company has 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. As at March 31, 2010, the Company had the following physical sales contracts.




Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
January 2010 - December 2010 (i) Natural Physical 3,500 GJ/d $7.15 Call
Gas
January 2010 - March 2011 Natural Physical 1,500 GJ/d $5.74 fixed
Gas
April 2010 - December 2010 Natural Physical 3,000 GJ/d $6.25
Gas floor/$7.47
ceiling
April 2010 - December 2010 Natural Physical 4,000 GJ/d $5.93 floor
Gas plus
50% greater
than $5.93
April 2010 - March 2011 Natural Physical 3,000 GJ/d $6.12 fixed
Gas
April 2010 - March 2011 Natural Physical 2,500 GJ/d $5.73 fixed
Gas
April 2011 - October 2011 Natural Physical 2,000 GJ/d $5.66 fixed
Gas
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(i) The 2010 call contract was executed in 2009 to obtain a $6.00 put in
2009 on a costless basis.


For the three months ended March 31, 2010, the Canadian dollar physical contracts resulted in settlement gains of $2.9 million (March 31, 2009 - $3.0 million) that have been included in petroleum and natural gas sales. For the three months ended March 31, 2010, the financial contracts resulted in gains of $0.1 million (March 31, 2009 - $1.0 million) that have been included in the statement of earnings as a realized gain on risk management activities. If natural gas prices had been higher by $0.10 per mcf, with all other variables held constant, the net change in the unrealized loss on risk management activities in the statement of earnings for the three months ended March 31, 2010 would have been lower by approximately $0.4 million (March 31, 2009 - $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 interest 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 related to 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, 2010 and no bad debt expense was recorded during the quarter.



As at March 31, 2010 the Company's aged receivables are as follows.

March 31, 2010
----------------------------------------------------------------------------
Current (less than 30 days) 15,422
Past due (31-90 days) 8,415
Past due (more than 90 days) 1,611
----------------------------------------------------------------------------
Total 25,448
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(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, 2010.



less than 1 1-2 3-5
Financial liabilities Year Years Years Thereafter
----------------------------------------------------------------------------
Outstanding cheques 5,270 - - -
Accounts payable and accrued
liabilities 58,600 - - -
Risk management liability - -
Long term debt - principal - 80,000 - -
----------------------------------------------------------------------------
Total 63,870 80,000 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NOTE 8: 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: 2010 - $4.9 million; 2011 - $5.1 million; 2012 - $3.8 million; 2013 - $3.0 million; 2014 - $2.5 million.

NOTE 9: CHANGES IN NON-CASH WORKING CAPITAL ITEMS



March 31, December 31,
2010 2009
----------------------------------------------------------------------------
Change in working capital item:
Accounts receivable (9,818) (550)
Prepaid expenses and deposits 821 (2,874)
Accounts payable and accrued liabilities 25,667 (6,073)
----------------------------------------------------------------------------
Total change in non-cash working capital 16,670 (9,497)
Relating to:
Operating activities (4,028) (4,142)
Investing activities 20,698 (5,355)
----------------------------------------------------------------------------
16,670 (9,497)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


CORPORATE INFORMATION

DIRECTORS OFFICERS

David J. Reid David J. Reid
President and Chief Executive Officer President and Chief Executive Officer
Delphi Energy Corp.
Tony Angelidis
Tony Angelidis Senior Vice President Exploration
Senior Vice President Exploration
Delphi Energy Corp. Hugo H. Batteke
Vice President Operations
Harry S. Campbell, Q.C. (3)
Partner Rod A. Hume
Burnet, Duckworth & Palmer LLP Vice President Engineering

Robert A. Lehodey, Q.C. (2) (3) Michael S. Kaluza
Partner Chief Operating Officer
Osler, Hoskin & Harcourt LLP
Brian P. Kohlhammer
Stephen Mulherin (1) Vice President Finance and Chief
Partner Financial
Polar Capital Corporation Officer
CORPORATE OFFICE
Andrew E. Osis (1)
Chief Executive Officer and Director 300, 500 - 4th Avenue S.W.
Multiplied Media Corporation Calgary, Alberta
T2P 2V6
David Sandmeyer (2) Telephone: (403) 265-6171
Director Facsimile: (403) 265-6207
Freehold Royalty Trust Email: info@delphienergy.ca
Website: www.delphienergy.ca
Lamont C. Tolley (1) (2)
Independent Businessman
BANKERS
(1) Member of the Audit Committee
(2) Member of the Reserves Committee National Bank of Canada
(3) Member of the Corporate The Bank of Nova Scotia
Governance and Compensation Committee Alberta Treasury Branches

AUDITORS

KPMG LLP INDEPENDENT ENGINEERS

LEGAL COUNSEL GLJ Petroleum Consultants Ltd.

Osler, Hoskin & Harcourt LLP

TRANSFER AGENT STOCK EXCHANGE LISTING

Olympia Trust Company Toronto Stock Exchange -- DEE

ABBREVIATIONS

bbls barrels mmcf/d million cubic feet per day
bbls/d barrels per day NGL natural gas liquids
mbbls thousand barrels bcf billion cubic feet
mcf thousand cubic feet boe barrels of oil equivalent (6 mcf:1 bbl)
mcf/d thousand cubic feet boe/d barrels of oil equivalent per day
per day
mmcf million cubic feet mmboe million barrels of oil equivalent


Contact Information

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