Delphi Energy Corp.
TSX : DEE

Delphi Energy Corp.

July 22, 2009 18:48 ET

Delphi Reports Ninth Quarter of Production Growth and Increases Cash Flow and Financial Flexibility

CALGARY, ALBERTA--(Marketwire - July 22, 2009) - Delphi Energy Corp. ("Delphi" or "the Company") (TSX:DEE) is pleased to announce its financial and operational results for the second quarter ended June 30, 2009.

Second Quarter 2009 Highlights

- Achieved record production of 6,809 barrels of oil equivalent per day (boe/d) in the second quarter of 2009, marking the ninth consecutive quarter of production growth.

- Generated funds from operations of $12.4 million ($0.16 per basic share) in the quarter, up from $10.0 million ($0.13 per basic share) in the first quarter of 2009.

- Reduced net debt to $104.1 million at the end of the second quarter of 2009, down $9.1 million from $113.2 million at the end of the first quarter, increasing total credit availability to $35.9 million.

- Drilled one well with a success rate of 100 percent on a net capital program of $3.3 million in the quarter. For the first six months, the net capital program totaled $17.3 million, approximately 77 percent of the first half cash flow.

- The Company's natural gas hedge position extends as far as December 31, 2010 at an average price of $7.34 per mcf and $6.88 per mcf for the remainder of 2009 and 2010, respectively.

- Renewed the Company's total credit facilities at $140.0 million, consisting of a revolving production facility of $125.0 million and an acquisition/development facility of $15.0 million.



Financial Highlights ($ thousands except per unit amounts)

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Petroleum and natural
gas sales 23,229 38,569 (40) 47,434 70,781 (33)
Per boe 37.49 68.33 (45) 38.62 63.45 (39)
Funds from operations 12,371 19,965 (38) 22,388 37,024 (40)
Per boe 19.97 35.37 (44) 18.23 33.18 (45)
Per share - Basic 0.16 0.29 (45) 0.28 0.54 (48)
Per share - Diluted 0.16 0.28 (43) 0.28 0.53 (47)
Net earnings (loss) (2,817) 49 - (6,137) (690) 789
Per boe (4.54) 0.09 - (4.99) (0.62) 705
Per share - Basic (0.04) - - (0.08) (0.01) 700
Per share - Diluted (0.04) - - (0.08) (0.01) 700
Capital invested 3,602 7,489 (52) 17,694 33,987 (48)
Disposition of
properties (74) (2,950) (98) (225) (2,950) (92)
----------------------------------------------------------------------------
Net capital invested 3,528 4,539 (22) 17,469 31,037 (44)
Acquisition of
properties (218) 3,850 - (218) 3,850 -
----------------------------------------------------------------------------
Total capital 3,310 8,389 (61) 17,251 34,887 (51)
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Jun. 30 Dec. 31
2009 2008 % Change
----------------------------------------------------------------------------
Debt plus working capital deficiency (1) 104,100 109,237 (5)
Total assets 349,868 364,538 (4)
Shares outstanding (000's)
Basic 79,067 79,067 -
Diluted 86,305 83,798 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) excludes risk management asset and the related current future income
tax liability.



Operational Highlights

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Natural gas (mcf/d) 35,641 31,898 12 35,229 31,838 11
Crude oil (bbl/d) 371 368 1 423 378 12
Natural gas liquids
(bbl/d) 498 517 (4) 491 444 11
----------------------------------------------------------------------------
Total (boe/d) 6,809 6,202 10 6,786 6,129 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------


MESSAGE TO SHAREHOLDERS

Despite the 30 percent drop in the AECO natural gas price in the second quarter as compared to the first quarter of 2009, Delphi accomplished modest growth in average quarterly production volumes, stronger cash flow than in the first quarter and in combination with a minimal capital program, achieved significant net debt reduction during the quarter. At the end of the second quarter, the Company had increased its financial flexibility with $35.9 million of available credit lines. The Company believes it is well positioned for sustainable long-term, organic growth in any business environment. The global recession continues with commodity prices remaining under pressure, however, Delphi believes it can operate effectively in these challenging times and is in a position of relative strength to many of its peer group.

During the second quarter, the Company's field operations were limited due to spring break-up. The Company was, however, able to begin its summer capital program by mid-June with the completion of drilling operations on a well (1.0 net) at Hythe, Alberta by the end of the second quarter and undertook several recompletions. Fracture stimulation and tie-in operations of the drilled well will be completed in the third quarter. The focus of the summer capital program will continue to be directed towards the Hythe and Bigstone properties to take advantage of the multi-zone nature of these assets, low operating costs and quick on-stream capability associated with owned gathering and processing infrastructure. Total net capital expenditures for the second quarter were $3.3 million.

Production during the second quarter of 2009 averaged 6,809 boe/d, an increase of ten percent compared to 6,202 boe/d in the second quarter of 2008 and one percent greater than the first quarter in 2009 of 6,762 boe/d. Second quarter production represented Delphi's ninth consecutive quarter of production growth. New production from the Company's successful first quarter capital program contributed significantly to this modest growth in second quarter production despite significant turnarounds at Bigstone, Alberta and the Company's North East British Columbia operations during the quarter.

Delphi's production continues to receive a premium to the price at AECO due to marketing arrangements, heating content and natural gas hedges. Approximately 53 percent of the Company's natural gas production was hedged at an average price of $7.38 per mcf in the second quarter, resulting in a gain on natural gas contracts of $7.0 million. Delphi's realized natural gas price of $5.81 per mcf in the second quarter represented a premium of 67 percent to the average AECO price in the quarter.

Funds from operations in the second quarter of 2009 were $12.4 million ($0.16 per basic share) compared to $20.0 million ($0.29 per basic share) in the second quarter of 2008, primarily as a result of significantly lower average oil and natural gas prices being partially offset by increased production volumes, reduced royalty rates and an eight percent reduction in cash operating costs per boe.

At June 30, 2009, the Company had net debt of $104.1 million, a $5.1 million decrease from $109.2 million at December 31, 2008. The decrease in net debt during the first six months of 2009 resulted from Delphi's successful capital program totaling only $17.3 million or 77 percent of the cash flow generated in the first six months of 2009. The Company's debt to cash flow ratio on an annualized 2009 cash flow basis was reduced to 2.3:1 at the end of the second quarter from 2.8:1 at the end of the first quarter. Net debt includes bank debt plus working capital deficiency excluding the risk management asset and the related current future income taxes liability.

The annual credit review by the Company's lenders was completed in the second quarter. The Company's lenders continue to be National Bank of Canada and Bank of Nova Scotia. The total credit facilities were renewed at $140.0 million comprised of a revolving $125.0 million production credit facility and a non-revolving $15.0 million acquisition/development credit facility. At the same time, the pricing on the facilities had been adjusted to reflect current market rates for credit facilities of this nature. All other terms of the credit facilities remain unchanged from the previous arrangements.

NORTH WEST ALBERTA

During the second quarter, Delphi achieved record production volumes as a result of the successful first quarter drilling, workover and optimization program primarily focused in the Hythe and Bigstone areas. Operations during the second quarter were limited in scope due to spring breakup which typically restricts the ability to conduct drilling and workover operations until late in the quarter. Operational activities in the second quarter were focused on moving forward projects that would build upon the successes in the first quarter and position the Company to exploit its predictable, repeatable and capital efficient opportunities.

Hythe

At Hythe, the Company drilled and cased one vertical, gas well (1.0 net) during the second quarter. Completion operations have been initiated and a total of six zones will be completed based on log analysis. This well offsets other Delphi producers that have initial three month average production rates ranging from 250 to 600 boe/d. As a follow up to the Doe Creek light oil discovery first announced in September 2008, Delphi has recompleted a 100 percent working interest well which offsets the discovery well. The recompletion was successful and the well tested at rates in excess of 225 barrels of oil per day (bbls/d) over a forty eight hour flow period. The well has been tied-in to Delphi's infrastructure and has been placed on production at a stabilized rate of 160 bbls/d. A horizontal well offsetting the successful oil recompletion has been licensed and will spud prior to the end of July to calibrate the productivity enhancement and increased reserve recovery associated with a multi-stage fracture completion. In reservoirs of this nature, initial production rates and reserve recoveries for horizontal wells are typically two to three times that of vertical wells.

The Company is continuing to move drilling, recompletion and optimization projects forward by obtaining the regulatory and partner approvals necessary for project execution. Timing of the individual projects will be dependent upon commodity pricing and results from completed operations. The second half capital program at Hythe was generated from a project list that exceeds $48.0 million allowing for operational flexibility in regards to project selection. Delphi currently has eight vertical wells and four horizontal wells licensed or in the process of being licensed for the contemplated remaining 2009 capital program.

Technical and operational activities are ongoing in an effort to unlock the large volumes of gas in place associated with the Nikanassin formation. One of the vertical wells drilled in the first quarter was successfully completed in the Nikanassin and was mechanically isolated during the second quarter while a prolific uphole Cretaceous sand was production tested. The Company is now in the process of commingling the Nikanassin with several uphole Cretaceous sands with a completion design that will allow for long term performance monitoring of the Nikanassin formation. Pressure transient analysis indicates this well has experienced only minimal pressure depletion even though it is located 775 metres from an offset Nikanassin completion that has cumulative production of 2.2 billion cubic feet (bcf). The pressure and production data support the volumetric calculations of 15 bcf per spacing unit in this part of the Hythe field. A regional study has been initiated to characterize the porosity and permeability relationships, define geologic depositional models and understand the effects of various drilling and completion practices. The outcome of this study will allow Delphi to optimize development of the Nikanassin resource in relation to deliverability and reserve recovery. Toward that end, the Company has identified multiple Nikanassin recompletion opportunities to be pursued in the second half of the year.

Delphi continues to take advantage of attractive opportunities resulting from the current business environment through the acquisition of undeveloped land. During the second quarter, the Company successfully participated in several Crown land sales acquiring 1,280 gross acres at a working interest of 100 percent.

Bigstone

At Bigstone, the Company has licensed and built a location in preparation for drilling an offset to a successful first quarter well that averaged 650 boe/d gross over the first three months of production. In addition, Delphi is continuing to evaluate performance results from several Cardium oil pools on the Bigstone lands and is monitoring industry activity along trend in the Cardium formation. Delphi currently has identified six potential Cardium horizontal oil wells of which two are in the process of being licensed for the contemplated remaining 2009 capital program.

OUTLOOK

Natural gas prices have continued to weaken throughout the first part of the year and are at risk of further reduction as a result of natural gas supply in excess of demand, particularly due to reduced industrial demand from the lower economic activity in North America. Delphi will manage its capital spending prudently in light of the fact that potential lower natural gas prices may prevail for the remainder of 2009. As in prior years, the Company's risk management program provides stability to the Company's cash flow for the remainder of the year allowing a minimum level of capital to be incurred.

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

Cash flow for 2009 is forecast to be between $38.0 million and $43.0 million on an average natural gas price for AECO of approximately $4.25 per mcf. The Company has hedged approximately 51 percent of its natural gas production at $7.34 per mcf for the remainder of 2009 to achieve this forecasted cash flow. Over the year and based on its current capital program, Delphi expects an overall reduction in net debt of approximately $2.0 - $4.0 million from the amount outstanding at December 31, 2008.

Delphi remains confident in its ability to achieve continued per share growth during these challenging times. The Company's expanding inventory of drilling locations gives rise to continued optimism for growth beyond 2009.

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

CONFERENCE CALL

A conference call is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Thursday, July 23, 2009. The conference call number is 800-565-0813 or 416-695-6616. A brief presentation by David Reid, President and CEO and Brian Kohlhammer, VP Finance & CFO will be followed by a question and answer period.

If you are unable to participate in the conference call, a taped broadcast will be available until August 6, 2009. To access the replay, dial 800-408-3053 or 416-695-5800. The passcode is 3752405. Delphi's second quarter 2009 financial statements and management's discussion and analysis are available on Delphi's website at www.delphienergy.ca and will be available on SEDAR at www.sedar.com within 24 hours.

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

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

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

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

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

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

MANAGEMENT DISCUSSION AND ANALYSIS

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

The management discussion and analysis has been prepared by management and reviewed and approved by the Board of Directors of Delphi Energy Corp. ("Delphi" or "the Company"). The discussion and analysis is a review of the financial results of the Company based upon accounting principles generally accepted in Canada. Its focus is primarily a comparison of the financial performance for the six months ended June 30, 2009 and 2008 and should be read in conjunction with the audited financial statements and accompanying notes for the years ended December 31, 2008 and 2007. The discussion and analysis has been prepared as of July 21, 2009.

OPERATIONAL AND FINANCIAL HIGHLIGHTS

Delphi delivered another record quarterly production average of 6,809 barrels of oil equivalent per day (boe/d), representing the ninth consecutive quarter of production growth and a 10 percent increase from the comparable period in 2008. This consistent production growth in varying economic conditions speaks to the quality of the Company's core assets, management and staff and inventory of opportunities. Natural gas production comprised 87 percent of the Company's average production.

Funds flow from operations in the second quarter of 2009 was $12.4 million or $0.16 per basic share, compared to $20.0 million or $0.29 per basic share in 2008, primarily as a result of lower average oil and natural gas prices for the quarter offset by the growth in production volumes, reduced royalty rates and an eight percent reduction in cash operating costs per boe to the comparative quarter. Delphi's risk management program continued to contribute to funds from operations providing the Company with $7.0 million in realized gains in the quarter.

Delphi's financial position continues to remain strong in the second quarter of 2009, providing financial flexibility to execute the remainder of its 2009 capital program and reduce debt from current levels. At June 30, 2009, the Company had net debt of $104.1 million on total credit facilities of $140.0 million, providing excess financial capacity of approximately $35.9 million. The net capital program in the first half of the year was $17.3 million, approximately 77 percent of cash flow, contributing to the net debt reduction of $5.1 million from December 31, 2008.

The annual credit review by the Company's lenders was completed in the second quarter. The Company's lenders continue to be National Bank of Canada and Bank of Nova Scotia. The total credit facilities were renewed at $140.0 million comprised of a revolving $125.0 million production credit facility and a non-revolving $15.0 million acquisition/development credit facility. At the same time, the pricing on the facilities has been adjusted to reflect current market rates for credit facilities of this nature. All other terms of the credit facilities remain unchanged from the previous arrangements.



BUSINESS ENVIRONMENT

Benchmark Prices

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Natural Gas
NYMEX (US $/mmbtu) 3.71 10.69 (65) 4.14 9.39 (56)
AECO (CDN $/mcf) 3.47 10.22 (66) 4.21 9.10 (54)
Crude Oil
West Texas
Intermediate
(US $/bbl) 59.62 123.98 (52) 51.46 110.94 (54)
Edmonton Light
(CDN $/bbl) 65.88 126.07 (48) 57.88 111.79 (48)
Foreign Exchange
Canadian to US dollar 1.17 1.01 16 1.21 1.01 20
US to Canadian dollar 0.86 0.99 (13) 0.83 0.99 (16)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 is subject to disruption from time to time. The increase in capacity of natural gas liquefaction and regasification facilities has resulted in natural gas in North America becoming a global commodity, more so through the winter heating season than the summer cooling season, 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 2009, the U.S. Northeast and Midwest and Central Canada experienced below average seasonal temperatures resulting in reduced average demand for natural gas for electrical generation and industrial demand remains significantly reduced due to the current economic slowdown. Downward pressure on natural gas prices began early in 2009 and has continued into the second quarter as natural gas storage numbers continue to grow over the five year average levels. AECO averaged $3.47 per mcf in the second quarter and continues to decline through the summer. The drop in natural gas prices has had a significant effect on the active drilling rig count in both Canada and the United States.

For internal forecasting purposes, Delphi is expecting a challenging natural gas market in 2009 and anticipates AECO to average between $4.00 and $5.00 per mcf. Delphi continues to monitor the variables affecting the price of natural gas in order to ensure its capital program is in line with expected funds flow from operations.

Crude Oil

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

Through the second quarter of 2009, the price for crude oil fluctuated between U.S. $45.00 and $72.00 per barrel. Crude oil supplies continued to grow in the quarter as demand remained reduced due to the slowdown in global economies and use of energy. WTI averaged U.S. $59.62 per barrel for the quarter compared to U.S. $123.98 per barrel for the same quarter in the prior year, a decrease of 52 percent. The average price of U.S. $59.62 per barrel was, however, 38 percent higher than the first quarter average of U.S. $43.08 per barrel.

In the second quarter of 2009, the value of the Canadian dollar increased against its U.S. counterpart as the demand for the United States dollar as a safe haven in these uncertain economic times decreased. This negative effect to the price of oil for Canadian producers was compounded by a widening basis differential between U.S. and Canadian markets. In the second quarter of 2009, Canadian crude oil prices averaged $65.88 per barrel compared to $126.07 per barrel for the same quarter in the prior year, a decrease of 48 percent.

Prices for heavy oil and other lesser quality crude oils trade at a discount or differential to light crude oil due to the additional costs involved in the refining process. The average differential in the second quarter of 2009 was $3.54 per barrel compared to $21.43 per barrel in 2008. The decrease in the average differential, offset by lower light oil prices, resulted in Bow River crude prices averaging $62.36 per barrel compared to $104.63 per barrel in the second quarter of 2008.

For internal forecasting purposes, Delphi anticipates WTI to average between U.S. $50.00 and $60.00 per barrel for 2009 with the Canadian dollar to remain between $1.10 and $1.25 per U.S. dollar.

Industry Cost of Services

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

FINANCIAL STRATEGY

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

Delphi has a strategy of hedging approximately 40 to 50 percent of its natural gas production as long as demand/supply fundamentals indicate volatile markets in the future. Currently, Delphi has hedged approximately 51 percent of its before-royalty natural gas production at a predominantly AECO based average floor price of $7.34 per mcf for the remainder of 2009. This compares to the forward strip commodity price for AECO of $4.10 per mcf as of June 30, 2009. The following natural gas hedges are in place to support the Company's cash flow.



July-Oct Nov-Mar Apr-Dec Jul-Dec Jan-Dec
2009 2009/2010 2010 2009 2010
----------------------------------------------------------------------------
Production hedged (mmcf/d) 19.0 13.1 6.6 18.4 7.6
Percentage of natural gas
production (1) 53% 36% 18% 51% 21%
Price floor (Cdn $/mcf) $7.38 $7.51 $6.39 $7.34 $6.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) based on 36 mmcf/d


The fair value of the outstanding contracts is estimated to be approximately $13.2 million as of June 30, 2009.

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

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

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

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

Delphi continues to be focused on reducing its leverage and improving its financial flexibility through net debt reduction or increasing funds flow growth resulting in a lower net debt to annualized quarterly funds from operations ratio. The Company continues to be focused on achieving its internal target range for this ratio of 1.3 to 1.5 times. In a low price environment, the Company's objective would be to reduce or at least not increase the net debt balance by undertaking a capital program within cash flow.



SELECTED INFORMATION

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

Jun. 30 Mar. 31 Dec. 31 Sept. 30
2009 2009 2008 2008
----------------------------------------------------------------------------
Production
Natural gas (mcf/d) 35,641 34,813 35,545 33,691
Oil (bbl/d) 371 475 431 372
Natural gas liquids (bbl/d) 498 485 353 421
----------------------------------------------------------------------------
Barrels of oil equivalent (boe/d) 6,809 6,762 6,708 6,409
Financial
($ thousands except per unit
amounts)
Petroleum and natural gas
revenue 23,229 24,205 30,160 34,461
Funds from operations 12,371 10,017 13,473 18,160
Per share - basic 0.16 0.13 0.18 0.24
Per share - diluted 0.16 0.13 0.18 0.23
Net earnings (loss) (2,817) (3,320) (959) 6,743
Per share - basic (0.04) (0.04) (0.01) 0.09
Per share - diluted (0.04) (0.04) (0.01) 0.09
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Jun. 30 Mar. 31 Dec. 31 Sept. 30
2008 2008 2007 2007
----------------------------------------------------------------------------
Production
Natural gas (mcf/d) 31,898 31,777 30,610 28,196
Oil (bbl/d) 368 387 346 579
Natural gas liquids (bbl/d) 517 372 420 422
----------------------------------------------------------------------------
Barrels of oil equivalent (boe/d) 6,202 6,056 5,868 5,700
Financial
($ thousands except per unit
amounts)
Petroleum and natural gas
revenue 38,569 32,212 26,632 24,548
Funds from operations 19,965 17,059 13,747 12,600
Per share - basic 0.29 0.25 0.20 0.19
Per share - diluted 0.28 0.25 0.20 0.18
Net earnings (loss) 49 (739) 1,732 (1,348)
Per share - basic - (0.01) 0.03 (0.02)
Per share - diluted - (0.01) 0.03 (0.02)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production for the last eight consecutive quarters reflects the following events: In 2007, success at Bigstone, Alberta throughout the year and Noel, British Columbia in the third quarter complemented the mid-year start up of production at Tower Creek, Alberta resulting in consistent quarter over quarter production growth. In 2008, the combination of a successful winter and summer capital program and the production increase from the acquisition resulted in continued production growth quarter over quarter. In the first half of 2009, production growth was achieved with drilling success at Bigstone and Hythe, Alberta. Revenue and funds from operations reflect the cycle of natural gas prices and production volumes.

Natural gas prices over the past two years have generally reflected the cyclical nature of demand. Higher prices in the winter months, reflecting demand for heating, weaken through the summer months as production is placed in storage for the upcoming heating season demand. Natural gas prices in the second quarter of 2008 did not follow the cyclical trend expected, as prices continued to increase coming out of the winter heating season due to concerns over natural gas supply in storage and the continued increase in crude oil prices. Subsequent to the second quarter, natural gas prices decreased significantly and then stabilized in the fourth quarter. In 2009, reduced heating demand and industrial demand due to the economic crisis caused natural gas prices to decrease further as a result of concerns over excess supply. The Company achieved record cash flow of approximately $20.0 million in the second quarter of 2008 at the peak of commodity prices. Delphi continues to mitigate the volatility of commodity prices on its cash flow and capital program by undertaking an active risk management program. In the first and second quarters of 2009, the Company has recorded cash flow of $10.0 million and $12.4 million, respectively, during a period of weak commodity pricing. The strong 2009 cash flow is attributed to an increase in production volumes, reduced cost structure and a successful risk management program.



DRILLING RESULTS

Three Months Ended Six Months Ended
June 30, 2009 June 30, 2009
Gross Net Gross Net
----------------------------------------------------------------------------
Natural gas wells 1.0 1.0 6.0 4.8
Oil wells - - - -
----------------------------------------------------------------------------
Total wells 1.0 1.0 6.0 4.8
Success rate (%) 100 100 100 100
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company had a 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 June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Land 290 - 100 556 - 100
Seismic 270 - 100 296 3 9,767
Drilling and
completions 72 4,115 (98) 11,082 22,611 (51)
Equipping and
facilities 2,078 2,321 (10) 3,556 9,248 (62)
Capitalized expenses 697 1,030 (32) 1,813 1,667 9
Other 195 23 748 391 458 (15)
----------------------------------------------------------------------------
Capital invested 3,602 7,489 (52) 17,694 33,987 (48)
Disposition of
properties (74) (2,950) (98) (225) (2,950) (92)
----------------------------------------------------------------------------
Net capital invested 3,528 4,539 (22) 17,469 31,037 (44)
Acquisition of
properties (218) 3,850 - (218) 3,850 -
----------------------------------------------------------------------------
Total capital 3,310 8,389 (61) 17,251 34,887 (51)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company continues to focus its capital program towards its core areas of Bigstone and Hythe to take advantage of the multi-zone nature of these assets, low operating costs and quick on-stream capability associated with owned gathering and processing infrastructure. During the first half of 2009, the Company directed the majority of capital to the drilling, completion and tie-in of three wells at Hythe, Alberta, one well at Bigstone, Alberta and one well at Noel, British Columbia. Total net capital for the quarter was $3.3 million, representing a 61 percent reduction from the comparative quarter as field operations were started later in the quarter due to lower commodity prices and cash flow.



PRODUCTION

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Natural gas (mcf/d) 35,641 31,898 12 35,229 31,838 11
Crude oil (bbls/d) 371 368 1 423 378 12
Natural gas liquids
(bbls/d) 498 517 (4) 491 444 11
----------------------------------------------------------------------------
Total (boe/d) 6,809 6,202 10 6,786 6,129 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production for the three months ended June 30, 2009 averaged 6,809 boe/d representing an increase of 10 percent over the comparative period primarily due to the successful drilling and optimization programs at Bigstone and Hythe. Second quarter 2009 production volumes represent the ninth consecutive quarter of production growth for the Company.

Delphi is focused on delivering consistent results and achieving quarter over quarter production gains. While operating in a challenging economic environment in the first half of 2009, the Company has continued to deliver record quarterly production through organic growth. This is a testament to the quality of the asset base and technical expertise of the staff and management. A significant undeveloped land base, multi-zone potential and the successful application of emerging technologies continue to provide material growth opportunities in existing and new play concepts. The Company's production portfolio for the year was weighted 87 percent to natural gas, six percent to crude oil and seven percent to natural gas liquids.

Crude oil production was one percent higher for the three months ended June 30, 2009 over the comparative quarter.

Natural gas liquids were four percent lower for the three months ended June 30, 2009, as compared to the comparative period in 2008 due to the increased natural gas production at Hythe, which has a lower liquids-rich content.



REALIZED SALES PRICES

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
AECO ($/mcf) 3.47 10.22 (66) 4.21 9.10 (54)
Heating content and
marketing ($/mcf) 0.19 0.53 (64) 0.24 0.50 (52)
Gain (loss) on physical
contracts ($/mcf) 1.80 (0.97) - 1.38 (0.28) -
Gain (loss) on financial
contracts ($/mcf) 0.35 (0.12) - 0.34 (0.03) -
----------------------------------------------------------------------------
Realized natural gas
price ($/mcf) 5.81 9.66 (40) 6.17 9.29 (34)

Realized oil price
($/bbl) 62.11 116.36 (47) 53.13 100.27 (47)

Realized natural gas
liquids price ($/bbl) 50.20 103.10 (51) 44.77 96.14 (53)
----------------------------------------------------------------------------
Total realized sales
price ($/boe) 37.49 68.33 (45) 38.62 63.45 (39)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and six months ended June 30, 2009, Delphi's risk management program realized a gain of $7.0 million and $11.0 million, respectively. For the quarter, the realized gain was $2.15 per mcf with physical contracts contributing a gain of $1.80 per mcf and financial contracts contributing a gain of $0.35 per mcf. For the six months ended June 30, 2009, the average realized natural gas price was 34 percent less than the comparative period due to a 54 percent decrease in the AECO spot price offset by significant realized hedging gains.

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

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



Jun. 30 Mar. 31 Dec. 31 Sept. 30
2009 2009 2008 2008
----------------------------------------------------------------------------
Natural Gas Price
Delphi realized ($/mcf) 5.81 6.55 8.14 8.28
AECO average ($/mcf) 3.47 4.95 6.70 7.73
Premium (discount) to AECO 67% 32% 21% 7%
Hedging gain (loss) ($000's) 6,997 3,991 1,985 (67)
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Jun. 30 Mar. 31 Dec. 31 Sept. 30
2008 2008 2007 2007
----------------------------------------------------------------------------
Natural Gas Price
Delphi realized ($/mcf) 9.66 8.91 7.61 7.20
AECO average ($/mcf) 10.22 7.97 6.15 5.14
Premium (discount) to AECO (5%) 12% 24% 40%
Hedging gain (loss) ($000's) (3,153) 1,371 2,996 3,875
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

RISK MANAGEMENT ACTIVITIES

Delphi enters into both financial and physical commodity contracts as part of its risk management program to manage commodity price fluctuations designed to ensure sufficient cash is generated to fund its capital program particularly when commodity prices are extremely volatile. Delphi makes a concerted effort to hedge production volumes at prices greater than the upper limit of the historical three to five year AECO price range of $5.25 to $8.40 per mcf and is quick to react to price aberrations such as those experienced at the end of 2005 and the summer of 2008. Another component of the risk management program is to layer in contracts over a period of time, as opposed to locking in a significant portion of volumes at any one point in time, to take advantage of unexpected price spikes. For natural gas production, Delphi has hedged approximately 51 percent of its before-royalty natural gas production at a predominately AECO based average floor price of $7.34 per mcf for the second half of 2009.

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

The Company recognized an unrealized non-cash loss on its financial contracts and United States dollar denominated physical contracts of $0.2 million for the first half of 2009. The fair values of these contracts are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the contracts outstanding at the end of the period having regard to forward prices and market values provided by independent sources. Due to the inherent volatility in commodity prices, actual amounts realized may differ from these estimates.

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



Time Type of Quantity Contract Price
Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
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

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

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

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

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

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

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

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

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

February
2009 -
December
2009(1) Natural Gas Financial 3,500 GJ/d $6.00 Put

March 2009
- December
2009(1) Natural Gas Physical 3,500 GJ/d $6.00 Put

January
2010 -
December
2010(1) Natural Gas Financial 3,500 GJ/d $7.40 Call

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


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



REVENUE

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Natural gas 11,856 31,191 (62) 28,377 55,597 (49)
Natural gas physical
contract gains 5,851 (2,818) - 8,813 (1,595) -
Crude oil 2,097 3,897 (46) 4,068 6,898 (41)
Natural gas liquids 2,275 4,851 (53) 3,979 7,769 (49)
Sulphur 4 1,783 (100) 22 2,299 (99)
Realized gain on risk
management contracts 1,146 (335) - 2,175 (187) -
----------------------------------------------------------------------------
Total 23,229 38,569 (40) 47,434 70,781 (33)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The decrease in revenue over the comparative periods is attributed to the decrease in realized sales price per boe offset by the realized gains from the risk management program and the increase in production volumes.

Additionally, during the first half of 2008, sulphur prices began their rise as demand for fertilizers increased around the world. Delphi received $2.3 million from the sale of sulphur during the first half of 2008, primarily associated with production at its Tower Creek well. As a result of the slowing economies around the world, sulphur prices have fallen significantly resulting in minimal sales in the first half of 2009 despite ongoing production at Tower Creek.



ROYALTIES

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Total 466 8,346 (94) 4,909 14,208 (65)
Per boe 0.75 14.79 (95) 4.00 12.74 (69)
Percent of revenue
including realized
hedges 2.0 21.5 (91) 10.3 20.0 (48)
Percent of revenue
excluding realized
hedges 2.9 20.0 (86) 13.5 19.6 (31)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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, 2009, royalties as a percentage of revenue decreased over the comparative period due to favorable prior period adjustments to the annual capital cost and processing fee deductions. Additionally, the New Royalty Framework (NRF) rates as a percentage of revenue decreased in a low natural gas price environment. Overall, Delphi is expecting royalties as a percentage of revenue, before hedging, to be between 13 and 17 percent in 2009.

On October 25, 2007, the Government of Alberta announced the New Royalty Framework. The NRF established new royalties for oil and natural gas which are based on commodity prices, well production volumes and well depths. The NRF rates apply to both new and existing production and became effective on January 1, 2009. In the fourth quarter of 2008, the Government of Alberta announced royalty relief which provided that for new wells drilled after November 19, 2008, the Company could elect to have the pre-NRF royalty regime apply on those wells. On March 3, 2009, the Alberta Government announced further royalty incentives to promote oilfield activity in light of the current economic environment. The incentives provided drilling credits based on the depth drilled and a reduced royalty rate of five percent for natural gas production brought on-stream after March 31, 2009. On June 25, 2009 the Alberta Government announced an extension of this incentive program to March 31, 2011 from March 31, 2010.



OPERATING EXPENSES

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Total 6,169 5,896 5 12,373 10,769 15
Per boe 9.96 10.45 (5) 10.07 9.65 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Operating costs on a per boe basis for the three and six months ended June 30, 2009, decreased five percent and increased four percent, respectively, over the comparative periods. The second quarter decrease is primarily due to higher production volumes and a lower level of workover and maintenance activity in 2009 than 2008. Delphi continues to focus on cost reduction and anticipates lower operating costs per boe as volumes increase at core areas and the industry experiences a further reduction in field costs. Delphi expects operating costs to be $9.75 to $10.25 per boe in 2009.



TRANSPORTATION EXPENSES

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Total 2,128 1,820 17 3,589 3,677 (2)
Per boe 3.43 3.22 7 2.92 3.30 (12)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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, 2009, increased by seven percent and decreased 12 percent, respectively, over the comparative periods. Transportation costs in the second quarter of 2009 included the reclassification of approximately $0.4 million of natural gas gathering costs reported as operating costs in the first quarter. Effective November 1, 2007 and again on November 1, 2008, Delphi transferred a portion of its excess processing and transmission capacity in North East British Columbia to third parties resulting in reductions in transportation costs. Delphi expects transportation costs to be between $2.75 and $3.00 per boe for the remainder of 2009.



GENERAL AND ADMINISTRATIVE

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
General and
administrative costs 2,159 2,982 (28) 5,416 4,986 9
Overhead recoveries (213) (176) 21 (472) (544) (13)
Salary allocations (723) (1,462) (51) (2,599) (2,124) 22
----------------------------------------------------------------------------
Net 1,223 1,344 (9) 2,345 2,318 1
Per boe 1.97 2.38 (17) 1.91 2.08 (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On a per boe basis, general and administrative (G&A) costs for the three and six months ended June 30, 2009 decreased 17 percent and eight percent over the comparative periods in 2008 due to the timing of compensation adjustments and an increase in production volumes. Delphi is committed to delivering strong growth and believes a strong technical team is paramount to achieve this goal. For the remainder of 2009, Delphi is expecting G&A per boe to be approximately $1.80 to $2.00 per boe.



STOCK-BASED COMPENSATION

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Stock-based
compensation 393 542 (27) 884 1,112 (20)
Capitalized costs 264 282 (6) 544 620 (12)
----------------------------------------------------------------------------
Net 129 260 (50) 340 492 (31)
Per boe 0.21 0.46 (54) 0.28 0.44 (36)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees, directors and key consultants of the Company. The fair value of all options granted is estimated at the date of grant using the Black-Scholes option pricing model. The stock-based non-cash compensation expense for the three and six months ended June 30, 2009, decreased 54 percent and 36 percent. During the six months ended June 30, 2009, Delphi capitalized $0.5 million of stock-based compensation associated with exploration and development activities.



INTEREST

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Total 872 1,198 (27) 1,830 2,785 (34)
Per boe 1.41 2.12 (33) 1.49 2.50 (40)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and six months ended June 30, 2009, interest expense on a per boe basis decreased 33 percent and 40 percent over the comparable periods due to lower interest costs from reduced interest rates and higher production volumes. The reduction in interest costs as a result of lower interest rates is expected to be offset by an increase in the Company's credit spread associated with its credit facilities due to the increase in market lending rates.

During the first half of 2009, the Company converted $80.0 million of its outstanding long term debt from prime-based loans to bankers' acceptances. The bankers' acceptances have terms ranging from 179 to 185 days and a weighted average effective interest rate of 0.98 percent plus the applicable stamping fee according to the pricing grid for bankers' acceptances over the term.

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



DEPLETION, DEPRECIATION AND ACCRETION

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Depletion and
depreciation 15,140 14,859 (2) 29,690 29,867 (1)
Accretion expense 151 152 (1) 394 295 34
----------------------------------------------------------------------------
Total 15,291 15,011 2 30,084 30,162 -
Per boe 24.68 26.60 (7) 24.49 27.04 (9)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Depletion, depreciation, and accretion per boe for the three and six months ended June 30, 2009 decreased 7 percent and 9 percent over the comparative period. With continued success at Bigstone and Hythe, Delphi is in an excellent position to continue to add proved reserves at metrics below the Company's current depletion rate. The decrease in total depletion and depreciation was a result of the depletion costs associated with increased production being more than offset by the improvement in the depletion rate.

Accretion expense of asset retirement obligations relates to the passing of time until the Company estimates it will retire its assets and restore the asset locations to a condition which meets or exceeds environmental standards. Due to the long term nature of certain assets of the Company, this accretion expense is estimated to extend over a term of three to 20 years. The Company uses a credit adjusted risk-free interest rate of 8.0 to 10.0 percent for the purpose of calculating the fair value of its asset retirement obligations and hence the accretion expense. The accretion expense for the three and six months ended June 30, 2009 decreased 1 percent and increased 34 percent over the comparative period due to the wells acquired in the Peace River Arch acquisition in the third quarter of 2008.



INCOME TAXES

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Current - - - -
Future (reduction) (954) (34) 2,706 (2,061) (520) 296
----------------------------------------------------------------------------
Total (954) (34) 2,706 (2,061) (520) 296
Per boe (1.54) (0.06) 2,467 (1.68) (0.47) 257
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The provision for income taxes in the financial statements for the three and six months ended June 30, 2009, was a reduction of $1.0 million and $2.1 million, respectively. Delphi does not anticipate it will be cash taxable before 2011.



FUNDS FROM OPERATIONS

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Net earnings (loss) (2,817) 49 - (6,137) (690) 789
Non-cash items:
Depletion,
depreciation and
accretion 15,291 15,011 (2) 30,084 30,162 -
Unrealized loss on
risk management
activities 722 4,679 (85) 162 7,580 (98)
Stock-based
compensation expense 129 260 (50) 340 492 (31)
Future income taxes
(reduction) (954) (34) 2,712 (2,061) (520) 296
----------------------------------------------------------------------------
Funds from operations 12,371 19,965 (38) 22,388 37,024 (40)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and six months ended June 30, 2009, funds from operations were $12.4 million ($0.16 per basic share) and $22.4 million ($0.28 per basic share) compared to $20.0 million ($0.29 per basic share) and $37.0 million ($0.54 per basic share) in the comparative period. The decrease in funds from operations is a result of a reduction in revenue received per boe, partially offset by an increase in production volumes, reduced royalty rates and a reduction in operating costs per boe.

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

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



Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Funds from
operations: Non-GAAP 12,371 19,965 (38) 22,388 37,024 (40)
Change in non-cash
working capital 89 (2,491) - (1,415) (11,719) (88)
----------------------------------------------------------------------------
Cash flow from
operating
activities: GAAP 12,460 17,474 (29) 20,973 25,305 (17)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NET EARNINGS

For the three and six months ended June 30, 2009, Delphi recorded a net loss of $2.8 million and $6.1 million, respectively. Net earnings were affected by non-cash items such as depletion, depreciation and accretion, unrealized gain or loss on risk management activities, stock-based compensation and future income taxes. These non-cash items represent the majority of the significant difference between funds from operations and net earnings.



NETBACK ANALYSIS

Three Months Ended June 30 Six Months Ended June 30
2009 2008 % Change 2009 2008 % Change
----------------------------------------------------------------------------
Barrels of oil
equivalent ($/boe)
Realized sales price 37.49 68.33 (45) 38.62 63.45 (39)
Royalties, net of ARTC 0.75 14.79 (95) 4.00 12.74 (69)
Operating expenses 9.96 10.45 (5) 10.07 9.65 4
Transportation 3.43 3.22 7 2.92 3.30 (12)
----------------------------------------------------------------------------
Operating netback 23.35 39.87 (41) 21.63 37.76 (43)
G&A 1.97 2.38 (17) 1.91 2.08 (8)
Interest 1.41 2.12 (33) 1.49 2.50 (40)
----------------------------------------------------------------------------
Cash netback 19.97 35.37 (44) 18.23 33.18 (45)
Unrealized loss on
financial contracts 1.16 8.28 (86) 0.13 6.79 (98)
Stock-based
compensation expense 0.21 0.46 (54) 0.28 0.44 (36)
Depletion,
depreciation and
accretion 24.68 26.60 (7) 24.49 27.04 (9)
Future income taxes
(reduction) (1.54) (0.06) 2,467 (1.68) (0.47) 257
----------------------------------------------------------------------------
Net earnings (loss) (4.54) 0.09 - (4.99) (0.62) 705
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 Ended Six Months Ended
June 30, 2009 June 30, 2009
----------------------------------------------------------------------------
Sources:
Funds from operations 12,371 22,388
Disposition of petroleum and
natural gas properties 74 225
Cash and cash equivalents - 2,715
----------------------------------------------------------------------------
12,445 25,328

Uses:
Cash and cash equivalents 4,605 -
Capital expenditures 3,384 17,476
Change in non-cash working capital 10,132 18,628
----------------------------------------------------------------------------
18,121 36,104

----------------------------------------------------------------------------
Increase in bank debt 5,676 10,776
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the period ended June 30, 2009 Delphi funded its capital program through a combination of funds from operations and an increase in its bank debt.

Share Capital

At June 30, 2009, the Company had 79.1 million common shares outstanding (December 31, 2008 - 79.1 million). The common shares of Delphi trade on the TSX under the symbol DEE. The following table summarizes outstanding share data for the three and six months ended June 30, 2009.



Three Months Ended Six Months Ended
June 30, 2009 June 30, 2009
----------------------------------------------------------------------------
Weighted Average Common Shares
Basic 79,067 79,067
Diluted 79,067 79,067
Trading Statistics (1)
High 1.28 1.28
Low 0.80 0.56
Average daily, volume 430,027 350,403
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Trading statistics based on closing price.


As at July 21, 2009, the Company had 79.1 million common shares outstanding and 7.2 milllion stock options outstanding.

Bank Debt plus Working Capital Deficiency

At June 30, 2009, the Company had $102.2 million outstanding on its credit facility and a working capital deficiency of $1.9 million for total debt plus working capital deficiency of $104.1 million excluding the financial asset of $1.6 million relating to the unrealized gain on financial commodity contracts and the related current future income tax liability of $0.4 million. The Company's debt to cash flow ratio on an annualized 2009 cash flow basis was reduced to 2.3:1 at the end of the second quarter from 2.8:1 at the end of the first quarter. Delphi anticipates spending less than projected funds from operations on capital expenditures during 2009 resulting in reduction in net debt of approximately $2.0 to $4.0 million.

Contractual Obligations

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



The future minimum commitments are as follows:


2009 2010 2011 2012 2013
----------------------------------------------------------------------------
Gathering, processing and
transmission 1,829 4,227 3,907 2,833 1,846
Office and equipment lease 505 1,023 1,029 775 390
----------------------------------------------------------------------------
Total 2,334 5,250 4,936 3,608 2,236
----------------------------------------------------------------------------
----------------------------------------------------------------------------


GUARANTEES AND OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING ESTIMATES

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

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

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

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

- Capital expenditures on projects that are in progress;

- Fair value of derivative contracts;

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

NEW ACCOUNTING STANDARDS

International Financial Reporting Standards (IFRS)

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

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

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

CORPORATE GOVERNANCE

Overview

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

Disclosure Controls and Procedures and Internal Controls over Financial Reporting

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

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

2009 OUTLOOK

Corporate Strategy

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

Capital Activities

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

The capital program for the second half of the year includes the drilling of up to 10 wells with the majority of the capital allocated to the Company's two main areas, Bigstone and Hythe.

Financial Strategy

The Company is well positioned to endure the current weak economic environment with high quality producing assets, a large inventory of economic projects and a 2009 cash flow stream protected with 51 percent of the Company's current natural gas production hedged at an average price of $7.34 per mcf for the remainder of the year. Maintaining operational and financial flexibility, combined with expanding the Company's long-term growth inventory in a low-cost environment, will be key drivers in the capital spending decision process for the remainder of 2009.

ADDITIONAL INFORMATION

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

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

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

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

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

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



DELPHI ENERGY CORP.
Consolidated Balance Sheets (unaudited)

June 30 December 31
(Stated in thousands of dollars) 2009 2008
----------------------------------------------------------------------------
Assets
Current assets
Cash 29 1,029
Accounts receivable 10,435 14,522
Prepaid expenses and deposits 5,130 2,928
Risk management asset (Note 8) 1,559 1,721
----------------------------------------------------------------------------
17,153 20,200

Property, plant and equipment (Note 4) 332,715 344,338
----------------------------------------------------------------------------
Total assets 349,868 364,538
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities
Current liabilities
Outstanding cheques 1,820 105
Future income taxes 438 501
Accounts payable and accrued liabilities 15,698 36,211
----------------------------------------------------------------------------
17,956 36,817

Long term debt (Note 5) 102,176 91,400
Future income taxes 34,953 33,655
Asset retirement obligations (Note 6) 10,207 9,730
----------------------------------------------------------------------------
165,292 171,602

Shareholders' equity
Share capital (Note 7) 171,887 174,995
Contributed surplus (Note 7) 10,490 9,605
Retained earnings 2,199 8,336
----------------------------------------------------------------------------
Total shareholders' equity 184,576 192,936
----------------------------------------------------------------------------
Total liabilities and shareholders' equity 349,868 364,538
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Commitments (Note 9)

See accompanying notes to the interim consolidated financial statements.



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

Three Months Ended Six Months Ended
(Stated in thousands of dollars, June 30 June 30
except per share amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales 22,083 38,904 45,259 70,968
Realized gain (loss) on risk
management activities (Note 8) 1,146 (335) 2,175 (187)
----------------------------------------------------------------------------
23,229 38,569 47,434 70,781
Royalties (466) (8,346) (4,909) (14,208)
Unrealized loss on risk management
activities (Note 8) (722) (4,679) (162) (7,580)
----------------------------------------------------------------------------
22,041 25,544 42,363 48,993

Expenses
Operating 6,169 5,896 12,373 10,769
Transportation 2,128 1,820 3,589 3,677
General and administrative 1,223 1,344 2,345 2,318
Stock-based compensation (Note 7) 129 260 340 492
Interest 872 1,198 1,830 2,785
Depletion, depreciation and accretion 15,291 15,011 30,084 30,162
----------------------------------------------------------------------------
25,812 25,529 50,561 50,203

----------------------------------------------------------------------------
Earnings (loss) before income taxes (3,771) 15 (8,198) (1,210)

Income taxes
Future (reduction) (954) (34) (2,061) (520)
----------------------------------------------------------------------------
(954) (34) (2,061) (520)

----------------------------------------------------------------------------
Net earnings (loss) and comprehensive
income (loss) (2,817) 49 (6,137) (690)
Retained earnings, beginning of period 5,016 2,503 8,336 3,242
----------------------------------------------------------------------------
Retained earnings, end of period 2,199 2,552 2,199 2,552
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Loss per share (Note 7)
Basic and diluted (0.04) - (0.08) (0.01)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

Cash flow from operating activities
Net earnings (loss) for the period (2,817) 49 (6,137) (690)
Add non-cash items:
Depletion, depreciation and accretion 15,291 15,011 30,084 30,162
Stock-based compensation 129 260 340 492
Unrealized loss on risk management
activities 722 4,679 162 7,580
Future income taxes (reduction) (954) (34) (2,061) (520)
Change in non-cash working capital 89 80 (1,415) (8,073)
----------------------------------------------------------------------------
12,460 20,045 20,973 28,951
Cash flow from financing activities
Issue of common shares, net of issue
costs - 971 - 1,349
Increase in long term debt 5,676 500 10,776 8,000
----------------------------------------------------------------------------
5,676 1,471 10,776 9,349

----------------------------------------------------------------------------
Cash flow available for investing
activities 18,136 21,516 31,749 38,300

Cash flow from (used in) investing
activities
Capital expenditures (3,602) (7,489) (17,694) (33,987)
Disposition of petroleum and natural
gas properties 74 2,950 225 2,950
Acquisition of petroleum and natural
gas properties 218 (3,850) 218 (3,850)
Change in non-cash working capital (10,221) (10,027) (17,213) 762
----------------------------------------------------------------------------
(13,531) (18,416) (34,464) (34,125)

----------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents 4,605 3,100 (2,715) 4,175
Cash and cash equivalents, beginning
of period (6,396) (3,283) 924 (4,358)
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period (1,791) (183) (1,791) (183)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash and cash equivalents is
comprised of:
Cash 29 529 29 529
Outstanding cheques (1,820) (712) (1,820) (712)
----------------------------------------------------------------------------
(1,791) (183) (1,791) (183)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Interest paid 851 827 2,083 2,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the interim consolidated financial statements.


DELPHI ENERGY CORP.

Notes to the Interim Consolidated Financial Statements

As at and for the periods ended June 30, 2009 and 2008 (unaudited)

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

NOTE 1: DESCRIPTION OF BUSINESS

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

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

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

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

NOTE 3: NEW ACCOUNTING STANDARDS

International Financial Reporting Standards

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



NOTE 4: PROPERTY, PLANT AND EQUIPMENT

Accumulated
depletion and
As at June 30, 2009 Cost depreciation Net book value
----------------------------------------------------------------------------
Petroleum and natural gas properties 420,575 194,091 226,484
Production equipment 136,443 30,818 105,625
Furniture, fixtures and office
equipment 1,237 631 606
----------------------------------------------------------------------------
558,255 225,540 332,715
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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


For the six months ended June 30, 2009, the Company capitalized $1.7 million (June 30, 2008 - $1.7 million) of general and administrative costs directly related to exploration and development activities.

As at June 30, 2009, costs in the amount of $2.1 million (December 31, 2008 - $3.4 million) representing unproved properties were excluded from the depletion calculation and estimated future development costs of $44.9 million (December 31, 2008 - $46.7 million) have been included in costs subject to depletion. All costs of unproved properties have been capitalized. Ultimate recoverability of these costs will be dependent upon finding proved oil and natural gas reserves.



NOTE 5: LONG TERM DEBT

June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Prime-based loans 22,176 91,400
Bankers' acceptances 80,000 -
----------------------------------------------------------------------------
Total debt 102,176 91,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company has a revolving facility for $125.0 million with a syndicate of Canadian chartered banks. The facility is a 364 day committed revolving facility until May 31, 2010, the term-out date. The term-out date may be extended for a further 364 day period upon approval by the banks. Following the term-out date, the facilities would be available on a non-revolving basis for a one year term. The credit facility bears interest based on a sliding scale pricing grid tied to the Company's trailing debt to cash flow ratio: from a minimum of the bank's prime rate plus 2.0 percent to a maximum of the bank's prime rate plus 5.0 percent or from a minimum of bankers' acceptances rate plus a stamping fee of 3.0 percent to a maximum of bankers' acceptances rate plus a stamping fee of 5.0 percent.

In the first half of 2009, the Company converted $80.0 million of its outstanding long term debt from prime-based loans to bankers' acceptances. The bankers' acceptances have terms ranging from 179 to 185 days and a weighted average effective interest rate of 2.9 percent over the term.

In addition to the revolving term facility, the Company has a $15.0 million development facility with its lenders. The pricing grid on the development facility is 1.50 to 1.75 percent higher than the revolving term facility. As at June 30, 2009, there is no amount drawn under this facility.

The two facilities are secured by a $200.0 million demand floating charge debenture and a general security agreement over all assets of the Company. The credit facilities are subject to semi-annual review.

NOTE 6: ASSET RETIREMENT OBLIGATIONS

The Company's asset retirement obligations result from working interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations, over the next three to 20 years, is approximately $21.7 million (December 31, 2008 - $21.4 million). A credit-adjusted risk-free rate of 8.0 to 10.0 percent and an inflation rate of 2.5 percent were used to calculate the estimated fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below.

June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Balance, beginning of period 9,730 7,183
Liabilities incurred 83 271
Liabilities disposed - (83)
Liabilities acquired - 2,021
Liabilities settled - (312)
Accretion expense 394 650
----------------------------------------------------------------------------
Balance, end of period 10,207 9,730
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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, 2009 December 31, 2008

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


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

As at June 30, 2009, the Company has incurred the necessary qualifying exploration expenditures to satisfy the terms of the flow-through common shares issued in 2008. Although the Company believes it has incurred the necessary qualifying expenditures, these amounts may be subject to audit and subsequent interpretation by the Canada Revenue Agency.

(c) Stock options

The Company has established a stock option plan under which it has granted options to acquire common shares to certain officers, directors, employees and key consultants. The plan provides for the granting of options up to ten percent of the issued and outstanding common shares of the Company. Options issued under the plan have a term of five years to expiry and vest over a two-year period starting on the date of the grant. The exercise price of each option equals the five day weighted average of the market price of the Company's common shares, immediately preceding the date of the grant. As at June 30, 2009 there were 7.2 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, 2009 December 31, 2008

Weighted Weighted
Outstanding average Outstanding average
options exercise options exercise
(000's) price (000's) price
----------------------------------------------------------------------------
Balance, beginning of period 4,731 1.75 5,481 1.60
Granted 2,557 0.74 615 2.23
Cancelled (50) 0.71 (60) 1.55
Forfeited - - (154) 1.56
Exercised - - (1,151) 1.33
----------------------------------------------------------------------------
Balance, end of period 7,238 1.40 4,731 1.75
----------------------------------------------------------------------------
Exercisable at end of period 4,017 1.53 2,938 1.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes information about the stock options
outstanding and exercisable at June 30, 2009.

Options outstanding Options exercisable

Weighted
Weighted average Weighted
Outstanding average remaining average
Range of exercise options exercise term Exercisable exercise
price (000's) price (years) (000's) price
----------------------------------------------------------------------------
$ 0.65 - $1.54 2,607 0.76 4.7 919 0.78
$ 1.55 - $1.72 3,751 1.67 3.8 2,540 1.67
$ 1.73 - $2.15 660 1.80 3.4 445 1.80
$ 2.16 - $3.34 220 3.18 4.0 113 3.23
----------------------------------------------------------------------------
Total 7,238 1.40 3.9 4,017 1.53
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(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, 2009, Delphi recorded non-cash compensation expense of $0.3 million (June 30, 2008 - $0.5 million). The Company capitalized $0.5 million (June 30, 2008 - $0.6 million) of stock-based compensation directly related to exploration and development activities.

During the six month period ended June 30, 2009, the Company granted 2.6 million options. The fair values of all options granted during the period are estimated at the date of grant using the Black-Scholes option pricing model. The weighted average fair value of options granted during the period was $0.40 per option. The assumptions used in the Black-Scholes model to determine fair value were as follows.



Six months ended Six months ended
June 30, 2009 June 30, 2008
----------------------------------------------------------------------------
Risk-free interest rate (%) 2.0 5.0
Expected life (years) 5.0 5.0
Expected volatility (%) 64.4 53.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(e) Contributed surplus

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

June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Balance, beginning of the period 9,605 8,236
Stock-based compensation expensed 340 994
Stock-based compensation capitalized 545 1,120
Reclassification to common shares on
exercise of stock options - (745)
----------------------------------------------------------------------------
Balance, end of the period 10,490 9,605
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(f) Net earnings (loss) per share

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

Three Months Ended Six Months Ended
June 30 June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Basic 79,067 68,833 79,067 68,555
Diluted 79,067 70,421 79,067 68,555
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and six months ended June 30, 2009, the stock options were anti-dilutive and therefore excluded from the calculation of weighted average common shares.

NOTE 8: FINANCIAL INSTRUMENTS

(a) Risk management overview

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

(b) Fair value of financial assets and liabilities

The Company's financial instruments as at June 30, 2009 include cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, long-term debt and risk management asset.

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

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

(c) Market risk

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

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

Foreign currency exchange rate risk

Foreign currency exchange rate risk is the risk that future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company's petroleum and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for petroleum and natural gas are affected by changes in the exchange rate between the Canadian and United States dollar. The exchange rate could affect the values of certain contracts, however, this indirect influence cannot be accurately quantified. The Company had no foreign exchange rate swap or related financial contracts in place as at June 30, 2009.

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in the market interest rates. The Company is exposed to interest rate risk to the extent that bank debt is at a floating rate of interest. If interest rates had been 100 basis points lower with all other variables held constant, net earnings for the six months ended June 30, 2009 would have been $0.2 million (2008 - $0.4 million) higher, due to lower interest expense.

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

The Company has also entered into an interest rate swap transaction on borrowings through bankers' acceptances in the amount of $40.0 million maturing on May 4, 2011. The bankers acceptance rate on the transaction will increase in fixed monthly increments of 4.55 basis points for an average fixed rate over two years of 0.94 percent. The effective interest rate over the two year term on $40.0 million of bankers' acceptances will be 0.94 percent plus the applicable stamping fee according to the pricing grid for bankers' acceptances. The fair value of this contract at June 30, 2009 is a gain of $12,000.

Commodity price risk

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

As at June 30, 2009, the Company had the following financial derivative and United States dollar physical sales contracts which were recorded on the balance sheet at fair value of $1.6 million (December 31, 2008 - $1.7 million) with changes in fair value included in unrealized gain (loss) on risk management activities in the statement of earnings.




Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
April 2009 -
October 2009 Natural Gas Physical 1,000 mmbtu/d U.S. $8.18 fixed

February 2009 -
December 2009(1) Natural Gas Financial 3,500 GJ/d $6.00 Put

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


The Company has both United States and Canadian dollar physical sales contracts. The Canadian dollar physical sales contracts were entered into and continue to be held for the purpose of delivery of non-financial items as executory contracts and have not been recorded at fair value. As at June 30, 2009, the Company had the following physical sales contracts.



Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------

April 2009 - Natural
October 2009 Gas Physical 1,000 GJ/d $7.08 fixed

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

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

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

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

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

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

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

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

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

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

March 2009 - Natural
December 2009(2) Gas Physical 3,500 GJ/d $6.00 Put

January 2010 - Natural
December 2010(2) Gas Physical 3,500 GJ/d $7.15 Call
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(2) The Company has acquired a natural gas put contract at $6.00 per
gigajoule on 3,500 gigajoules per day for the period March 1, 2009
through December 31, 2009. This put was paid for with the sale of a
natural gas call on 3,500 gigajoules per day at a price of $7.15 per
gigajoule for the period January 1, 2010 through December 31, 2010.


For the six months ended June 30, 2009, the Canadian dollar physical contracts resulted in settlement gains of $8.8 million (2008 loss - $1.6 million) that have been included in petroleum and natural gas sales. For the six months ended June 30, 2009, the financial contracts and U.S. dollar based physical contracts resulted in gains of $2.2 million (2008 loss - $0.2 million) that have been included in the statement of earnings as a realized gain on risk management activities. As at June 30, 2009, if natural gas prices had been +/- $0.10 per mcf, with all other variables held constant, the net change in the unrealized gain or loss on risk management activities in the statement of earnings for the year would have been +/- $0.2 million (2008 - $0.1 million).

d) Credit risk

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

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

The carrying amount of cash and accounts receivable represents the maximum credit exposure. The Company does not consider an allowance for doubtful accounts to be required as at June 30, 2009, however, bad debt expense of $21,000 was recorded during the quarter.



As at June 30, 2009 the Company's aged receivables are as follows.

June 30, 2009
----------------------------------------------------------------------------
Current (less than 30 days) 7,544
Past due (31-90 days) 2,018
Past due (more than 90 days) 873
----------------------------------------------------------------------------
Total 10,435
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(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, 2009.

less than 1 1 - 2 3 - 5
Financial liabilities Year Years Years Thereafter
----------------------------------------------------------------------------
Outstanding cheques 1,820 - - -
Accounts payable and
accrued liabilities 15,698 - - -
Long term debt -
principal - 102,176 - -
----------------------------------------------------------------------------
Total 17,518 102,176 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NOTE 9: COMMITMENTS

The Company is committed to future minimum payments for natural gas transmission and processing, operating leases on compression equipment and office space. Payments required under these commitments for each of the next five years are: 2009-$2.3 million; 2010-$5.3 million; 2011-$4.9 million; 2012-$3.6 million; 2013-$2.2 million.




CORPORATE INFORMATION

DIRECTORS OFFICERS

David J. Reid David J. Reid
President and Chief Executive Officer President and Chief Executive Officer
Delphi Energy Corp.
Tony Angelidis
Tony Angelidis Senior Vice President Exploration
Senior Vice President Exploration
Delphi Energy Corp. Hugo H. Batteke
Vice President Operations
Harry S. Campbell, Q.C. (2)
Partner Rod A. Hume
Burnet, Duckworth & Palmer LLP Vice President Engineering

Henry R. Lawrie (1) Michael S. Kaluza
Independent Businessman Chief Operating Officer

Robert A. Lehodey, Q.C. (2) Brian P. Kohlhammer
Partner Vice President Finance and
Osler, Hoskin & Harcourt LLP Chief Financial Officer

Andrew E. Osis (1) CORPORATE OFFICE
Chief Executive Officer and Director
Multiplied Media Corporation 300, 500 - 4th Avenue S.W.
Calgary, Alberta
Lamont C. Tolley (1) T2P 2V6
Independent Businessman Telephone: (403) 265-6171
Facsimile: (403) 265-6207
(1) Member of the Audit and Reserves Email: info@delphienergy.ca
Committee Website: www.delphienergy.ca
(2) Member of the Corporate Governance
and Compensation Committee
BANKERS
AUDITORS
National Bank of Canada
KPMG LLP The Bank of Nova Scotia

LEGAL COUNSEL INDEPENDENT ENGINEERS

Osler, Hoskin & Harcourt LLP GLJ Petroleum Consultants Ltd.

TRANSFER AGENT STOCK EXCHANGE LISTING

Olympia Trust Company Toronto Stock Exchange - DEE


ABBREVIATIONS

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


Contact Information

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