Delphi Energy Corp.
TSX : DEE

Delphi Energy Corp.

July 31, 2008 09:00 ET

Delphi Energy Achieves Record Production, Strengthens Balance Sheet in Q2 2008

CALGARY, ALBERTA--(Marketwire - July 31, 2008) - Delphi Energy Corp. ("Delphi" or the "Company") (TSX:DEE) is pleased to announce its financial and operational results for the three and six months ended June 30, 2008.

Second Quarter 2008 Highlights

- Achieved record production of 6,202 barrels of oil equivalent per day (boe/d), marking the fifth consecutive quarter of production growth.

- Generated record funds from operations (cash flow) of $20.0 million ($0.29 per share), a 74 percent increase over $11.5 million ($0.17 per share) in the comparative quarter of 2007.

- Reduced net debt to 1.2 times annualized second quarter funds from operations, down from 1.8 times at the end of 2007. Net debt amounted to $97.2 million at the end of the second quarter.

- On July 29, 2008, the Company's lenders increased Delphi's credit facilities to $140 million, up from $125 million.



Financial Highlights ($ thousands except per unit amounts)
Three Months Ended Six Months Ended
June 30 June 30
% %
2008 2007 Change 2008 2007 Change
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Petroleum and natural gas
sales 38,569 24,779 56 70,781 46,753 51
Per boe 68.33 50.63 35 63.45 53.22 19
Funds from operations 19,965 11,469 74 37,024 22,134 67
Per boe 35.37 23.44 51 33.18 25.19 32
Per share - Basic 0.29 0.17 71 0.54 0.34 59
Per share - Diluted 0.28 0.17 65 0.53 0.34 56
Net earnings (loss) 49 797 (94) (690)(10,856) (94)
Per boe 0.09 1.63 (94) (0.62) (12.36) (95)
Per share - Basic - 0.01 (100) (0.01) (0.17) (94)
Per share - Diluted - 0.01 (100) (0.01) (0.17) (94)
Capital invested 7,489 4,311 74 33,987 20,307 67
Disposition of properties 2,950 - 100 2,950 - 100
Net capital invested 4,539 4,311 5 31,037 20,307 53
Acquisition of properties 3,850 10,871 (65) 3,850 10,871 (65)
Total capital 8,389 15,182 (45) 34,887 31,178 (12)


June 30, Dec. 31, %
2008 2007 Change
Debt plus working capital deficiency (1) 97,172 100,658 (3)
Total assets 323,791 311,735 4
Shares outstanding (000's)
Basic 69,120 68,070 2
Diluted 73,862 73,551 -
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(1) excludes risk management asset or liability and the related current
future income tax asset.

Operational Highlights

Three Months Ended Six Months Ended
June 30 June 30
% %
Production 2008 2007 Change 2008 2007 Change
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Natural gas (mcf/d) 31,898 26,967 18 31,838 24,327 31
Crude oil (bbls/d) 368 423 (13) 378 395 (4)
Natural gas liquids (bbls/d) 517 461 12 444 404 10
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Total (boe/d) 6,202 5,379 15 6,129 4,854 26
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MESSAGE TO SHAREHOLDERS

Delphi Energy Corp. continued to achieve record production in the second quarter of 2008, with average daily production increasing for the fifth consecutive quarter. Production increased 43 percent year over year from an average of 4,322 barrels of oil equivalent per day (boe/d) in the first quarter of 2007 to 6,202 boe/d. Natural gas production comprised 87 percent of the Company's overall production which, combined with the increase in natural gas prices, contributed to record funds from operations (cash flow) in the second quarter.

The increase in natural gas prices in the second quarter of 2008 continues a trend which began in September 2007 when AECO was $4.48 per thousand cubic feet (mcf). While partially influenced by the strength of crude oil price increases, natural gas price increases are predominantly based on supply and demand fundamentals in the North American market. During the period, liquefied natural gas (LNG) imports to the United States remained below the historical average and well below record injections in the spring of 2007, as world prices for natural gas provided greater economic returns to offshore U.S. producers. Natural gas injections into storage in the United States through the second quarter resulted in storage levels being approximately 13 percent below last year's levels and approximately one percent below the five-year historical average. The continuing increase in crude oil prices has also had a positive effect on the rise in natural gas prices. During the second quarter, the AECO average daily spot price ranged from $8.55 per mcf early in the quarter to $11.77 per mcf at the end of the quarter.

Crude oil prices maintained momentum in the second quarter of 2008, approaching U.S. $145 per barrel late in the quarter. This increase can be attributed to continued strong global demand, production disruptions, geopolitical unrest in major producing regions and the devaluation of the U.S. dollar. The outlook for oil remains strong despite its lofty heights and growing concerns over the U.S. and global economies. For Canadian producers, the realized price for light crude oil is very similar to the price of West Texas Intermediate due to the Canadian dollar continuing to remain around parity with the U.S. dollar.

Funds from operations in the second quarter of 2008 were a record $20.0 million ($0.29 per basic share), compared to $11.5 million ($0.17 per basic share) in the same period of 2007. This is a result of strong cash netbacks from the increasing natural gas price environment and the Company's significant leverage to increasing natural gas prices. The second quarter of 2008 was the first quarter in the past 10 in which Delphi's risk management program resulted in a realized loss on hedging contracts. For the three months ended June 30, 2008, Delphi recognized approximately $2.8 million in realized losses on Canadian dollar denominated physical contracts, included in natural gas revenue, and recognized a realized loss of approximately $0.4 million on financial contracts and U.S. denominated physical contracts. For the six months ended June 30, 2008 the Company has recognized approximately $1.8 million in realized losses on hedging contracts. Despite the realized loss on risk management activities, Delphi recorded net earnings of $49,000 in the second quarter of 2008 as increased revenues helped offset the loss on hedging contracts.

The Company is focused on ensuring its capital program provides near-term production growth at attractive capital metrics. As a result of spring break-up, the Company's summer drilling program commenced late in the second quarter. Completion of first quarter projects and the late start-up of summer drilling resulted in a capital program for the second quarter of $7.5 million, with one well being drilled and subsequent completion operations continuing into the third quarter. Proceeds from the disposition of a minor property in North East British Columbia of $3.0 million resulted in a net capital program of $4.5 million in the quarter. In addition, the Company provided a $3.9 million cash deposit towards the acquisition of oil and natural gas properties. Excess cash flow over net capital and the cash deposit was used to pay down the Company's net debt.

With the reduction in net debt the Company's financial position continues to strengthen. At June 30, 2008, the Company had net debt, excluding the risk management liability and related current future income tax asset, of $97.2 million, down 11 percent from $109.7 million at March 31, 2008. The reduction in net debt was anticipated due to strong natural gas prices, production growth and a limited capital program in the second quarter because of spring break-up. Based on annualized second quarter funds from operations, Delphi improved its net debt ratio to 1.2 times funds flow from 1.6 times at the end of the first quarter. Net debt includes bank debt plus working capital deficiency excluding the risk management asset or liability and the related current future income tax asset. The annual credit review by the Company's lenders has also been completed. On July 29, 2008 the lenders renewed the production credit facility at $130.0 million and continue to make available the $10.0 million development credit facility. With the recent closing of Delphi's acquisition of properties in the Peace River Arch, described below, the Company has a strong enough cash flow and credit capacity of approximately $37.0 million to potentially expand the capital program.

On June 26, 2008, the Company announced the acquisition of oil and natural gas properties for $38.1 million, after closing adjustments, in the Peace River Arch area of North West Alberta and North East British Columbia. At the same time, the Company announced an equity offering of 6,316,000 common shares at $2.85 per share and 3,530,000 flow-through shares at $3.40 per share for proceeds of approximately $30.0 million ($28.1 million net). The financing transaction closed on July 17, 2008 and the acquisition of the properties was concluded on July 30, 2008. The acquisition was funded by the net proceeds of the equity offering and the Company's credit facilities.

OPERATIONAL REVIEW

As previously indicated, Delphi's second quarter capital program was limited in scope because of restricted surface access associated with spring break-up. The Company drilled and cased one well (1.0 net) in Hythe with completion and tie-in operations continuing into the third quarter. Additional Hythe activities included initiating the completion and tie-in operations on one well (1.0 net) drilled in the first quarter, spudding one well (1.0 net) late in the second quarter and several minor well reactivation / optimization projects. The Company has also received regulatory approval for downspacing on 45 sections of land in the Hythe area allowing two wells per section. The immediate benefits of downspacing include accelerated development of higher quality reservoirs and capital savings associated with location building, rig moves and wellsite equipping and tie-ins. At Bigstone, the Company spudded one well (0.6 net) and initiated several recompletion projects that are ongoing into the third quarter. Minor well, facility and gas gathering system maintenance and optimization projects were initiated at Fontas, East Central Alberta and North East British Columbia.

The Company is currently operating two drilling rigs at Hythe and Bigstone. At Hythe, the Company plans to drill six wells (6.0 net) during the third quarter on a range of prospects, including a shallow Doe Creek oil play, conventional multi-zone Cretaceous gas sands and horizontal wells targeting the Bluesky, Cadomin, Dunvegan and Nikanassin formations. The initial round of drilling will focus on conventional vertical wells to collect the necessary information to optimize future development of the area and to assist in fine-tuning the drilling and completion operations for two horizontal wells to be drilled later in the third quarter. Preliminary results are encouraging, and the Company looks forward to providing specific results as they become available. Looking beyond the current capital program, the Company has initiated the process of licensing an additional 11 horizontal wells (8.3 net) that could be drilled in the fourth quarter of 2008 or first quarter of 2009.

At Bigstone, the Company is drilling the first of two wells (1.1 net) planned for the third quarter. In addition, three recompletions are in progress to evaluate new fracture stimulation technologies in existing pools and pool extensions. Once again, preliminary results have been encouraging and continued success will result in a major recompletion program on existing wellbores and additional drilling to extend the current pool boundaries.

As noted, Delphi's acquisition of oil and natural gas properties in the Peace River Arch area of North West Alberta and North East British Columbia closed on July 30, 2008, adding approximately 650 boe/d of predominantly natural gas. At closing, the Company elected to participate in drilling one well (0.1 net) in Valhalla, a recompletion attempt on one well (0.1 net) in Pouce Coupe and a three well (0.7 net) reactivation program in the Clayhurst area. Multiple reactivation and optimization projects are in the planning stage, with execution planned for late Q3 or early Q4 2008. In addition, the technical teams have begun to assemble an inventory of drillable prospects for execution in late Q4 2008 or early Q1 2009.

OUTLOOK

Positive drilling results and continued production growth, coupled with improved natural gas prices and secure financial resources, continue to favorably influence Delphi's capital investment decisions. Delphi expects to spend a net capital program of approximately $60.0 million in 2008 - 81 to 84 percent of anticipated 2008 cash flow - drilling 20 to 25 wells. The majority of the capital will be directed towards drilling and completion activities in the Bigstone, Noel and Hythe core areas, with minimal capital being directed at the recently acquired assets. In Hythe, the Company will be pursuing development of the resource potential in the Bluesky, Cadomin, Dunvegan and Nikanassin formations. The Company holds approximately 86 sections of land in the area with an average working interest of 72 percent.

Production guidance for 2008 has been increased to between 6,350 and 6,550 boe/d. This increase is primarily a result of the acquisition of oil and natural gas properties in the Peace River Arch. Delphi's guidance for the third quarter of 2008 has been established at an average of 6,400 to 6,600 boe/d, a 14 percent increase over the third quarter of 2007.

Funds from operations for 2008 are now forecast to be between $71.5 million ($0.97 per share) and $74.0 million ($1.01 per share), up from $60.0 to $65.0 million ($0.87 to $0.95 per share) as a result of increased production from the acquisition and expected higher average natural gas prices. The Company has a year-end net debt target of less than $100.0 million on an average AECO price of $8.50 per mcf for 2008. Delphi's independent reserves evaluator, GLJ Petroleum Consultants Ltd., recently revised its future price forecast. Based on this updated price forecast the net asset value of the Company, including the recent acquisition of oil and natural gas properties, discounted at 8 per cent would increase to over $4.00 per share from $2.91 per share, as calculated and reported in the Company's 2007 annual report.

Delphi has a significant inventory of defined and repeatable conventional prospects concentrated within its core areas of operation. The multi-zone nature of Delphi's core areas and recently approved downspacing provisions contribute to the Company's large development drilling inventory. Delphi continues to pursue emerging technologies to enhance recoveries of existing reserves as well as untapped natural gas resources within the Company's current land holdings. Delphi is fully engaged in an active third and fourth quarter capital program and looks forward to reporting further positive results in the coming quarters.

CONFERENCE CALL

A conference call is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Thursday, July 31, 2008. The conference call number is 1-866-300-7687 or 416-641-6121. A brief presentation by Brian Kohlhammer, VP Finance & CFO and Michael Kaluza, Chief Operating Officer 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 August 7, 2008. To access the replay, dial 1-800-408-3053 or 416-695-5800. The passcode is 3265797.Delphi's second quarter 2008 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.

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

More particularly and without limitation, this press release contains forward looking statements and information relating to the Company's risk management program, petroleum and natural gas production, future funds flow from operations, capital programs, natural gas prices 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.

A barrel of oil equivalent (boe), derived by converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil, may be misleading, particularly if used in isolation. A boe conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Non-GAAP Measures. The MD&A contains the terms "funds from operations", "funds from operations per share" 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.

MANAGEMENT DISCUSSION AND ANALYSIS

(all tabular amounts are expressed 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 and six months ended June 30, 2008 and 2007 and should be read in conjunction with the audited financial statements and accompanying notes for the year ended December 31, 2007. The discussion and analysis has been prepared as of July 24, 2008.

OPERATION AND FINANCIAL HIGHLIGHTS

Delphi Energy Corp. continued to achieve production growth in the second quarter of 2008 with average daily production increasing on a quarter over quarter basis for the fifth consecutive quarter from an average of 4,322 barrels of oil equivalent per day (boe/d) in the first quarter of 2007 to 6,202 boe/d, an increase of 43 percent over the period. Second quarter sales volumes represent record quarterly production. Natural gas production comprised 87 percent of the Company's average production which coupled with the increase in natural gas prices contributed to record funds from operations (cash flow) in the second quarter.

Funds from operations in the second quarter of 2008 were a record $20.0 million or $0.29 per basic share, compared to $11.5 million or $0.17 per basic share in the second quarter of 2007, as a result of strong cash netbacks from an increasing natural gas price environment and the benefit of the Company's significant leverage to increasing natural gas prices. The second quarter of 2008 was the first quarter in the past 10 in which Delphi's risk management program resulted in a realized loss on hedging contracts. For the three months ended June 30, 2008, Delphi recognized approximately $2.8 million in realized losses on Canadian dollar denominated physical contracts, included in natural gas revenue, and recognized a realized loss of approximately $0.4 million on financial contracts and U.S. dollar denominated physical contracts. For the six months ended June 30, 2008 the Company has recognized approximately $1.8 million in realized losses on hedging contracts.

The Company is focused on ensuring its capital program provides near term production growth at attractive capital metrics. As a result of spring break-up, the Company's summer drilling program commenced late in the second quarter. Completion of first quarter projects and the late start-up of summer drilling resulted in a capital program for the second quarter of $7.5 million, with one well being drilled with completion operations continuing into the third quarter. Proceeds on the disposition of a minor property in North East British Columbia of $3.0 million resulted in a net capital program of $4.5 million in the quarter. In addition, the Company provided a $3.9 million cash deposit towards the acquisition of oil and natural gas properties. Excess cash flow over net capital and the cash deposit was used to pay down the Company's net debt.

With the reduction in net debt, the Company's financial position continued to strengthen in the second quarter of 2008. At June 30, 2008, the Company had net debt, excluding the risk management liability and the related current future income taxes of $97.2 million, down from $109.7 million at March 31, 2008. The reduction in net debt was anticipated due to strong natural gas prices, production growth and a planned lower capital program in the second quarter due to spring break-up. On an annualized second quarter funds from operations basis, Delphi improved its net debt to funds flow ratio to 1.2 times from 1.6 times at the end of the first quarter. Net debt includes bank debt plus working capital deficiency excluding the risk management asset or liability and the related current future income tax asset. The annual credit review by the Company's lenders has also been completed. As of July 29, 2008, the lenders have renewed the production credit facility at $130.0 million and continue to make available the $10.0 million development credit facility. With the recent closing of the acquisition, described below, the Company has strong cash flow and credit capacity of approximately $37.0 million to potentially expand the capital program.

On June 26, 2008, the Company announced the proposed acquisition of oil and natural gas properties for $38.1 million, after closing adjustments, in the Peace River Arch area of North West Alberta and North East British Columbia. At the same time, the Company also announced an equity offering of 6,316,000 common shares at $2.85 per share and 3,530,000 flow-through shares at $3.40 per share for proceeds of approximately $30.0 million (net proceeds of $28.1 million). The financing transaction was closed on July 17, 2008 and subsequently the acquisition of the properties was concluded on July 30, 2008. The acquisition was funded by the net proceeds of the equity offering and the Company's credit facilities.



BUSINESS ENVIRONMENT

Benchmark Prices

Three Months Ended Six Months Ended
June 30 June 30
% %
2008 2007 Change 2008 2007 Change
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Natural Gas
NYMEX (US $/mmbtu) 10.69 7.53 42 9.39 7.36 28
AECO (CDN $/mcf) 10.22 7.09 44 9.10 7.25 26
Crude Oil
West Texas Intermediate
(US $/bbl) 123.98 65.02 91 110.94 61.63 80
Edmonton Light (CDN $/bbl) 126.07 73.78 71 111.79 70.84 58
Foreign Exchange Rate
Canadian to US dollar 1.01 1.10 (8) 1.01 1.13 (11)
US to Canadian dollar 0.99 0.91 9 0.99 0.88 13
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Natural Gas

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

In the second quarter of 2008, natural gas prices continued to increase, a trend which had begun from the lows of $4.48 per thousand cubic feet (mcf) for AECO in September 2007. While partially influenced by the strength of crude oil price increases, natural gas price increases are predominantly based on supply and demand fundamentals in the North American market. In the first quarter, with global natural gas prices considerably higher than the prices in the United States, LNG imports to the U.S. throughout the winter were less than average and significantly less than the peak imports during the summer of 2007. Cold winter weather persisted to the end of March 2008 in the major natural gas consuming regions of central Canada and the northeast United States. By the end of the natural gas withdrawal season, an increase of over 400 billion cubic feet had been taken out of natural gas storage compared to the previous withdrawal season. Natural gas in storage in the United States had been drawn down below five year average levels, a key measure of supply. In the second quarter, LNG imports to the United States continued to remain below the historical average, also well below the record injections in the spring of 2007, as world prices for natural gas provided greater economic returns to offshore U.S. producers. Natural gas injections into storage in the United States through the second quarter have resulted in storage levels being approximately 13 percent below last year's levels at this time and approximately one percent below the five year historical average. The continuing increase in crude oil prices has also had a positive affect on the rise in natural gas prices. During the second quarter, the AECO average daily spot price ranged from a low of $8.55 per mcf early in the quarter to a high of $11.77 per mcf at the end of the second quarter. For internal forecasting purposes, looking toward the remainder of 2008, Delphi anticipates AECO natural gas prices will now average approximately $8.00 to $8.50 per mcf.

Crude Oil

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

The second quarter of 2008 maintained the momentum for crude oil prices which continued to increase, approaching U.S. $145.00 per barrel late in the second quarter, on continued strong global demand, production disruptions, never ending geopolitical unrest in major producing regions and the devaluation of the U.S. dollar. The outlook for oil remains strong despite its lofty heights and growing concerns over the U.S. and global economies. For Canadian producers the realized price for light crude oil is very similar to the price of West Texas Intermediate due to the Canadian dollar continuing to remain around parity with the U.S. dollar. For internal forecasting purposes, Delphi now anticipates WTI to average between U.S. $100.00 to $110.00 per barrel and the Canadian dollar to remain at, or near, par with the U.S. dollar throughout 2008.

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 in the refining process. The average differential in the second quarter of 2008 was $21.43 per barrel compared to $21.02 per barrel in the second quarter of 2007. The increase in the average differential, offset by higher light oil prices, resulted in Bow River crude prices averaging $104.63 per barrel compared to $50.91 per barrel in the second quarter of 2007.

Industry Cost of Services

For oil and gas producers lower costs of services existed through the 2007/2008 winter drilling season with a significant improvement in the skill level of the oilfield crews and fewer equipment breakdowns due to maintenance of the equipment through the summer and fall of 2007. The higher crude oil and natural gas prices experienced in 2008 so far are expected to lead to increased demand for oilfield services and equipment and higher costs of services heading into the busy winter drilling season.

FINANCIAL STRATEGY

The Company maintains an active risk management program as an integral part of its overall financial strategy to mitigate volatility in funds from operations resulting from fluctuating commodity prices. The strategy takes 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 play. Delphi's risk management program consists of both fixed price contracts and costless collars, which provide downside protection and the opportunity to share in the upside if market prices increase above the floor price for the costless collar. If market prices are above fixed price contracts or the ceiling price of costless collars, the Company would continue to achieve its downside protection while realizing losses on these hedging contracts. Currently, Delphi has hedged approximately 42 percent of its before-royalty natural gas production at a predominantly AECO based average floor price of $7.99 per mcf for the remaining two quarters of 2008. Delphi has a strategy of hedging between 40 to 50 percent of its natural gas production as long as demand/supply fundamentals indicate volatile markets in the future. As the Company's financial condition improves and/or demand/supply fundamentals move toward equilibrium or reduced supply, Delphi will manage its hedging program accordingly to take advantage of exposure to higher natural gas commodity prices.

Delphi continues to direct efforts at maintaining or reducing its controllable costs. Increasing production at its various operating fields through Company owned infrastructure reduces fixed costs on a per boe basis and improves netbacks. Field operators are encouraged to undertake preventative maintenance on field infrastructure and wellsite equipment to minimize production downtime and prevent significant operating costs associated with repairs. In a cost environment which continues to be affected by quality labour shortages and increasing costs of supplies, the Company strives to achieve improvement in its costs of production and at a minimum maintain current production costs.

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

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

Delphi continues to be focused on reducing its leverage and improving its financial flexibility through net debt reduction or increasing funds flow growth resulting in a lower net debt to annualized quarterly funds from operations ratio. The Company is focused on achieving its internal target range for this ratio of 1.3 to 1.5 times.



SELECTED INFORMATION

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

Jun. 30 Mar. 31 Dec. 31 Sept. 30 Jun. 30
2008 2008 2007 2007 2007
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Production
Natural gas (mcf/d) 31,898 31,777 30,610 28,196 26,967
Oil (bbl/d) 368 387 346 579 423
Natural gas liquids (bbl/d) 517 372 420 422 461
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Barrels of oil equivalent
(boe/d) 6,202 6,056 5,868 5,700 5,379
Financial
($ thousands except per unit
amounts)
Petroleum and natural gas
revenue 38,569 32,212 26,632 24,548 24,779
Funds from operations 19,965 17,059 13,747 12,600 11,469
Per share - basic 0.29 0.25 0.20 0.19 0.17
Per share - diluted 0.28 0.25 0.20 0.18 0.17
Net earnings (loss) 49 (739) 1,732 (1,348) 797
Per share - basic - (0.01) 0.03 (0.02) 0.01
Per share - diluted - (0.01) 0.03 (0.02) 0.01
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Mar. 31 Dec. 31 Sept. 30
2007 2006 2006
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Production
Natural gas (mcf/d) 21,658 24,919 25,403
Oil (bbl/d) 366 388 444
Natural gas liquids (bbl/d) 346 441 412
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Barrels of oil equivalent (boe/d) 4,322 4,982 5,090
Financial
($ thousands except per unit amounts)
Petroleum and natural gas revenue 21,974 22,928 21,587
Funds from operations 10,665 11,817 10,902
Per share - basic 0.17 0.19 0.18
Per share - diluted 0.17 0.19 0.18
Net earnings (loss) (11,653) 290 658
Per share - basic (0.18) - 0.01
Per share - diluted (0.18) - 0.01
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Production for the last eight consecutive quarters reflects the following events: The change in production volumes from the third quarter of 2006 to the first quarter of 2007 was due to a reduced capital program leading to production declines and the disposition of several minor, non-operated properties in the latter half of 2006. In 2007 success at Bigstone, Alberta throughout the year and Noel, British Columbia in the third quarter complemented the mid-year start up of production at Tower Creek, Alberta resulting in consistent quarter over quarter production growth. Production increased in the first half of 2008 due to a successful winter program in the core areas. Revenue and funds from operations reflect the cycle of natural gas prices and production volumes.

Natural gas prices over the past two years have reflected the cyclical nature of demand. Higher prices in the winter months, reflecting demand for heating, weaken through the summer months as production is placed in storage for the upcoming heating season demand. Natural gas prices in the second quarter of 2008 did not follow the cyclical trend expected, as prices continued to increase coming out of the winter heating season due to concerns over natural gas supply in storage and the continued increase in crude oil prices. In the first quarter of 2007, net earnings were significantly reduced by the impairment of goodwill in the amount of $12.1 million. In the first half of 2008, the Company achieved record cash flow of $37.0 million or $0.54 per share, due to continued production growth and increasing natural gas and crude oil prices.




DRILLING RESULTS

Three Months Ended Six Months Ended
June 30, 2008 June 30, 2008
Gross Net Gross Net
----------------------------------------------------------------------------
Natural gas wells 1.0 1.0 11.0 8.0
Oil wells - - 1.0 1.0
----------------------------------------------------------------------------
Total wells 1.0 1.0 12.0 9.0
Success rate (%) 100 100 100 100
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The Company had another successful quarter with the drill bit resulting in a
drilling success rate of 100 percent. The Company has in excess of one
hundred drilling locations identified within its core areas of operations.

CAPITAL INVESTED

Three Months Ended Six Months Ended
June 30 June 30
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Land - 13 (100) - 13 (100)
Seismic - 85 (100) 3 214 (99)
Drilling and completions 4,115 2,100 96 22,611 12,744 77
Equipping and facilities 2,321 1,822 27 9,248 5,800 59
Capitalized expenses 1,030 195 428 1,667 1,165 43
Other 23 96 (76) 458 371 23
----------------------------------------------------------------------------
Capital invested 7,489 4,311 74 33,987 20,307 67
Disposition of properties (2,950) - 100 (2,950) - 100
----------------------------------------------------------------------------
Net capital invested 4,539 4,311 5 31,037 20,307 53
----------------------------------------------------------------------------
Acquisition of properties 3,850 10,871 (65) 3,850 10,871 (65)
Total capital 8,389 15,182 (45) 34,887 31,178 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As a result of spring break-up, the Company's summer drilling program commenced late in the second quarter. Completion of first quarter projects and the late start-up of summer drilling resulted in a gross capital program for the second quarter of $7.5 million. Proceeds on the disposition of a minor property in North East British Columbia of $3.0 million resulted in a net capital program of $4.5 million in the quarter. In addition the Company was required to provide a $3.9 million cash deposit towards the acquisition of oil and gas properties which closed on July 30, 2008.

Year to date, the Company has directed the majority of capital to the drilling and completion of six wells at Bigstone, four wells at Hythe in Alberta and two wells at Noel, British Columbia.



PRODUCTION

Three Months Ended Six Months Ended
June 30 June 30
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Natural gas (mcf/d) 31,898 26,967 18 31,838 24,327 31
Crude oil (bbls/d) 368 423 (13) 378 395 (4)
Natural gas liquids (bbls/d) 517 461 12 444 404 10
----------------------------------------------------------------------------
Total (boe/d) 6,202 5,379 15 6,129 4,854 26
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production for the three months ended June 30, 2008 (the "Quarter") averaged 6,202 boe/d representing an increase of 15 percent over the comparative period primarily due to the successful drilling and optimization programs at Bigstone, Hythe and other core areas. Delphi continues to deliver quarter over quarter organic growth and is well positioned for future production increases within its core assets. The Company's production portfolio for the six months ended June 30, 2008 was weighted 87 percent to natural gas, six percent to crude oil and seven percent to natural gas liquids.

Crude oil production was 13 percent lower for the three months ended June 30, 2008 primarily due to downtime in east central Alberta and natural production declines in the Bigstone area.

The increase in production of natural gas liquids is consistent with the increase in natural gas volumes.



REALIZED SALES PRICES

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
AECO ($/mcf) 10.22 7.09 44 9.10 7.25 26
Heating content and
marketing ($/mcf) 0.64 0.65 (2) 0.54 0.69 (22)
Gain(loss) on physical
contracts ($/mcf) (0.97) 0.45 - (0.28) 0.88 -
Gain(loss) on financial
contracts ($/mcf) (0.12) 0.01 - (0.03) 0.01 -
----------------------------------------------------------------------------
Realized gas price ($/mcf) 9.77 8.20 19 9.32 8.83 6

Realized oil price ($/bbl) 116.36 59.24 96 100.27 56.39 78

Realized natural gas liquids
price ($/bbl) 103.10 56.61 82 96.14 52.91 82
----------------------------------------------------------------------------
Total realized sales price
($/boe) 68.33 50.63 35 63.45 53.22 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and six months ended June 30, 2008, Delphi had a realized loss from its risk management program of $3.2 million and $1.8 million, respectively. For the quarter, the realized loss was $1.09 per mcf with physical contracts contributing $0.97 per mcf and financial contracts contributing $0.12 per mcf. For the six months ended June 30, 2008, the average realized gas price was six percent higher than the comparable period due to an increase in the price of natural gas.

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

The following table outlines the premium (discount) Delphi realized on natural gas prices compared to the average quarterly AECO price due to the risk management program, quality of production and gas marketing arrangements. The second quarter of 2008 was the first quarter in the past ten quarters in which Delphi realized a net hedging loss in its risk management program.



Jun. 30 Mar. 31 Dec. 31 Sept. 30
2008 2008 2007 2007
----------------------------------------------------------------------------
Natural Gas Price
Delphi realized ($/mcf) 9.77 8.91 7.61 7.20
AECO average ($/mcf) 10.22 7.97 6.15 5.14
Premium(discount) to AECO (4%) 12% 24% 40%
Hedging gain (loss) ($000's) (3,153) 1,371 2,996 3,875
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Jun. 30 Mar. 31 Dec. 31 Sept. 30
2007 2007 2006 2006
----------------------------------------------------------------------------
Natural Gas Price
Delphi realized ($/mcf) 8.20 9.61 8.41 7.20
AECO average ($/mcf) 7.06 7.40 6.90 6.04
Premium(discount) to AECO 16% 30% 22% 19%
Hedging gain (loss) ($000's) 1,130 2,780 2,987 3,532
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Delphi's oil production is slightly better than medium grade oil; therefore the Company's average price fluctuates with the quality differential. Increased production of light oil at Bigstone continues to high grade the Company's quality of crude oil resulting in pricing more reflective of light oil. Realized natural gas liquids prices have increased due to the increase in the price received for condensate, the primary component of the Company's natural gas liquid production.

RISK MANAGEMENT ACTIVITIES

Delphi enters into both financial and physical commodity contracts as part of its risk management program to manage commodity price fluctuations designed to ensure sufficient cash is generated to fund its capital program particularly when commodity prices are extremely volatile. Delphi makes a concerted effort to hedge production volumes at prices greater than the upper limit of the historical three to five year AECO price range of $5.25 to $8.40 per mcf and is quick to react to price aberrations such as those experienced at the end of 2005. Another component of the risk management program is to layer fixed price contracts in over a period of time, as opposed to locking in a significant portion of volumes at any one point in time, to take advantage of unexpected price spikes. For natural gas production, Delphi has hedged approximately 42 percent of its before-royalty natural gas production at a predominately AECO based average floor price of $7.99 per mcf for the remainder of 2008.

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

The Company recognized an unrealized non-cash loss of $7.6 million on financial contracts and US dollar denominated physical contracts in the first half of 2008. The fair values of these contracts are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the contracts outstanding at the end of the period having regard to forward prices and market values provided by independent sources. Due to the inherent volatility in commodity prices, actual amounts realized may differ from these estimates.

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




Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
April 2008 -
October 2008 Natural Gas Physical 4,000 GJ/d $7.21 fixed
April 2008 -
October 2008 Natural Gas Physical 3,000 GJ/d $7.61 fixed
April 2008 -
October 2008 Natural Gas Physical 2,000 mmbtu/d U.S. $8.00 fixed
April 2008 -
October 2008 Natural Gas Financial 1,000 GJ/d $8.07 fixed
April 2008 -
October 2008 Natural Gas Financial 1,000 GJ/d $8.07 fixed
April 2008 - $7.75 floor/
October 2008 Natural Gas Financial 1,000 GJ/d $9.55 ceiling
April 2008 -
December 2008 Natural Gas Physical 2,000 GJ/d $7.82 fixed
April 2008 -
March 2009 Natural Gas Physical 2,000 GJ/d $7.30 fixed
November 2008
- March 2009 Natural Gas Physical 4,000 GJ/d $7.46 fixed
November 2008
- March 2009 Natural Gas Financial 2,000 GJ/d $7.62 fixed
November 2008 $7.00 floor/
- March 2009 Natural Gas Physical 2,000 GJ/d $8.05 ceiling
November 2008
- March 2009 Natural Gas Physical 2,000 mmbtu/d U.S. $9.00 fixed
November 2008 $8.00 floor/
- March 2009 Natural Gas Financial 1,000 GJ/d $11.07 ceiling
April 2009 -
October 2009 Natural Gas Physical 1,000 GJ/d $7.08 fixed
April 2009 - $8.25 floor/
October 2009 Natural Gas Physical 2,000 GJ/d $10.00 ceiling
April 2009 -
October 2009 Natural Gas Physical 1,000 mmbtu/d U.S. $8.18 fixed
April 2009 -
October 2009 Natural Gas Physical 2,000 GJ/d $8.59 fixed
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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.

The combination of the significant increase in natural gas prices over the past three months and the Alberta royalty changes, which become effective January 1, 2009, have caused the Company to be very cautious in executing additional risk management contracts for 2009. Based on past natural gas pricing cycles, the Company would have normally executed additional contracts at forward prices which were available over the past several months. However, in light of the possibility that natural gas prices may increase even further and the proposed new royalty rates which will result in a greater percentage of the prices going to the Alberta government, the Company is concerned about the effect this combination may have on the Company's natural gas netbacks on hedged volumes if natural gas prices do increase substantially going forward. Evaluation of the proper time and form of contract continues.



REVENUE

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
Natural gas 28,373 20,100 41 54,002 38,828 39
Crude oil 3,897 2,280 71 6,898 4,032 71
Natural gas liquids 4,851 2,375 104 7,769 3,869 101
Sulphur 1,783 - 100 2,299 - 100
Realized gain (loss) on
risk management (335) 24 - (187) 24 -
----------------------------------------------------------------------------
Total 38,569 24,779 56 70,781 46,753 51
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The increase in revenue over the comparative periods is attributed to the increase in production volumes and the increase in crude oil and natural gas prices. For the three months ended June 30, 2008 revenue increased 56 percent over the comparative period due to a 15 percent increase in production volumes and a 19 percent increase in the realized natural gas price.



ROYALTIES

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
Total 8,346 3,843 117 14,208 7,051 102
Per boe 14.79 7.85 88 12.74 8.03 59
Percent of total revenue
including hedges 21.5 15.5 39 20.0 15.1 33
Percent of total revenue
excluding hedges 20.0 16.3 23 19.6 16.4 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company pays royalties to provincial governments (Crown), freeholders, which can be individuals or companies, and other oil and gas operators that own surface or mineral rights. Crown royalty rates are calculated on a sliding scale based on commodity prices and individual well production rates. Royalty rates can change due to price fluctuations or changes in production volumes on a well by well basis subject to a minimum and maximum rate restriction ascribed by the Crown. For the three months ended June 30, 2008, royalties as a percentage of revenue increased over the comparative period due to Tower Creek coming off royalty holiday, hedge losses realized compared to gains in comparative period and increased commodity prices realized in the quarter. Delphi is expecting royalties as a percentage of revenue, before hedging, to be between 20 and 22 percent in 2008.



OPERATING EXPENSES

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
Total 6,168 4,798 29 11,321 8,635 31
Per boe 10.93 9.80 12 10.15 9.83 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Operating expenses on a per boe basis for the three and six month period ended June 30, 2008, increased 12 percent and three percent respectively, over the comparative periods. The increase in operating costs is primarily due to a high level of workover and maintenance activity in 2008 compared to 2007. In addition, the Company incurred significant cost adjustments for prior years from the facility operator on the newly acquired Hythe property. Delphi expects operating costs to be $8.50 to $9.00 per boe for the remainder of 2008.



TRANSPORTATION EXPENSES

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
Total 1,548 1,902 (19) 3,125 3,231 (3)
Per boe 2.74 3.89 (29) 2.80 3.68 (24)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

On a per boe basis, transportation costs for the three and six months ended June 30, 2008 decreased by 29 percent and 24 percent over the comparative period. The decrease is attributed to higher production volumes with fixed firm service fees for production and lower transportation costs at Hythe, Alberta than the Bigfoot area which was disposed of in the third quarter of 2007. Effective November 1, 2007 Delphi transferred a portion of its excess processing and transmission capacity to third party producers resulting in further reductions in transportation costs.



GENERAL AND ADMINISTRATIVE

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
General and administrative
costs 2,982 1,519 96 4,986 3,225 55
Overhead recoveries (176) (110) 60 (544) (357) 52
Salary allocations (1,462) (555) 163 (2,124) (1,255) 69
----------------------------------------------------------------------------
Net 1,344 854 57 2,318 1,613 44
Per boe 2.38 1.74 37 2.08 1.84 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On a per boe basis, general and administrative (G&A) costs for the three and six months ended June 30, 2008 increased 37 percent and 13 percent over the comparative periods in 2007. The increase is due to additional technical and administrative staff hired year over year. As a result of high levels of activity for Delphi and for the industry as a whole, the costs associated with hiring, compensating and retaining employees and consultants have risen. Delphi is committed to continuing to deliver strong growth and believes a strong technical team is paramount to achieve this goal. Delphi expanded its team in 2008 with the addition of two senior exploitation engineers and a new land manager. For the remainder of 2008, Delphi is expecting G&A per boe to decrease slightly as additional production volumes are achieved.



STOCK-BASED COMPENSATION

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
Total 260 101 158 492 314 57
Per boe 0.46 0.21 120 0.44 0.36 23
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees, directors and key consultants of the Company. The fair value of all options granted is estimated at the date of grant using the Black-Scholes option pricing model. The non-cash compensation expense for the three and six months ended June 30, 2008, increased 120 percent and 23 percent due to the granting of additional stock options during the period. During the three and six months ended June 30, 2008, Delphi capitalized $0.5 million and $0.8 million of stock-based compensation associated with exploration and development activities.



INTEREST

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
Total 1,198 1,913 (37) 2,785 4,089 (32)
Per boe 2.12 3.91 (46) 2.50 4.65 (46)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and six months ended June 30, 2008, interest expense on a per boe basis decreased 46 percent over the comparable periods due to lower interest costs from reduced interest rates and higher production volumes. Delphi anticipates interest per boe will decrease throughout the year as debt is paid down and production is brought on stream.



DEPLETION, DEPRECIATION AND ACCRETION

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
Depletion and depreciation 14,859 11,984 24 29,867 21,359 40
Accretion expense 152 164 (7) 295 322 (8)
----------------------------------------------------------------------------
Total 15,011 12,148 24 30,162 21,681 39
Per boe 26.60 24.82 7 27.04 24.68 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Depletion, depreciation, and accretion per boe for the three and six months ended June 30, 2008 increased seven percent and 10 percent due to higher cost proved reserve additions. With the Hythe property and success at Bigstone and Noel, Delphi is in an excellent position to add proved reserves at metrics below the Company's current depletion rate. The increase in total depletion and depreciation versus the comparative periods is a result of increased production levels and a higher per boe rate.

Accretion expense of asset retirement obligations relates to the passing of time until the Company estimates it will retire its assets and restore the asset locations to a condition which meets or exceeds environmental standards. Due to the long term nature of certain assets of the Company, this accretion expense is estimated to extend over a term of three to 20 years. The Company uses a credit adjusted risk-free rate of eight 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 June 30, 2008 decreased seven percent over the comparative period due to a lower asset retirement obligation from dispositions.



TAXES

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current - - - -
Future (reduction) (34) 464 - (520) 740 -
----------------------------------------------------------------------------
Total (34) 464 - (520) 740 -
Per boe (0.06) 0.71 - (0.47) 0.71 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The provision for income taxes in the financial statements for the three months ended June 30, 2008, was a reduction of $34,000. For the six months ended June 30, 2008, the provision for income taxes was a reduction of $0.5 million. Delphi does not anticipate it will be cash taxable until late 2009.



FUNDS FROM OPERATIONS

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
Net earnings (loss) 49 797 (94) (690) (10,856) (94)
Non-cash items:
Depletion, depreciation
and accretion 15,011 12,148 24 30,162 21,681 39
Impairment of goodwill - - - - 12,100 (100)
Unrealized loss on risk
management activities 4,679 (2,041) - 7,580 (1,845) -
Stock-based
compensation expense 260 101 158 492 314 57
Future income taxes
(reduction) (34) 464 - (520) 740 -
----------------------------------------------------------------------------
Funds from operations 19,965 11,469 74 37,024 22,134 67
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and six months ended June 30, 2008, funds from operations were $20.0 million ($0.29 per basic share) and $37.0 million ($0.54 per basic share) compared to $11.5 million ($0.17 per basic share) and $22.1 million ($0.34 per basic share).

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

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



Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
Funds from operations:
Non-GAAP 19,965 11,469 74 37,024 22,134 67
Settlement of asset
retirement obligations - (255) (100) - (446) (100)
Change in non-cash
working capital (2,491) 3,720 - (11,719) 5,636 -
----------------------------------------------------------------------------
Cash flow from
operating
activities: GAAP 17,474 14,934 17 25,305 27,324 (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NET EARNINGS (LOSS)

For the three and six months ended June 30, 2008, Delphi recorded net earnings of $49,000 and a net loss of $0.7 million, respectively. Net earnings were adversely affected by non-cash items such as depletion, depreciation and accretion, unrealized loss on risk management activities, stock-based compensation, impairment provisions and future income taxes. These non-cash items represent the majority of the significant difference between funds from operations and the net loss.



NETBACK ANALYSIS

Three Months Ended Six Months Ended
June 30 June 30
2008 2007 % Change 2008 2007 % Change
----------------------------------------------------------------------------
Barrels of oil equivalent
($/boe)
Realized sales price 68.33 50.63 35 63.45 53.22 19
Royalties, net of ARTC 14.79 7.85 88 12.74 8.03 59
Operating expenses 10.93 9.80 12 10.15 9.83 3
Transportation 2.74 3.89 (29) 2.80 3.68 (24)
----------------------------------------------------------------------------
Operating netback 39.87 29.09 37 37.76 31.68 19
G&A 2.38 1.74 37 2.08 1.84 13
Interest 2.12 3.91 (46) 2.50 4.65 (46)
----------------------------------------------------------------------------
Cash netback 35.37 23.44 51 33.18 25.19 32
Unrealized loss (gain)on
financial contracts 8.28 (4.17) - 6.79 (2.10) -
Stock-based compensation
expense 0.46 0.21 120 0.44 0.36 22
Depletion, depreciation and
accretion 26.60 24.82 7 27.04 24.68 10
Impairment of goodwill - - - - 13.77 (100)
Future income taxes
(reduction) (0.06) 0.95 - (0.47) 0.84 -
----------------------------------------------------------------------------
Net earnings (loss) 0.09 1.63 (94) (0.62) (12.36) (95)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Approximately 87 percent of Delphi's production is natural gas and therefore
Delphi's cash netbacks are primarily driven by the price received for
natural gas.

LIQUIDITY AND CAPITAL RESOURCES

Funding

Three Months Six Months
Ended Ended
June 30, 2008 June 30, 2008
----------------------------------------------------------------------------
Sources:
Funds from operations 19,965 37,024
Disposition of petroleum and natural gas
properties 2,950 2,950
Issue of common shares, net of issue costs 971 1,349
----------------------------------------------------------------------------
23,886 41,323

Uses:
Cash 529 529
Capital expenditures 7,489 33,987
Acquisition of petroleum and natural gas
properties 3,850 3,850
Change in non-cash working capital 12,518 10,957
----------------------------------------------------------------------------
24,386 49,323
----------------------------------------------------------------------------
Increase in bank debt 500 8,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the six months ended June 30, 2008 Delphi funded its capital program through funds from operations and increased its bank debt to reduce the working capital deficiency.

Share Capital

At June 30, 2008, the Company had 69.1 million common shares outstanding (June 30, 2007 - 68.1 million). The common shares of Delphi trade on the TSX under the symbol DEE. The following table summarizes outstanding share data for the three and six months ended June 30, 2008.



Three Months Six Months
Ended Ended
June 30, 2008 June 30, 2008
----------------------------------------------------------------------------
Weighted Average Common Shares
Basic 68,833 68,555
Diluted 70,421 70,143
Trading Statistics (1)
High 3.43 3.43
Low 1.92 1.69
Average daily, volume 271,638 236,419
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Trading statistics based on closing price


As at July 24, 2008 the Company had 79.1 million common shares outstanding and 4.7 milllion stock options outstanding.

Bank Debt plus Working Capital Deficiency

At June 30, 2008, the Company had $90.0 million outstanding on its credit facility and a working capital deficit of $7.2 million for total debt plus working capital deficit of $97.2 million excluding the financial liability of $6.0 million relating to the unrealized loss on financial commodity contracts and the related current future income tax asset of $1.9 million. Delphi anticipates spending less than projected funds from operations on capital expenditures during 2008.

The capital intensive nature of the industry will generally result in the Company having a working capital deficiency. As of July 29, 2008, the Company has a revolving facility for $130.0 million with a syndicate of Canadian chartered banks. The facility is a 364 day committed revolving facility with a one year term out provision. The credit facility bears interest based on a sliding scale tied to the Company's trailing debt to funds from operations ratio: from a minimum of the bank's prime rate to a maximum of the bank's prime rate plus 1.5 percent. In addition to the revolving term facility, the Company has a $10.0 million development facility. The pricing grid on the development facility is 0.25 percent higher than the revolving term facility.

Contractual Obligations

The Company has a 364 day committed revolving credit facility with a syndicate of Canadian chartered banks which is available until May 31, 2009, the term out date. The term out date may be extended for an additional 364 days upon approval by the banks. Following the term out date, the facilities would become non-revolving for a one year term, at which time the balance outstanding will be due and payable.

Delphi has firm contracts for gathering, processing and transmission of natural gas in British Columbia. The Company has a lease for office space in Calgary, Alberta.




The future minimum commitments are as follows:

2008 2009 2010 2011 2012
----------------------------------------------------------------------------
Bank debt - 90,000 - - -
Gas transmission and treatment 2,055 4,213 4,074 3,473 1,846
Office lease 291 589 603 609 623
----------------------------------------------------------------------------
Total 2,346 94,802 4,677 4,082 2,469
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company has an obligation to incur an additional $1.7 million in qualifying exploration expenditures by December 31, 2008 to satisfy the obligation relating to the issuance of flow-through shares in 2007.

GUARANTEES AND OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING ESTIMATES

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

- Estimated revenues, operating expenses and royalties for which actual revenues and costs have not been received;

- Estimated capital expenditures on projects that are in progress;

- Estimated fair value of derivative contracts;

- Estimated amount of the asset retirement obligation including estimates of future costs and the timing of the costs.


CHANGES IN ACCOUNTING POLICIES AND FILING REQUIREMENTS

Financial Instruments

Effective January 1, 2008 the Company adopted CICA section 3862 - Financial Instruments - Disclosure which requires additional disclosure about the Company's financial instruments to be included in the financial statements. The recommendations prescribe an increased importance on risk disclosures associated with recognized and unrecognized financial instruments and how such risks are managed. In addition, the recommendations outline revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial instruments.

Details of the Company's accounting policies for the recognition and measurement of financial instruments and the basis for which revenues and expenses are recognized are disclosed in Note 2 of the Company's audited 2007 annual financial statements.

(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 takes 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 commodity market as a pure commodity play.

(b) Fair value of financial assets and liabilities

The Company's financial instruments as at June 30, 2008 include cash, accounts receivable, bank indebtedness, accounts payable and accrued liabilities, bank debt and risk management asset or liability.

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

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

(c) Market risk

Market risk is the risk that the fair value of 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 the fair value of 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 June 30, 2008.

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in the market interest rates. The Company is exposed to interest rate risk to the extent that bank debt is at a floating rate of interest. The Company had no interest rate swap or related financial contracts in place as at June 30, 2008. As at June, 2008, if interest rates had been 100 basis points lower with all other variables held constant, the net loss for the period would have been $0.2 million (2007- $0.3 million) lower, due to lower interest expense.

Commodity price risk

For commodity price risk - see "Risk Management Activities" earlier in the MD&A.

(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 venture partners. All of the Company's accounts receivable are with customers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. With respect to counterparties to financial instruments, the Company partially mitigates associated credit risk by limiting transactions to counterparties with investment grade credit ratings.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. The Company's policy to mitigate credit risk associated with these balances is to establish marketing relationships with large purchasers. The Company historically has not experienced any collection issues with its petroleum and natural gas marketers, however, subsequent to quarter end its sulphur marketer filed for protection under the Company Creditor Arrangement Act (Canada). The financial exposure is estimated to be approximately $850,000 of sulphur revenue. The Company is diligently pursuing all options available to recover the amounts owing to the Company and has a payable to the marketer in the amount of approximately $950,000 for gathering and processing fees.. Joint venture receivables are typically collected within one to three months of the joint venture billing being issued to the partner. The Company attempts to mitigate the risk from joint venture 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 venture partners, however, the Company does have the ability to withhold production from joint venture partners in the event of non-payment.

The carrying amount of cash and accounts receivable represent the maximum credit exposure. The Company does not have an allowance for doubtful accounts as at June 30, 2008 and 2007 and was not required to write-off any receivables during the quarter.



As at March 31, 2008 the Company considers its receivables to be aged as
follows:

June 30, 2008
----------------------------------------------------------------------------
Current (less than 30 days) 15,418
Past due (31-90 days) 121
Past due (more than 90 days) 1,362
----------------------------------------------------------------------------
Total 16,901
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(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 is 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, 2008:


Less than 1 - 2 2 - 5
Financial liabilities 1 Year Years Years Thereafter
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 27,040 - - -
----------------------------------------------------------------------------
Bank debt - principal - 90,000 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 27,040 90,000 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


International Financial Reporting Standards (IFRS)

In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the changeover to IFRS from Canadian GAAP will be required for publicly accountable enterprises effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. The AcSB issued the "omnibus" exposure draft of IFRS with comments due by July 31, 2008, wherein early adoption by Canadian entities is also permitted. The Canadian Securities Administrators ("CSA") has also issued Concept Paper 52-402, which requested feedback on the early adoption of IFRS as well as the (continued) use of US GAAP by domestic issuers. The eventual changeover to IFRS represents changes due to new accounting standards. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Company's reported financial position and results of operations.

The Company has not completed development of its IFRS changeover plan, which will include project structure and governance, resourcing and training, analysis of key GAAP differences and a phased plan to assess accounting policies under IFRS as well as potential IFRS 1 exemptions. The Company expects to complete its project scoping, which will include a timetable for assessing the effects on data systems, internal controls over financial reporting, and business activities, such as financing and compensation arrangements, by December 31, 2008.

The International Accounting Standards Board (IASB) has stated that it plans to issue an exposure draft relating to certain amendments to IFRS 1 in order to make it more useful to Canadian entities adopting IFRS for the first time. One such exemption relating to full cost oil and gas accounting is expected to result in a reduced administrative transition from the current Canadian full cost accounting for oil and gas activities to IFRS. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late in 2009. The amendment will potentially permit the Company to apply IFRS prospectively to their full cost pool, rather than the retrospective restatement of capitalized exploration and development expenses, with the proviso that a ceiling test, under IFRS standards, be conducted at the transition date.

CORPORATE GOVERNANCE

Overview

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

Disclosure Controls and Procedures

Disclosure controls and procedures have been designed to ensure information required to be disclosed by Delphi is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding disclosures. The Company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by the annual filings, that the Company's disclosure controls and procedures provide a reasonable level of assurance that information required to be disclosed by the Company is recorded, processed, summarized and reported within the time periods specified. The 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 Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company notes that while it believes the disclosure controls and procedures provide a reasonable level of assurance that they are effective, it does not expect that the disclosure controls and procedures 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.

2008 OUTLOOK

Strategy

Delphi emphasizes a full-cycle approach to its business and strives for internally generated development opportunities as a means of enhancing its production base and ultimately creating value for shareholders. Delphi's goal is to become a dominant natural gas developer and explorer focused in North West Alberta and North East British Columbia. The objective is to develop an inventory of opportunities and undeveloped land base from which production and reserves can be added independent of acquisition activity. In that regard, the Company's ability to add production through the drill bit creates a competitive advantage over those competitors that rely on acquisitions to build or maintain their production base. Currently, Delphi has identified over one hundred drilling locations, 2 to 3 years drilling inventory, on its core areas. Delphi continues to pursue acquisitions that will be accretive on a per share basis to cash flow, production, reserves and net asset value and which provide significant development opportunities to further enhance value.

2008 Capital Activities

The capital program, excluding acquisitions, for 2008 has been increased to an estimated $60.0 million for the drilling of approximately 20 to 25 net wells. The Company has allocated approximately one-third of its capital to each of Bigstone and Hythe with the remaining one-third to be allocated to other areas throughout the year. The majority of the expenditures through the winter drilling season were allocated to Bigstone. In the latter half of the year, the majority of the capital will be directed towards Hythe, now that the technical teams have had sufficient time to evaluate the multi-zone nature of this significant land base. Positive results from the capital program and secure financial resources continue to be the main drivers of Delphi's capital investing decision making in the context of natural gas prices and the proposed Alberta royalty regime changes. Delphi is well positioned to internally finance its capital program through funds from operations and if necessary, available bank lines.

2008 Production Guidance

With the closing of the Peace River Arch property acquisition, the Company has now forecast average production volumes to be in the 6,350 to 6,550 boe/d range, an increase of 21 percent over the average production volumes in 2007. Delphi's production guidance for the third quarter of 2008 is expected to average between 6,400-6,600 boe/d, approximately a 14 percent increase over the third quarter of 2007. Further quarterly production guidance will be made available through the year. The volumes will continue to be dominated by natural gas production of approximately 85 percent.

Alberta Royalty Review

On September 18, 2007 the Royalty Review Panel, comprised of independent members appointed by the Government of Alberta, released its report outlining recommendations on how the Government of Alberta should modify the existing royalty structure on oil and gas production. On October 25, 2007, the Government of Alberta responded by announcing its proposed changes to the royalty structure which are to be made effective January 1, 2009. The proposed recommendations would revise the royalty calculation formula for conventional oil and gas, increasing the sensitivity of royalties to both commodity prices and well productivity rates. A simplification of the overall royalty regime was also part of the recommendations including the elimination of oil and gas tiers, the elimination of a number of special royalty programs and expanded royalty rate limits on both oil and gas commodity prices. The Government of Alberta also introduced a deep gas drilling adjustment for wells greater than a certain measured depth. The Company will continue to monitor the status of the recommendations as the final royalty structure is established.

ADDITIONAL INFORMATION

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

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

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

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

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

Non-GAAP Measures. The MD&A contains the terms "funds from operations", "funds from operations per share" 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.



DELPHI ENERGY CORP.
Consolidated Balance Sheets (unaudited)

June 30 December 31
($ thousands) 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Assets
----------------------------------------------------------------------------
Current assets
----------------------------------------------------------------------------
Cash 529 -
----------------------------------------------------------------------------
Accounts receivable 16,901 12,604
----------------------------------------------------------------------------
Prepaid expenses and deposits 3,150 2,752
----------------------------------------------------------------------------
Risk management asset (Note 8) - 1,113
----------------------------------------------------------------------------
Future income taxes 1,898 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
22,478 16,469
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Property, plant and equipment (Note 4) 301,313 295,266
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total assets 323,791 311,735
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Liabilities
----------------------------------------------------------------------------
Current liabilities
----------------------------------------------------------------------------
Bank indebtedness 712 -
----------------------------------------------------------------------------
Accounts payable and accrued liabilities 27,040 34,014
----------------------------------------------------------------------------
Risk management liability (Note 8) 6,467 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
34,219 34,014
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Long term debt (Note 5) 90,000 82,000
----------------------------------------------------------------------------
Future income taxes 34,516 28,162
----------------------------------------------------------------------------
Asset retirement obligations (Note 6) 7,666 7,183
----------------------------------------------------------------------------
----------------------------------------------------------------------------
166,401 151,359
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Shareholders' equity
----------------------------------------------------------------------------
Share capital (Note 7) 146,120 148,898
----------------------------------------------------------------------------
Contributed surplus (Note 7) 8,718 8,236
----------------------------------------------------------------------------
Retained earnings 2,552 3,242
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total shareholders' equity 157,390 160,376
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total liabilities and shareholders' equity 323,791 311,735
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Commitments (Note 9)

Subsequent events (Note 10)

See accompanying notes to the interim consolidated financial statements.

DELPHI ENERGY CORP.
Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss) and
Retained Earnings (unaudited)
For the three and six months ended June 30

Three Months Ended Six Months Ended
June 30 June 30
($ thousands, except per unit amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue
----------------------------------------------------------------------------
Petroleum and natural gas sales 38,904 24,755 70,968 46,729
----------------------------------------------------------------------------
Realized gain (loss) on risk
management activities (335) 24 (187) 24
----------------------------------------------------------------------------
----------------------------------------------------------------------------
38,569 24,779 70,781 46,753
----------------------------------------------------------------------------

Royalties (8,346) (3,843) (14,208) (7,051)
----------------------------------------------------------------------------
Unrealized gain (loss) on risk
management activities (4,679) 2,041 (7,580) 1,845
----------------------------------------------------------------------------
----------------------------------------------------------------------------
25,544 22,977 48,993 41,547
----------------------------------------------------------------------------

Expenses
----------------------------------------------------------------------------
Operating 6,168 4,798 11,321 8,635
----------------------------------------------------------------------------
Transportation 1,548 1,902 3,125 3,231
----------------------------------------------------------------------------
General and administrative 1,344 854 2,318 1,613
----------------------------------------------------------------------------
Stock-based compensation (Note 7) 260 101 492 314
----------------------------------------------------------------------------
Interest 1,198 1,913 2,785 4,089
----------------------------------------------------------------------------
Depletion, depreciation and accretion 15,011 12,148 30,162 21,681
----------------------------------------------------------------------------
Impairment of goodwill - - - 12,100
----------------------------------------------------------------------------
----------------------------------------------------------------------------
25,529 21,716 50,203 51,663
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings (loss) before taxes 15 1,261 (1,210) (10,116)
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Taxes
----------------------------------------------------------------------------
Current - - - -
----------------------------------------------------------------------------
Future (reduction) (34) 464 (520) 740
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(34) 464 (520) 740
----------------------------------------------------------------------------
Net earnings (loss) and
comprehensive income (loss) 49 797 (690) (10,856)
----------------------------------------------------------------------------
Retained earnings, beginning of period 2,503 2,061 3,242 13,714
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained earnings, end of period 2,552 2,858 2,552 2,858
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Net earnings (loss) per share (Note 7)
----------------------------------------------------------------------------
Basic and diluted - 0.01 (0.01) (0.17)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the interim consolidated financial statements.

DELPHI ENERGY CORP.
Consolidated Statements of Cash Flows (unaudited)
For the three and six months ended June 30

Three Months Ended Six Months Ended
June 30 June 30
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Cash flow from operating activities
----------------------------------------------------------------------------
Net earnings(loss) 49 797 (690) (10,856)
----------------------------------------------------------------------------
Add non-cash items:
----------------------------------------------------------------------------
Depletion, depreciation and accretion 15,011 12,148 30,162 21,681
----------------------------------------------------------------------------
Impairment of goodwill - - - 12,100
----------------------------------------------------------------------------
Stock-based compensation 260 101 492 314
----------------------------------------------------------------------------
Unrealized (gain) loss on risk
management activities 4,679 (2,041) 7,580 (1,845)
----------------------------------------------------------------------------
Future taxes (reduction) (34) 464 (520) 740
----------------------------------------------------------------------------
Expenditures on asset
retirement obligations - (255) - (446)
----------------------------------------------------------------------------
Change in non-cash working
capital (2,491) 3,720 (11,719) 5,636
----------------------------------------------------------------------------
----------------------------------------------------------------------------
17,474 14,934 25,305 27,324
----------------------------------------------------------------------------
Cash flow from financing activities
----------------------------------------------------------------------------
Issue of flow-through common
shares, net of issue costs - (51) - 16,826
----------------------------------------------------------------------------
Issue of common shares, net of
issue costs 971 83 1,349 83
----------------------------------------------------------------------------
Increase(decrease) in bank debt 500 2,900 8,000 (12,100)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1,471 2,932 9,349 4,809
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Cash flow used in investing activities
----------------------------------------------------------------------------
Capital expenditures (7,489) (4,311) (33,987) (20,307)
----------------------------------------------------------------------------
Disposition of petroleum and natural
gas properties 2,950 - 2,950 -
----------------------------------------------------------------------------
Acquisition of petroleum and natural
gas properties (3,850) (10,871) (3,850) (10,871)
----------------------------------------------------------------------------
Change in non-cash working capital (10,027) (7,545) 762 (1,712)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(18,416) (22,727) (34,125) (32,890)
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Increase in cash and cash equivalents 529 (4,861) 529 (757)
----------------------------------------------------------------------------
Cash and cash equivalents, beginning
of period - 4,861 - 757
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash and cash equivalents, end
of period 529 - 529 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Interest paid 827 1,757 2,414 3,700
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the interim consolidated financial statements.

DELPHI ENERGY CORP.
Notes to Consolidated Financial Statements
As at and for the periods ended June 30, 2008 and 2007 (unaudited)
(all tabular amounts are expressed in thousands of dollars, except per unit
amounts)


NOTE 1: DESCRIPTION OF BUSINESS

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

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

The unaudited interim consolidated financial statements of Delphi have been prepared by management in accordance with accounting principles generally accepted in Canada and following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2007, except as described in Note 3. 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, 2007. 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: NEW DISCLOSURES

Financial Instruments - Disclosure and Presentation

Effective January 1, 2008 the Company adopted CICA section 3862 - Financial Instruments - Disclosure which requires additional disclosure about the Company's financial instruments to be included in the financial statements. The recommendations prescribe an increased importance on risk disclosures associated with recognized and unrecognized financial instruments and how such risks are managed. In addition, the recommendations outline revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial instruments. These additional disclosures are included in Note 8.



NOTE 4: PROPERTY, PLANT AND EQUIPMENT

Accumulated
depletion and
As at June 30, 2008 Cost depreciation Net book value
----------------------------------------------------------------------------
Petroleum and natural gas
properties 350,560 140,853 209,707
Production equipment 114,543 23,242 91,301
Furniture, fixtures and
office equipment 833 528 305
----------------------------------------------------------------------------
465,936 164,623 301,313
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Accumulated
depletion and
As at December 31, 2007 Cost depreciation Net book value
----------------------------------------------------------------------------
Petroleum and natural gas
properties 323,305 114,408 208,897
Production equipment 105,713 19,877 85,836
Furniture, fixtures and
office equipment 1,003 470 533
----------------------------------------------------------------------------
430,021 134,755 295,266
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at June 30, 2008, costs in the amount of $8.2 million (December 31, 2007 - $10.8 million) representing unproved properties were excluded from the depletion calculation and estimated future development costs of $9.0 million (December 31, 2007 - $15.7 million) have been included in costs subject to depletion. All costs of unproved properties have been capitalized. Ultimate recoverability of these costs will be dependent upon finding proved oil and natural gas reserves.

For the six months ended June 30, 2008, the Company capitalized $1.7 million (June 30, 2007 - $1.2 million) of general and administrative costs directly related to exploration and development activities.

NOTE 5: LONG TERM DEBT

As of July 29, 2008, the Company had a revolving facility for $130.0 million with a syndicate of Canadian chartered banks (see note 9). The facility is a 364 day committed revolving facility with a one year term out provision. The credit facility bears interest based on a sliding scale tied to the Company's trailing debt to cash flow: from a minimum of the bank's prime rate to a maximum of the bank's prime rate plus 1.5 percent.

In addition to the revolving term facility, the Company has a $10.0 million development facility with its lenders. The pricing grid on the development facility is 0.25 percent higher than the revolving term facility.

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

NOTE 6: ASSET RETIREMENT OBLIGATIONS

The Company's asset retirement obligations result from working interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations, over the next three to twenty years, is approximately $16.9 million. A credit-adjusted risk-free rate of 8.0 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.



June 30, 2008 December 31, 2007
----------------------------------------------------------------------------
Balance, beginning of period 7,183 7,951
Liabilities incurred 271 1,017
Liabilities disposed (83) (1,873)
Liabilities settled - (550)
Accretion expense 295 638
----------------------------------------------------------------------------
Balance, end of period 7,666 7,183
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NOTE 7: SHARE CAPITAL

(a) Authorized

An unlimited number of common shares.

An unlimited number of preferred shares issuable in series.

(b) Common shares issued

June 30, 2008 December 31, 2007

Outstanding Outstanding
shares (000's) Amount shares (000's) Amount
----------------------------------------------------------------------------
Balance,
beginning of period 68,070 148,898 60,663 139,108
Issue of flow-through
common shares - - 7,350 18,007
Exercise of stock options 1,050 1,349 57 83
Allocated from contributed
surplus - 631 - 39
Share issue costs - - - (1,208)
Future tax effect of share
issue costs - - - 369
Tax benefit renounced to
shareholders - (4,758) - (7,500)
----------------------------------------------------------------------------
Balance, end of period 69,120 146,120 68,070 148,898
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On March 1, 2007, the Company issued 7.35 million flow-through common shares at a price of $2.45 per share for gross proceeds of $18.0 million.

The Company has incurred the necessary qualifying exploration expenditures to satisfy the terms of the flow-through common shares issued in 2006. Although the Company believes it has incurred the necessary qualifying expenditures, these amounts may be subject to audit and subsequent interpretation by the Canada Revenue Agency. The Company has an obligation to incur qualifying exploration expenditures of $18.0 million by December 31, 2008 to satisfy the obligation relating to the issuance of flow-through shares in 2007. As at June 30, 2008 the Company has a remaining requirement to incur approximately $1.7 million of qualifying expenditures to fully satisfy this obligation.

(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 equal to ten percent of the issued and outstanding common shares of the Company. Options issued under the plan have a term of five years to expiry and vest over a two-year period starting on the date of the grant. The exercise price of each option equals the 5 day weighted average of the closing market price of the Company's common shares, immediately preceding the date of the grant. As at June 30, 2008 there were 4.7 million options to purchase shares outstanding.

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



June 30, 2008 December 31, 2007

Weighted Weighted
Outstanding average Outstanding average
options exercise options exercise
(000's) price (000's) price
----------------------------------------------------------------------------
Balance, beginning of
period 5,481 1.60 4,229 3.40
Granted 465 2.21 4,500 1.67
Cancelled (154) 1.56 (121) 3.92
Forfeited - - (3,070) 4.09
Exercised (1,050) 1.32 (57) 1.45
----------------------------------------------------------------------------
Balance, end of period 4,742 1.73 5,481 1.60
----------------------------------------------------------------------------
Exercisable at end of period 1,700 1.71 2,481 1.52
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes information about the stock options
outstanding and exercisable at June 30, 2008.

Options outstanding Options exercisable

Range Weighted Weighted Weighted
of Outstanding average average average
exercise options exercise remaining Exercisable exercise
price (000's) price term (years) (000's) price
---------------------------------------------------------------------------
$1.45 - $1.79 4,562 1.68 4.3 1,622 1.67
$1.80 - $3.34 180 2.93 4.8 65 2.85
---------------------------------------------------------------------------
Total 4,742 1.73 4.3 1,687 1.71
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(d) Stock-based compensation

The Company accounts for its stock-based compensation using the fair value method for all stock options. For the six months ended June 30, 2008 Delphi recorded non-cash compensation expense of $0.5 million (June 30, 2007- $0.3 million). The Company capitalized $0.6 million (June 30, 2007 - $0.5 million) of stock-based compensation directly related to exploration and development activities.

During the six month period ended June 30, 2008 the Company granted 0.5 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 $1.56 per share. The assumptions used in the Black-Scholes model to determine fair value were as follows.



Six Months Ended June 30, 2008
----------------------------------------------------------------------------
Risk free interest rate (%) 5.0
Expected life (years) 5.0
Expected volatility (%) 53.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(e) Contributed surplus

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

June 30, 2008 December 31, 2007
----------------------------------------------------------------------------
Balance, beginning of period 8,236 5,627
Stock-based compensation costs 1,113 2,648
Reclassification to common shares
on exercise of stock options (631) (39)
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Balance, end of period 8,718 8,236
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(f) Net earnings (loss) per share

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

Three Months Ended June 30 Six Months Ended June 30
2008 2007 2008 2007

----------------------------------------------------------------------------
Basic 68,833 68,019 68,555 65,582
Diluted 70,421 68,344 70,143 65,903
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The reconciling item between the basic and diluted weighted average common shares outstanding is stock options.

Note 8: Financial Instruments

Details of the Company's accounting policies for the recognition and measurement of financial instruments and the basis for which revenues and expenses are recognized are disclosed in Note 2 of the Company's audited 2007 annual financial statements.

(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 takes advantage of the upward swings in natural gas prices as a result of the changes in demand/supply fundamentals and/or the movement of significant financial assets invested in the natural gas market as a pure commodity investment.

(b) Fair value of financial assets and liabilities

The Company's financial instruments as at June 30, 2008 include cash, accounts receivable, bank indebtedness, accounts payable and accrued liabilities, bank debt and risk management asset or liability.

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

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

(c) Market risk

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

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

Foreign currency exchange rate risk

Foreign currency exchange rate risk is the risk that future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company's petroleum and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for petroleum and natural gas are affected by changes in the exchange rate between the Canadian and United States dollar. The exchange rate could affect the values of certain contracts, however, this indirect influence cannot be accurately quantified. The Company had no foreign exchange rate swap or related financial contracts in place as at June 30, 2008.

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in the market interest rates. The Company is exposed to interest rate risk to the extent that bank debt is at a floating rate of interest. The Company had no interest rate swap or related financial contracts in place as at June 30, 2008. As at June 30, 2008, if interest rates had been 100 basis points lower with all other variables held constant, the net loss for the six months ended June 30, 2008 would have been $0.2 million (2007- $0.3 million) lower, due to lower interest expense.

Commodity price risk

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

As at June 30, 2008, the Company had the following financial derivative sales contracts which were recorded on the balance sheet at fair value with changes in fair value included in unrealized gain or loss on risk management activities in the statement of earnings.



Contract
Type of Quantity Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
April 2008 - October 2008 Natural Gas Financial 1,000 GJ/d $8.07 fixed
April 2008 - October 2008 Natural Gas Financial 1,000 GJ/d $8.07 fixed
April 2008 - October 2008 Natural Gas Financial 1,000 GJ/d $7.75 floor/
$9.55 ceiling
November 2008 - March 2009 Natural Gas Financial 2,000 GJ/d $7.62 fixed
November 2008 - March 2009 Natural Gas Financial 1,000 GJ/d $8.00 floor/
$11.07 ceiling
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company has both United States and Canadian dollar physical sales contracts. The Canadian dollar physical sales contracts were entered into and continue to be held for the purpose of delivery of non-financial items as executory contracts and have not been recorded at fair value. The changes in fair value of the United States dollar physical sales contracts are included in unrealized gain or loss on risk management activities in the statement of earnings. As at June 30, 2008, the Company had the following physical sales contracts.



Contract
Type of Quantity Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
April 2008 -
October 2008 Natural Gas Physical 4,000 GJ/d $7.21 fixed
April 2008 -
October 2008 Natural Gas Physical 3,000 GJ/d $7.61 fixed
April 2008 -
October 2008 Natural Gas Physical 2,000 mmbtu/d U.S. $8.00 fixed
April 2008 -
December 2008 Natural Gas Physical 2,000 GJ/d $7.82 fixed
April 2008 -
March 2009 Natural Gas Physical 2,000 GJ/d $7.30 fixed
November 2008 -
March 2009 Natural Gas Physical 4,000 GJ/d $7.46 fixed
November 2008 -
March 2009 Natural Gas Physical 2,000 GJ/d $7.00 floor/
$8.05 ceiling
November 2008 -
March 2009 Natural Gas Physical 2,000 mmbtu/d U.S. $9.00 fixed
April 2009 -
October 2009 Natural Gas Physical 1,000 GJ/d $7.08 fixed
April 2009 -
October 2009 Natural Gas Physical 2,000 GJ/d $8.25 floor/
$10.00 ceiling
April 2009 -
October 2009 Natural Gas Physical 1,000 mmbtu/d U.S. $8.18 fixed
April 2009 -
October 2009 Natural Gas Physical 2,000 GJ/d $8.59 fixed
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the six months ended June 30, 2008, the Canadian dollar physical contracts resulted in settlement losses of $1.6 million (2007 gains - $2.8 million) that have been included in petroleum and natural gas sales. For the six months ended June 30, 2008, the financial contracts and U.S. dollar based physical contracts resulted in losses of $0.2 million (2007 - $nil) that have been included in the statement of earnings as a realized loss on risk management activities. As at June 30, 2008, if natural gas prices had been +/- $0.10 per mcf, with all other variables held constant, the net change in the unrealized gain or loss on risk management activities in the statement of earnings for the period would have been +/- $0.1 million (2007 - $nil). The sensitivity is higher in 2008 as compared to 2007 because of an increase in financial and U.S. dollar based physical contracts outstanding.

(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 venture partners. All of the Company's accounts receivable are with customers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. With respect to counterparties to financial instruments, the Company partially mitigates associated credit risk by limiting transactions to counterparties with investment grade credit ratings.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. The Company's policy to mitigate credit risk associated with these balances is to establish marketing relationships with large purchasers. The Company historically has not experienced any collection issues with its petroleum and natural gas marketers, however, subsequent to quarter end its sulphur marketer filed for protection under the Company Creditor Arrangement Act (Canada). The financial exposure is estimated to be approximately $850,000 of sulphur revenue. The Company is diligently pursuing all options available to recover the amounts owing to the Company and has a payable to the marketer in the amount of approximately $950,000 for gathering and processing fees. Joint venture receivables are typically collected within one to three months of the joint venture billing being issued to the partner. The Company attempts to mitigate the risk from joint venture 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 venture partners, however, the Company does have the ability to withhold production from joint venture partners in the event of non-payment.

The carrying amount of cash and accounts receivable represent the maximum credit exposure. The Company does not have an allowance for doubtful accounts as at June 30, 2008 and was not required to write-off any receivables during the quarter.

As at June 30, 2008 the Company considers its receivables to be aged as follows.



June 30, 2008
----------------------------------------------------------------------------
Current (less than 30 days) 15,418
Past due (31-90 days) 121
Past due (more than 90 days) 1,362
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Total 16,901
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(e) Liquidity risk

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

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

The following are the contractual maturities of financial liabilities as at June 30, 2008.



Financial less than
liabilities 1 Year 1 - 2 Years 2 - 5 Years Thereafter
----------------------------------------------------------------------------
Accounts payable
and accrued
liabilities 27,040 - - -
Bank debt - principal - 90,000 - -
----------------------------------------------------------------------------
Total 27,040 90,000 - -
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NOTE 9: CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The Company is committed to future minimum payments for natural gas transmission and processing and operating leases on compression equipment and office space. The Company's extendible term credit facility is available on a revolving basis until May 31, 2009, 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. Without assuming the renewal of the credit facilities, payments required under these commitments for each of the next five years are: 2008-$2.3 million; 2009-$94.8 million; 2010-$4.7 million; 2011-$4.1 million; 2012-$2.5 million.

NOTE 10: SUBSEQUENT EVENTS

On June 26, 2008, the Company announced the proposed acquisition of producing oil and natural gas properties for $38.1 million, after closing adjustments, in the Peace River Arch area of North West Alberta and North East British Columbia. At the same time, the Company also announced an equity offering of 6,316,000 common shares at $2.85 per share and 3,530,000 flow-through shares at $3.40 per share for proceeds of approximately $30.0 million (net proceeds of $28.1 million). The financing transaction was closed on July 17, 2008 and subsequently the acquisition of the properties was concluded on July 30, 2008. The acquisition was funded by the net proceeds of the equity offering and the Company's credit facilities.

Contact Information

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