Delphi Energy Corp.
TSX : DEE

Delphi Energy Corp.

November 05, 2007 09:00 ET

Delphi Energy Increases Third Quarter Funds From Operations on Continued Production Growth

CALGARY, ALBERTA--(Marketwire - Nov. 5, 2007) - Delphi Energy Corp. (TSX:DEE) is pleased to announce its financial and operational results for the quarter ended September 30, 2007.

Third Quarter ended September 30, 2007 Highlights

- Increased average production 12 percent to 5,700 boe/d (82 percent natural gas) in the third quarter over the comparative quarter of 2006. Production continued to increase quarter over quarter by six percent (321 boe/d) from the second quarter of 2007 and 32 percent (1,378 boe/d) from first quarter of 2007.

- Increased funds from operations over the comparative quarter in 2006 by 16 percent to $12.6 million in the third quarter ($0.19 per share) on higher production volumes and higher cash netbacks. Cash netbacks were up two percent from the second quarter to $24.02 per boe despite the benchmark AECO price falling by 27 percent from the second quarter.

- Reduced operating costs by 16 percent ($1.53 per boe) to $8.30 per boe from a first half average of $9.83 per boe.

- Realized an average natural gas price of $7.20 per mcf, 38 percent higher than the benchmark AECO price in the third quarter of 2007, as a result of the Company's hedging strategy and natural gas marketing arrangements.

- Reduced bank debt plus working capital by $13.5 million in the third quarter.

- Swapped the Company's non-operated 50 percent working interest at Bigfoot in British Columbia for cash proceeds of $14.5 million and an average 74 percent working interest in an operated conventional multi-zone natural gas property and infrastructure in the Hythe area of northwest Alberta.

MESSAGE TO SHAREHOLDERS

Delphi's successful capital program, low-decline production base and effective hedging strategy led to significant increases in production and funds from operations in the third quarter of 2007. The Company has achieved this growth from a net capital program equal to 87 percent of its cash flow through the first nine months of 2007. Delphi has positioned itself to continue to grow through this extended cycle of low natural gas prices with a large inventory of economically attractive drilling and recompletion opportunities supported by a high quality reserve base. In addition, industry service and equipment costs have declined, allowing the Company to decrease its operating and capital costs.

During the third quarter of 2007, Delphi executed a $14.6 million capital program, including drilling and completing one gas well at Bigstone, Alberta, two natural gas wells at Noel in British Columbia and one well at Brazeau, Alberta. The successful wells are being tied in and equipped, with production expected to be onstream during the fourth quarter. The Company exchanged its 50 percent working interest in Bigfoot for an average 74 percent working interest in an operated conventional multi-zone natural gas property and plant and pipeline infrastructure in the Hythe area of northwest Alberta plus cash proceeds to Delphi of $14.5 million. The cash has been used to reduce debt.



Three Months Ended Nine Months Ended
Operational Highlights September 30 September 30
2007 2006 2007 2006
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Production
Natural gas (mcf/d) 28,196 25,403 25,631 25,972
Crude oil (bbls/d) 579 444 457 506
Natural gas liquids (bbls/d) 422 412 410 477
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Total (boe/d) 5,700 5,090 5,139 5,312

Financial Highlights ($000s except
per boe and per share amounts)
Petroleum and natural gas sales 24,548 21,587 71,301 71,261
Per boe 46.81 46.10 50.82 49.14
Funds from operations 12,600 10,902 34,734 37,734
Per boe 24.02 23.28 24.75 26.02
Per share - Basic 0.19 0.18 0.52 0.66
Per share - Diluted 0.18 0.18 0.52 0.65
Net earnings (loss) (1,348) 658 (12,204) 6,613
Per boe (2.57) 1.40 (8.69) 4.55
Per share - Basic (0.02) 0.01 (0.18) 0.12
Per share - Diluted (0.02) 0.01 (0.18) 0.11
Capital invested 14,626 27,886 45,804 153,228
Proceeds on dispositions (15,502) (1,331) (15,502) (17,501)
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Net capital (876) 26,555 30,602 135,727
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September 30 December 31
2007 2006
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Debt plus working capital deficit 97,294 118,178
Total assets 310,158 326,668
Shares outstanding
Basic 68,070 60,663

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OPERATIONAL REVIEW

NORTH WEST ALBERTA

Hythe

Several optimization projects associated with wells and the gas gathering system have already been completed resulting in production increasing to over 600 boe/d net from approximately 400 boe/d net when Delphi acquired the Hythe assets in September 2007. The Company anticipates additional production gains in the near term as optimization projects are completed. An ongoing integrated technical review has already identified multiple well recompletions, well reactivations and low risk drilling opportunities. Between now and the end of the first quarter 2008, Delphi will carry on with this first phase of certain redevelopment work at Hythe by continuing the optimization program, recompleting or reactivating up to seven wells (4.8 net) and drilling up to five (2.6 net) low risk development wells targeting the Cretaceous and Triassic formations from 1,000 to 2,500 metres.

Bigstone

The Cretaceous gas well (0.75 net) that was drilled, completed and tied in to Company owned infrastructure continues to perform as expected with flowrates in the range of 250 to 300 boe/d net. Planning for the winter drilling program is well underway with the final regulatory approvals anticipated during November. The winter drilling program contemplates up to five (3.2 net) low risk development wells being drilled to test gas and oil targets in the Cretaceous aged sands at depths ranging from 1,800 to 2,800 metres. The program will begin as soon as surface conditions allow access, typically mid to late December.

Brazeau

Delphi, as operator, is finalizing plans to equip and tie-in the previously drilled and completed 1,900 metre well on its lands in the Brazeau River area of west central Alberta. The well flow-tested 100 boe/d of light oil on a short term test from the Belly River formation. An on-lease tie-in to a midstream company with substantial capacity for gathering and processing of the solution gas will allow the well to come on-stream prior to the end of the year. Delphi has a 48.2 percent working interest in the well and maintains a 27 percent working interest in the associated acreage.

Red Rock

Delphi, as operator, is continuing to drill the first of potentially two 3,800 metre tests in the Red Rock area. Drilling operations on the first well are expected to be completed by the end of November and, if successful, completion operations will begin in December. The Red Rock area is prospective for multi-zone sweet gas targets including the Cadomin, Gething, Bluesky, Falher, Cadotte, Dunvegan and Cardium formations at depths ranging from 1,500 to 3,800 metres. Analog wells in the area have a wide range of deliverability with a typical well having an initial production rate of 2 to 3 mmcf/d and several of the more prolific wells having initial production rates in excess of 10 mmcf/d.

Under the terms of the farm-in agreement, Delphi has the potential to earn a working interest in up to 18,000 acres (28 gas spacing units) of land on a rolling option basis. Upon earning, Delphi will have a 60 percent working interest in this acreage, which is fully covered with existing 3D seismic. Delphi's working interest partner has ownership and access to gas gathering and processing infrastructure in the immediate area.

NORTH EAST BRITISH COLUMBIA

Noel

Pipeline construction operations to tie-in two farm-in wells (1.4 net) drilled and completed this summer are progressing as planned with first production anticipated in December. Although the two wells had a combined test rate of 9,400 mcf/d gross from five intervals, Delphi will purposely curtail the initial production rates to approximately 3,000 mcf/d gross (approximately 300 boe/d net) until the size and producing characteristics of the resource are better defined. Plans for the winter drilling program are being finalized with the potential for drilling up to two (0.9 net) low risk development wells targeting multi-zone sweet gas in the Falher, Cadotte, Paddy, and Dunvegan formations at depths ranging from 1,400 to 2,400 metres.

Brassey

Delphi has assumed operatorship for the completion operations on the previously drilled 3,300 metre test in the Brassey area. The completion design to evaluate three potential gas bearing zones is being finalized with an anticipated start date of mid to late November. This well is part of a farm-in agreement Delphi entered into with an industry producer in the Brassey area of north east British Columbia. Under the terms of this agreement, Delphi pays 62.5 percent of the drilling and completion costs to earn a 37.5 percent working interest in 4,350 acres (six gas spacing units) and retains the option to earn a 37.5 percent working interest in an additional 5,075 acres (seven gas spacing units) of land on a rolling option basis.

FINANCIAL REVIEW

Funds from operations for the third quarter of 2007 were $12.6 million ($0.19 per share) resulting from a cash netback of $24.02 per boe on production of 5,700 boe/d. Delphi's cash flow per boe growth over the second quarter was primarily due to a reduced cost structure, particularly operating costs and its hedging program. Operating costs were reduced by 16 percent, $1.53 per boe, to $8.30 per boe from a first half average of $9.83 per boe. The risk management program resulted in hedging gains of $3.9 million in the third quarter of 2007. The Company realized an average natural gas price 38 percent higher than the benchmark AECO price in the third quarter of 2007. Funds from operations for the nine months ended September 30, 2007 were $34.7 million.

Overall for the quarter, net capital expenditures were proceeds of $0.9 million. Delphi incurred $14.6 million in capital expenditures in the third quarter, with 86 percent directed towards the drilling of five wells. During the quarter, Delphi also closed the property swap transaction of the Company's non-operated 50 percent working interest at Bigfoot in exchange for an average 74 percent working interest in certain operated conventional multi-zone natural gas properties and plant and pipeline infrastructure in the Hythe area located in northwest Alberta plus cash proceeds to Delphi of $14.5 million. The cash proceeds have been used to reduce debt.

The Company recorded a net loss of $1.3 million ($0.02 per share) in the third quarter of 2007 and a loss of $12.2 million for the nine months ended September 30, 2007 as a result of an impairment of goodwill recorded in the first quarter of 2007. The non-cash charge of $12.1 million was based on a review of the valuation of goodwill as of March 31, 2007 which incorporated the market capitalization of the Company taking into account the Company's share price on March 31, 2007.

At September 30, 2007, Delphi had outstanding bank debt plus working capital deficiency of $97.3 million. The outstanding bank debt plus working capital was reduced $13.5 million in the quarter. Subsequent to the end of the quarter, the Company's lenders completed their semi-annual review of the Company's credit facilities and continue to make available the existing borrowing base of a $115.0 million production credit facility and a $10.0 million development/acquisition credit facility. The scheduled annual review will take place in the second quarter of 2008 based upon the December 31, 2007 reserves report.

ALBERTA ROYALTY REVIEW

Delphi is evaluating the impact of announced changes to Alberta's royalty structure. On September 18, 2007, a panel of individuals appointed by the Province of Alberta, the "Alberta Royalty Review Panel" released a report outlining its recommendations on how the Government of Alberta should modify the existing royalty regime for oil and gas production. On October 25, 2007, the Government of Alberta, after considering, among other things, that report, announced a new framework for oil and gas royalties effective January 1, 2009. The changes increase the royalties for conventional oil and gas, with sliding scale sensitivities to both commodity prices and well productivity rates. A simplification of the overall royalty regime was also announced including the elimination of oil and gas tiers, the elimination of a number of special royalty programs and expanded royalty rate limits on both oil and gas commodity prices. The Government of Alberta also introduced a deep gas drilling adjustment for wells with a measured depth of greater than 2,000 metres. Due to the nature of Delphi's production and capital program, the inclusion of a deep gas drilling adjustment partially offsets the increased royalty rates.

Based on the information available to date, the Company's preliminary assessment of the changes indicates that in the current price environment the effect on cash flow would be approximately a two to four percent negative adjustment and that there would be no effect on Delphi's net present value of reserves as at December 31, 2006. In higher gas price environments, the upside from price increases will be shared with the Government of Alberta due to the changes to the sliding scale grid calculation of royalties. From the perspective of capital projects, the Company has a significant inventory of medium depth projects which remain economically attractive under the new regime, however, the announced royalty changes decreases the economics of deeper higher risk-reward targets such as the Company's Tower Creek-Wabamun prospect.

ASSET BACKED COMMERCIAL PAPER

Delphi has never held funds in asset-backed commercial paper (ABCP) and is not directly impacted by the current liquidity crunch. In July 2007, the U.S sub-prime mortgage market worsened and investors in Canadian ABCP became concerned there would be a fall-out in Canada as well with the potential for Canadian issuer trusts facing credit quality issues. In mid-August, a number of sponsors of non-bank ABCP announced it was not possible to place new ABCP due to unfavorable conditions. This resulted in numerous companies, including companies in the oil and gas sector, not being able to access their funds when the ABCP became ordinarily due resulting in a severe lack of liquidity. Delphi will continue to monitor the liquidity crunch and its potential impact on the oil and gas industry.

OUTLOOK

Delphi is maintaining a conservative view of the timeline to recovery of the North American natural gas market fundamentals. Record LNG imports through the first half of 2007 in the U.S. have largely offset reduced industry activity in Canada, putting continued pressure on the supply and demand fundamentals of the natural gas markets. Natural gas drilling in the U.S. is showing signs of slowing after sustained record levels of drilling activity. LNG imports are also beginning to moderate as demand shifts to other parts of the world. However, this oversupply condition of the natural gas markets could continue through 2008. The Company will continue to take advantage of the significant volatility in natural gas future strip pricing by maintaining an active risk management program through 2008 and into 2009. The Company has approximately 43 percent of its current natural gas production hedged from November 2007 to March 2008 at a minimum floor price of $9.11 per mcf, approximately 30 percent from April 2008 through to the end of October 2008 at a fixed price of $7.76 per mcf, and approximately seven percent from November 2008 to March 2009 at a fixed price of $7.69 per mcf.

Delphi is maintaining its near-term capital budget expectations within forecasted cash flow. The Company plans to spend approximately $27 million to $33 million through the fourth quarter 2007 and first quarter 2008, drilling up to 14 wells, in addition to the previously highlighted optimization and recompletion projects. Positive results from the capital program, coupled with moderating industry service and equipment costs and secure financial resources continue to be the key drivers of Delphi's capital investment decision-making as it finalizes the winter capital program, all in the context of natural gas price forecasts and Alberta royalty regime changes.

Delphi reiterates its fourth quarter production volume estimate of 5,800 boe/d. Operating costs are forecast to drop an additional five to seven percent through the fourth quarter of 2007 providing additional growth in funds from operations. Forecast year-end net debt of approximately $98 million and continued growth of funds from operations is expected to improve the debt to funds flow ratio at year-end to less than 1.8. The Company expects average first quarter 2008 production to be approximately 6,000 boe/d, a 35 percent increase over the first quarter 2007.

A conference call is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Monday, November 5, 2007. The conference call number is 1-866-542-4236 or 416-641-6125. A brief presentation by David J. Reid, Delphi's President & CEO and Brian Kohlhammer, VP Finance & CFO will be followed by a question and answer period.

Mr. Reid will also be presenting in New York City at the 10th Annual Energy Exploration and Production Conference sponsored by The New York Society of Security Analysts (NYSSA) at 1:35 p.m. Mountain Time (3:35 p.m. Eastern Time) on November 6, 2007. Mr. Reid's presentation will be webcast live from the conference through Delphi's website at www.delphienergy.ca. The NYSSA is celebrating 70 years as a leading forum for the investment community. With over 10,000 members, NYSSA is the largest of the 134 financial analyst societies worldwide that comprise the CFA Institute.

Delphi's third quarter 2007 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.


Management's Discussion and Analysis

(all tabular amounts are expressed in thousands of CDN dollars, except per unit amounts)

The following discussion and analysis has been prepared by management and reviewed and approved by the Board of Directors of Delphi Energy Corp ("Delphi" or "the Company"). The discussion and analysis is a review of the financial results of the Company based upon accounting principles generally accepted in Canada. Its focus is primarily a comparison of the financial performance for the three and nine months ended September 30, 2007 and 2006 and should be read in conjunction with the audited financial statements and accompanying notes for the year ended December 31, 2006. The discussion and analysis has been prepared as of November 2, 2007.

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

NON GAAP Measures. The MD&A contains the terms "funds from operations", "funds from operations per share" and "netbacks" which are not recognized measures under Canadian generally accepted accounting principles. The Company uses these measures to help evaluate its performance. Management considers netbacks an important measure as it demonstrates its profitability relative to current commodity prices. Management uses funds from operations to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and to repay debt. Funds from operations 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.

Forward-Looking Statements. Certain information regarding Delphi Energy Corp. set forth in this document, including management's assessment of the Company's future plans and operations, contains forward-looking statements that involve substantial known and unknown risks and uncertainties. These forward-looking statements are subject to numerous risks and uncertainties, certain of which are beyond the Company's control, including the effects of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other oil and gas companies, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from both internal and external sources. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements, and accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur.



Production

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
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Natural gas (mcf/d) 28,196 25,403 11 25,631 25,972 (1)
Crude oil (bbl/d) 579 444 30 457 506 (10)
Natural gas liquids
(bbl/d) 422 412 2 410 477 (14)
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Total (boe/d) 5,700 5,090 12 5,139 5,312 (3)
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Production for the three months ended September 30, 2007 (the "Quarter") averaged 5,700 boe/d representing an increase of six percent over the second quarter of 2007 and a 32 percent increase over the first quarter of 2007. Production guidance for the Quarter, had been originally set at 5,500 boe/d and then revised upward to 5,600 boe/d during the Quarter. Delphi continues to increase production through the drill bit in a very challenging environment, a testament to the quality of the Company's asset base. Throughout 2007, Delphi has been able to add production at less than $20,000 per flowing boe, and with the recently announced Hythe swap, Delphi believes it can continue to add production at these attractive metrics. Production increased 12 percent over the comparative quarter due to a successful drilling program in Bigstone and the tie in of the Tower 2-21 discovery well. Bigstone continues to be the Company's top performing region accounting for 52 percent of corporate production in the Quarter. The Company's production portfolio for the Quarter was weighted 82 percent to natural gas, 10 percent to crude oil and eight percent to natural gas liquids.

Year to date 2007 production was 5,139 boe per day consisting of 25,631 mcf per day of natural gas, 457 bbl per day of crude oil and 410 bbl of natural gas liquids. Year to date production is 3 percent lower than the same period of 2006 due to high initial flush rates from wells drilled in Bigfoot.



Commodity Prices and Risk Management

Benchmark Prices

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
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Natural gas
NYMEX (US $/mmbtu) 6.25 6.12 2 6.99 7.47 (6)
AECO (CDN $/mcf) 5.20 5.72 (9) 6.57 6.40 3
Crude oil
West Texas Intermediate
(US $/bbl) 75.15 70.60 6 66.13 68.23 (3)
Edmonton Light (CDN $/bbl) 80.25 80.31 - 73.97 75.69 (2)
Foreign exchange rate
Canadian to US dollar 1.05 1.12 (7) 1.10 1.13 (3)
US to Canadian dollar 0.96 0.89 8 0.91 0.88 3
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Natural Gas

United States natural gas prices are commonly referenced to the New York Mercantile Exchange Henry Hub in Louisiana (NYMEX) while Canadian natural gas prices are typically referenced to the AECO Hub in Alberta. Natural gas prices are influenced more by North American supply and demand than global fundamentals. Natural gas prices decreased nine percent over the comparative quarter and increased three percent over the prior year. The Quarter saw a divergence in commodity prices as West Texas Intermediate (WTI) crude oil averaged an all time high, while AECO natural gas prices averaged $5.20 per thousand cubic feet, an average quarterly price not realized since the third quarter of 2002. There continues to be concerns over the unprecedented level of natural gas in storage. In early August natural gas storage levels surpassed the record levels of 2006. The large increase in natural gas in storage has primarily been due to higher than average liquefied natural gas (LNG) import levels which have counterbalanced the lower Canadian supply levels. However, after reaching the high in August, the weekly injections have been below last year's levels partly because LNG imports fell by approximately 50 percent to an average of 1.5 Bcf/d in September, which is consistent with the 5 year average.

Delphi expects prices to remain volatile throughout 2007 and as such, continues to monitor forward price curves towards extending its price protection strategy to protect the Company's capital program and its balance sheet. For natural gas production, Delphi has protected approximately 50 percent of natural gas production through year-end 2007 at a floor of approximately $8.64 per thousand cubic feet ("mcf") and 43 percent through the first quarter of 2008 at a floor of approximately $9.11 per mcf. Delphi will layer in additional fixed price contracts when prudent.

Crude Oil

West Texas Intermediate at Cushing, Oklahoma 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.

Crude prices have increased over the comparative quarter despite fears of a U.S. recession resulting from the subprime fallout. On September 18, the Federal Open Market Committee lowered its target for the federal funds rate by 50 basis points to help mitigate the adverse effects resulting from the disruptions in the financial markets and to promote moderate growth over time. The outlook for oil remains bullish with prospects for another year of healthy global economic growth pointing to increasing demand for oil. The gain in oil prices, especially at the end of the Quarter, was partially offset by a strong increase in the Canadian dollar which recently moved to parity for the first time since the mid - 70's.

Prices for heavy oil and other lesser quality crudes trade at a discount or differential to light crude oil due to the additional costs in the refining process. Delphi primarily receives a Bow River crude price, a benchmark for medium grade oil and as such continues to receive a discount to WTI. As the development of the Cardium light oil play continues, the price received by Delphi for oil production will more closely correlate to the WTI price.

Risk Management Activities

Delphi enters into both financial and physical commodity contracts as part of its risk management program to manage commodity price fluctuations 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 historical three to five year price band and is quick to react on price aberrations such as those experienced at the end of 2005. Another component of the risk management program is to layer fixed price contracts in over a period of time as opposed to locking in a significant portion of volumes at any one point in time to take advantage of price spikes over time. For natural gas production, Delphi has protected approximately 50 percent of natural gas production volumes through year-end 2007 at a floor of approximately $8.64 per thousand cubic feet and 43 percent through the first quarter of 2008 at a floor of approximately $9.11 per mcf.

On January 1, 2007 the Company adopted the new accounting standards regarding the accounting for financial instruments. In addition to the adoption of the new standards, management has elected not to use hedge accounting and consequently records the fair value of its natural gas financial contracts at each reporting period with the change in the fair value being classified as unrealized gains and losses in the statement of earnings.

The Company recognized an unrealized non-cash gain on risk management activities for the nine months ended September 30, 2007 of $1.7 million and an unrealized non-cash loss of $0.2 million on financial contracts in the Quarter. 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 with reference 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:

Canadian
Type of Quantity Price
Time Period Commodity Contract Contracted (CDN$/unit)
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April 2007 Natural Gas Physical 3,000 GJ/d $8.75 floor
- October 2007 /$9.55 ceiling
April 2007 Natural Gas Physical 4,000 GJ/d $8.00 floor
- October 2007 /$8.92 ceiling
April 2007 Natural Gas Physical 2,000 mmbtu/d $8.94 fixed
- October 2007
April 2007 Natural Gas Physical 2,000 GJ/d $6.50 floor
- October 2007 /$8.15 ceiling
April 2007 Natural Gas Financial 2,000 GJ/d $6.50 floor
- October 2007 /$9.00 ceiling
April 2007 Natural Gas Financial 1,500 GJ/d $7.09 fixed
- October 2007
April 2007 Natural Gas Financial 1,500 GJ/d $7.10 fixed
- October 2007
November 2007 Natural Gas Financial 2,000 GJ/d $6.50 floor
- December 2007 /$10.45 ceiling
November 2007 Natural Gas Physical 3,000 GJ/d $9.00 floor
- March 2008 /$9.98 ceiling
November 2007 Natural Gas Physical 2,000 mmbtu/d $11.07 fixed
- March 2008
November 2007 Natural Gas Physical 2,000 GJ/d $7.75 floor
- March 2008 /$9.03 ceiling
November 2007 Natural Gas Physical 2,000 GJ/d $8.00 floor
- March 2008 /$10.02 ceiling
November 2007 Natural Gas Financial 1,500 GJ/d $8.55 fixed
- March 2008
November 2007 Natural Gas Physical 1,500 GJ/d $8.55 fixed
- March 2008
April 2008 Natural Gas Physical 4,000 GJ/d $7.21 fixed
- October 2008
April 2008 Natural Gas Physical 3,000 GJ/d $7.61 fixed
- October 2008
April 2008 Natural Gas Physical 2,000 GJ/d $7.30 fixed
- March 2009

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The Company has elected to account for its physical commodity 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. Prior to adoption of the new standards, physical delivery contracts did not fall within the definition of a financial instrument and were also accounted for as executory contracts.



Realized Sales Prices

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
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Natural gas ($/mcf) 6.93 7.20 (4) 8.12 7.93 2
Gain/(loss) on financial
contracts ($/mcf) 0.27 - - 0.10 (0.03) -
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Realized gas price ($/mcf) 7.20 7.20 - 8.22 7.90 4
Crude oil ($/bbl) 61.97 61.02 2 58.77 54.73 7
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Realized oil price ($/bbl) 61.97 61.02 2 58.77 54.73 7
Natural gas liquids
($/bbl) 66.49 59.81 11 57.63 58.66 (2)
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Total realized sales price
($/boe) 46.81 46.10 2 50.82 49.14 3
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During the Quarter, the average realized gas price remained constant with the comparable period despite a nine percent decrease in the average AECO price. The inelasticity of the average price received is directly related to Delphi's effective risk management program. For the three and nine months ended September 30, 2007, Delphi benefited from its risk management program in which the Company fixed the price on a portion of its natural gas production at amounts significantly higher than the AECO spot price. The risk management program increased the average price received by approximately $1.49 per mcf with physical fixed price contracts adding $1.22 per mcf and financial fixed price contracts adding $0.27 per mcf. 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 3,500 mmbtu per day on the Alliance pipeline which is priced at the Chicago Monthly Index. For the nine months ended September 30, 2007, Delphi's average realized gas price has increased 12 percent while AECO average price has increased only 3 percent, demonstrating the Company's effective risk management program. The risk management program has increased the average price received for the nine months ended September 30, 2007 by $1.11 per mcf.

Delphi's oil production is predominantly a medium grade oil; therefore the Company's average price fluctuates with the quality differential. Realized natural gas liquids prices have increased due to the increase in price received for condensate, the primary component of the Company's natural gas liquid production.



Revenue

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
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Natural gas 17,970 16,827 7 56,799 56,246 1
Crude oil 3,301 2,493 32 7,333 7,561 (3)
Natural gas liquids 2,581 2,267 14 6,450 7,639 (16)
Realized gain/(loss) on
financial contracts 695 - - 719 (185) -
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Total 24,548 21,587 14 71,301 71,261 -
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For the three months ended September 30, revenue increased 14 percent due to a 2 percent increase in the realized sales price and a 12 percent increase in production volumes. Year to date, revenue is consistent with the prior year due to a 3 percent increase in the realized price received offset by a 3 percent decrease in production volumes.



Royalties

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
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Total 3,437 2,663 29 10,488 10,921 (4)
Per boe 6.55 5.69 15 7.48 7.53 (1)
Percent of total revenue 14.0 12 13 14.7 15 (4)
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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.

During the Quarter, royalties as a percentage of revenue increased to 14 percent due to the elimination of the Alberta Royalty Tax Credit (ARTC) and increased volumes from the Bigstone area which has higher than corporate average royalty rates. The increase in royalties from the Bigstone area was partially offset by the Tower 2-21 discovery remaining on deep gas royalty credit for the Quarter. In the Quarter, Delphi realized approximately $3.9 million in hedging gains which are included in revenue but on which royalties are not payable. Delphi pays royalties based on the provincial reference price, not the prices received, resulting in Delphi not paying royalties on the incremental $3.9 million in hedging gains. In the Quarter, approximately 16 percent of Delphi's total revenue was not subject to royalties. For the nine months ended September 30, 2007 approximately 11 percent of Delphi's total revenue was not subject to royalties which is consistent with the comparable period in 2006. Delphi is expecting royalties as a percentage of revenue, before hedging, to be between 17 and 20 percent in 2007.



Operating Expenses

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Total 4,352 4,035 8 12,987 11,967 9
Per boe 8.30 8.62 (4) 9.26 8.25 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Operating expenses on a per boe basis for the three months ended September 30, 2007 decreased four percent from the comparable period and 15 percent from the second quarter of 2007. As expected, due to the increase in production volumes and a corporate focus on cost reduction, operating costs decreased significantly from the second quarter of 2007 and are expected to decrease further over the next several quarters. On a gross basis, operating costs have decreased nine percent from the second quarter of 2007 despite a six percent increase in production volumes. With the addition of the Hythe assets acquired in the Quarter, Delphi is expecting further cost reduction as the area has lower than corporate average operating costs. The Company's core area of Bigstone, Alberta continues to operate at a very efficient cost of approximately $4.50 per boe. For the nine months ended September 30, 2007, operating costs have increased nine percent on a gross basis and 12 percent per boe. The higher costs are due to a higher level of workover and maintenance activity than the previous year and cost adjustments from prior years in several non-operated areas.



Transportation Expenses

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Total 1,530 1,733 (12) 4,761 4,828 (1)
Per boe 2.92 3.70 (21) 3.39 3.33 2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In British Columbia, infrastructure is owned by Duke 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 gross cost and per boe basis, respectively, transportation costs for the three months ended September 30, 2007 decreased by 12 percent and 20 percent due to higher production volumes with fixed firm service commitment fees for transportation. With the Hythe swap, Delphi is expecting transportation costs to decrease in the fourth quarter of 2007 and again in the first quarter of 2008. For the nine months ended September 30, 2007, transportation costs on a gross basis and a per boe basis are consistent with the comparable period.



General and Administrative

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
General and administrative
costs 1,413 1,118 26 4,638 4,158 12
Overhead recoveries (158) (202) (22) (515) (944) (45)
Salary allocations (607) (414) 47 (1,862) (1,631) 14
----------------------------------------------------------------------------
Net 648 502 29 2,261 1,583 43
Per boe 1.24 1.07 15 1.61 1.09 48
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On a per boe basis, general and administrative (G&A) costs for the three and nine months ended September 30, 2007 increased 15 percent and 48 percent over the comparative periods in 2006, however, decreased 28 percent on a per boe basis from the second quarter of 2007. As a result of high levels of activity for Delphi and for the industry as a whole, the costs associated with hiring, compensating and retaining employees and consultants have risen. Delphi is committed to continue to deliver strong growth and believes a strong technical team is paramount to achieve this goal and as such hired a senior exploitation engineer and a senior geologist in the Quarter. Delphi is expecting G&A per boe to remain flat for the remainder of the year as additional production volumes are offset by an increase in personnel and rent costs.



Stock-based Compensation

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Total 431 311 39 745 2,174 (66)
Per boe 0.82 0.59 39 0.53 1.89 (72)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees, directors and key consultants of the Company. The fair value of all options granted is estimated at the date of grant using the Black-Scholes option pricing model. The non-cash compensation expense for the three months ended September 30, 2007, increased 39 percent due to the cancelling of certain stock options in which the Company recognized the unvested portion of the stock based compensation. In addition, the Company granted 1.5 million stock options to employees, excluding officers, and key consultants under the existing stock option plan. During the three and nine months ended September 30, 2007, Delphi capitalized $0.5 million and $0.8 million of stock-based compensation associated with exploration and development activities.



Interest and Financing

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Total 1,981 1,752 13 6,070 4,228 44
Per boe 3.78 3.74 1 4.33 2.92 48
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the Quarter, interest and financing costs increased 13 percent over the prior year due to higher interest rates and Part 12.6 tax associated with the flow through financing in 2006 offset by lower debt levels. The Part 12.6 tax is a monthly finance charge payable to the Canada Revenue Agency until flow through obligations have been satisfied. For the nine months ended September 30, 2007 interest and financing costs increased 44 percent from the previous year due to higher average debt levels, higher Part 12.6 tax, and higher interest rates. Delphi anticipates interest per boe will continue to decrease throughout the year as debt remains flat and additional production is brought on stream.



Depletion, Depreciation and Accretion

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Depletion and
depreciation 13,643 9,345 46 35,002 28,637 22
Accretion expense 131 161 (19) 453 464 (2)
----------------------------------------------------------------------------
Total 13,774 9,506 45 35,455 29,101 22
Per boe 26.26 20.31 29 25.27 20.07 26
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Depletion, depreciation, and accretion per boe for the three and nine months ended September 30, 2007 increased 29 percent due to higher cost proved reserve additions. Throughout 2006, Delphi invested a significant amount of capital towards field infrastructure, allocated to depletable costs on a reasonable basis, which does not increase proved reserves but is critical to current operations and future development plans. With the recently completed Hythe transaction and success at Bigstone and Noel, Delphi is in an excellent position to add proved reserves at metrics considerably below the Company's current depletion rate.



Taxes

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Total (411) 423 - 329 491 (33)
Per boe (0.78) 0.90 - 0.23 0.34 (31)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The provision for income taxes in the financial statements for the three and nine months ended September 30, 2007, differs from the result that would have been obtained by applying the combined federal and provincial tax rates to the Company's before tax loss, primarily due to the impairment of goodwill. Although the Company records the loss for accounting purposes, it is unable to claim the loss for tax purposes. Delphi does not anticipate it will be cash taxable until 2009 or later based on current commodity prices.

Goodwill

Goodwill, at the time of acquisition, represents the excess of purchase price of a business over the fair value of net assets acquired. Goodwill is assessed by the Company for impairment at least each year end. If the fair value of the business is less than the book value, a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the business' assets and liabilities from the fair value of the business to determine the implied fair value of goodwill and comparing that amount to the book value of goodwill. Any excess of the book value of goodwill over the implied fair value is the impairment amount and is charged to earnings in the period of the impairment.

The Company reviewed the valuation of goodwill as at March 31, 2007 based on the latest available information including the market capitalization of the Company as indicated by the Company's share price at that time. Based upon this review, an impairment of goodwill of $12.1 million was recorded as a non-cash charge to earnings in the first quarter of 2007. The Company notes the write-down is a non-cash charge and does not believe it is an indication of the ultimate underlying value of the Company assets.



Funds from Operations

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Net earnings (1,348) 658 - (12,204) 6,613 -
Non-cash items
Depletion, depreciation
and accretion 13,774 9,506 45 35,455 29,101 22
Impairment of goodwill - - 12,100 - -
Unrealized loss/(gain) on
risk management
activities 154 - - (1,691) (645) 162
Stock-based compensation
expense 431 315 37 745 2,174 (66)
Future income taxes (411) 423 - 329 491 (33)
----------------------------------------------------------------------------
Funds from operations 12,600 10,902 16 34,734 37,734 (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and nine months ended September 30, 2007 funds from operations were $12.6 million ($0.19 per basic share) and $34.7 million ($0.52 per basic share) compared to $10.9 million (2006 - $0.18 per basic share) and $37.7 million (2006 - $0.66 per basic share). Funds from operations increased 10 percent from the second quarter of 2007 despite a 27 percent decrease in the average AECO price.



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

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Funds from operations:
Non-GAAP 12,600 10,902 16 34,734 37,734 (8)
Settlement of asset
retirement obligations (11) (65) (83) (457) (405) 13
Change in non-cash
working capital (1,541) (12,027) (87) 4,095 5,325 (23)
----------------------------------------------------------------------------
Cash flow from operating
activities: GAAP 11,048 (1,190) (1,028) 38,372 42,654 (10)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net Earnings/Loss

For the three and nine months ended September 30, 2007, Delphi recorded a net loss of $1.3 million and $12.2 million. Earnings for the nine-month period were adversely affected by non-cash items such as depletion, depreciation, accretion, stock-based compensation, future income taxes and the impairment of goodwill. These non-cash items represent the majority of the significant difference between funds from operations and net earnings.



Netback Analysis

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Barrels of oil equivalent
($/boe)
Realized sales price 46.81 46.10 2 50.82 49.14 3
Royalties, net of ARTC 6.55 5.69 15 7.48 7.53 (1)
Operating expenses 8.30 8.62 (4) 9.26 8.25 12
Transportation 2.92 3.70 (21) 3.39 3.33 2
----------------------------------------------------------------------------
Operating netback 29.04 28.09 3 30.69 30.03 2
G&A 1.24 1.07 15 1.61 1.09 48
Interest 3.78 3.74 1 4.33 2.92 48
Current taxes - - - - - -
----------------------------------------------------------------------------
Cash netback 24.02 23.28 3 24.75 26.02 (5)
Unrealized (gain)/loss on
financial contracts 0.29 - - (1.21) (0.44) 174
Stock-based compensation
expense 0.82 0.67 23 0.53 1.50 (65)
Depletion, depreciation
and accretion 26.26 20.31 29 25.27 20.07 26
Impairment of goodwill - - - 8.62 - -
Future income taxes
(recovery) (0.78) 0.90 - 0.23 0.34 (31)
----------------------------------------------------------------------------
Net earnings (loss) (2.57) 1.40 - (8.69) 4.55 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Approximately 82 percent of Delphi's production is natural gas and therefore Delphi's netbacks are primarily driven by the price received for natural gas. Delphi has an active risk management program to mitigate some of the volatility in commodity prices.



Drilling Results

Three Months Ended Nine Months Ended
September 30 September 30
Gross Net Gross Net
----------------------------------------------------------------------------
Natural gas wells 4.0 2.4 8.0 4.5
Oil wells - - 2.0 0.5
Dry holes 1.0 0.3 1.0 0.3
----------------------------------------------------------------------------
Total wells 5.0 2.7 11.0 5.3
Success rate (%) 80 89 91 94
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Capital Invested

Three Months Ended Nine Months Ended
September 30 September 30
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Land 217 90 141 230 3,043 (92)
Seismic 223 20 1,015 437 10,070 (96)
Drilling and completions 12,485 14,232 (12) 25,229 82,929 (70)
Equipping and facilities 1,142 13,154 (91) 6,942 54,491 (87)
Property acquisition - - - 10,871 1,188 815
Property disposition (15,502) - - (15,502) - -
Capitalized expenses 518 370 40 1,683 1,457 16
Other 41 20 105 412 50 724
----------------------------------------------------------------------------
Capital invested (876) 27,886 (103) 30,302 153,228 (80)
Asset retirement costs 697 95 634 753 463 63
----------------------------------------------------------------------------
Total capital invested (179) 27,981 (101) 31,055 153,691 (80)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the Quarter, Delphi drilled five wells resulting in three new discoveries, a development well in Bigstone and a junked and abandoned well at Tower Creek. The capital program in the Quarter continues to be very efficient, with production additions being added at approximately $20,000 per flowing boe. The majority of capital in 2007 has been allocated to drilling operations, the acquisition of an additional 10.5 percent working interest in the 2-21 Leduc exploration discovery and the construction and commissioning of the Tower Creek facility. The significant difference in capital spent year to date versus the comparative period is due to the $90.0 million capital program in the Bigfoot area of North East British Columbia in 2006.



Liquidity and Capital Resources

Funding

Three Months Ended Nine Months Ended
September 30, 2007 September 30, 2007
----------------------------------------------------------------------------
Sources:
Funds from operations 12,600 34,734
Disposition of petroleum and natural gas
properties 15,502 15,502
Issue of flow through shares, net of issue
costs - 16,877
Issue of common shares, net of issue costs - 32
Change in non-cash working capital 309 4,233
----------------------------------------------------------------------------
28,411 71,378

Uses:
Cash 874 117
Capital expenditures 14,626 34,933
Acquisition of petroleum and natural gas
properties - 10,871
Expenditures on site restoration and
reclamation 11 457
----------------------------------------------------------------------------
15,511 46,378

Increase / (decrease) in bank debt (12,900) (25,000)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and nine months ended September 30, 2007, Delphi funded its capital program through a combination of funds from operations, the issuance of flow-through common shares and funds received from the Hythe transaction.

Share Capital

At September 30, 2007, the Company had 68.1 million common shares outstanding (September 30, 2006 - 60.7 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 nine months ended September 30, 2007.



Three Months Ended Nine Months Ended
September 30, 2007 September 30, 2007
----------------------------------------------------------------------------
Weighted Average Common Shares
Basic 68,070 66,461
Diluted 68,179 66,711
Trading Statistics
High $ 1.88 $ 2.38
Low $ 1.37 $ 1.32
Average daily, volume 123,201 259,574
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Trading statistics based on closing price.


As at November 2, 2007 the Company had 68.1 million common shares outstanding and 2.4 milllion stock options outstanding.

Bank Debt plus Working Capital Deficit

At September 30, 2007, the Company had $90.0 million outstanding on its credit facility and a working capital deficit of $7.3 million for total debt plus working capital deficit of $97.3 million excluding the financial asset of $2.0 million relating to the unrealized gain on financial commodity contracts and the $0.7 million relating to the current portion of future income taxes. Debt levels have decreased 18 percent from year end and 12 percent from the second quarter of 2007. Delphi anticipates spending projected funds from operations on capital expenditures during 2007.

The capital intensive nature of the industry will generally result in the Company having a working capital deficit. The Company has a revolving facility for $115.0 million with a syndicate of Canadian chartered banks. The facility is a 364 day committed revolving facility with a one year term out provision. The credit facility bears interest based on a sliding scale tied to the Company's trailing debt to funds flow from operations: from a minimum of the bank's prime rate to a maximum of the bank's prime rate plus 1.0 percent. In addition to the revolving term facility, the Company has a $10.0 million development facility. The pricing grid on the development facility is 0.25 percent higher than the revolving term facility.



Selected Quarterly Information

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

Sept.30 Jun. 30 Mar. 31 Dec. 31
2007 2007 2007 2006
----------------------------------------------------------------------------
Production
Oil and NGLs (bbl/d) 1,001 884 712 829
Natural gas (mcf/d) 28,196 26,967 21,658 24,919
Barrels of oil equivalent (boe/d) 5,700 5,379 4,322 4,982

Financial
($000s, except as noted)
Petroleum and natural gas revenue 24,548 24,779 21,974 22,928
Funds from operations 12,600 11,469 10,665 11,817
Per share - Basic 0.19 0.17 0.17 0.19
Per share - Diluted 0.18 0.17 0.17 0.19
Net earnings (loss) (1,348) 797 (11,653) 290
Per share - Basic (0.02) 0.01 (0) -
Per share - Diluted (0.02) 0.01 (0) -

Capital invested 14,626 15,182 15,996 12,124
Dispositions (15,502) - - (17,867)
----------------------------------------------------------------------------
Net Capital Invested (876) 15,182 15,996 (5,743)

Per unit information
Natural gas ($/mcf) 7.20 8.20 9.61 8.41
Oil and natural gas liquids ($/bbl) 63.87 58.51 50.64 48.39
Oil equivalent ($/boe) 46.81 50.63 56.49 50.02
Operating netback ($/boe) 29.04 29.09 34.95 31.92
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Sept. 30 Jun. 30 Mar. 31 Dec. 31
2006 2006 2006 2005
----------------------------------------------------------------------------
Production
Oil and NGLs (bbl/d) 856 1,034 1,062 1,028
Natural gas (mcf/d) 25,403 28,797 23,695 22,909
Barrels of oil equivalent (boe/d) 5,090 5,834 5,011 4,846

Financial
($000s, except as noted)
Petroleum and natural gas revenue 21,587 25,865 23,809 28,961
Funds from operations 10,902 14,452 12,380 16,118
Per share - Basic 0.18 0.26 0.22 0.31
Per share - Diluted 0.18 0.26 0.22 0.31
Net earnings (loss) 658 4,768 1,187 6,425
Per share - Basic 0.01 0.09 0.02 0.13
Per share - Diluted 0.01 0.09 0.02 0.12

Capital invested 27,886 44,313 81,029 29,056
Dispositions (1,331) (15,720) - -
----------------------------------------------------------------------------
Net Capital Invested 26,555 28,593 81,029 29,056

Per unit information
Natural gas ($/mcf) 7.20 7.59 8.54 11.69
Oil and natural gas liquids ($/bbl) 61.10 63.43 46.79 45.70
Oil equivalent ($/boe) 46.10 48.72 52.79 64.94
Operating netback ($/boe) 27.61 31.28 30.55 39.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Contractual Obligations

The Company is committed, under contracts of varying lengths, for the utilization of gathering, processing and pipeline capacity on a major natural gas processing and gathering system in North East British Columbia. The future minimum commitments are as follows:



----------------------------------------------------------------------------
2007 $ 1,152
2008 4,429
2009 4,111
2010 4,087
2011 3,661
2012 - 2015 6,938
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company has incurred the necessary qualifying exploration expenditures to satisfy the terms of the flow-through shares issued in 2005. 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. At September 30, 2007 the Company has an obligation to spend approximately $5.5 million on qualifying exploration expenditures by December 31, 2007 to satisfy the obligation relating to the issuance of flow-through shares in 2006. The Company has an obligation to incur qualifying exploration expenditures of $18.0 million by December 31, 2008 to satisfy the obligation relating to the issuance of flow-through shares in 2007.

Guarantees and Off-balance Sheet Arrangements

Delphi has not entered into any off-balance sheet arrangements or guarantees.

Business Conditions and Risk

See the Company's 2006 Annual Information Form (AIF) for a listing of certain risks.

Critical Accounting Estimates

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

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

- Depletion, depreciation and accretion based on estimates of oil and gas reserves;

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

- Estimated capital expenditures on projects that are in progress;

- Estimated fair value of derivative contracts;

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

- Estimated fair value of the Company in performing the goodwill impairment test.

Change in Accounting Policies

Effective January 1, 2007, the Company adopted the new Canadian accounting standards for financial instruments - recognition and measurement; financial instruments - presentation and disclosure, hedging and comprehensive income. The Company has adopted these standards prospectively and as such the comparative financial statements have not been restated. The adoption of these standards had no effect on opening retained earnings or accumulated other comprehensive income.

The Company adopted Section 1506 - Accounting Changes, the only effect of which is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with Section 1535 - Capital; Section 3862 - Financial Instruments Disclosures; and Section 3863 - Financial Instruments Presentations; which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Company will adopt these standards on January 1, 2008 and it is expected the only effect on the Company will be incremental disclosures about the Company's financial instruments as well as its capital and how it is managed.

Corporate Governance

Overview

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

Disclosure Controls

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

Current Operating Environment

Alberta Royalty Review

Delphi is evaluating the impact of announced changes to Alberta's royalty structure. On September 18, 2007, a panel of individuals appointed by the Province of Alberta, the "Alberta Royalty Review Panel" released a report outlining its recommendations on how the Government of Alberta should modify the existing royalty regime for oil and gas production. On October 25, 2007, the Government of Alberta, after considering, among other things, that report, announced a new framework for oil and gas royalties effective January 1, 2009. The changes increase the royalties for conventional oil and gas, with sliding scale sensitivities to both commodity prices and well productivity rates. A simplification of the overall royalty regime was also announced including the elimination of oil and gas tiers, the elimination of a number of special royalty programs and expanded royalty rate limits on both oil and gas commodity prices. The Government of Alberta also introduced a deep gas drilling adjustment for wells with a measured depth of greater than 2,000 metres. Due to the nature of Delphi's production and capital program, the inclusion of a deep gas drilling adjustment partially offsets the increased royalty rates.

Based on the information available to date, the Company's preliminary assessment of the changes indicates that in the current price environment the effect on cash flow would be approximately a two to four percent negative adjustment and that there would be no effect on Delphi's net present value of reserves as at December 31, 2006. From the perspective of capital projects, the Company has a significant inventory of medium depth projects which remain economically attractive under the new regime, however, the announced royalty changes decreases the economics of deeper higher risk-reward targets such as the Company's Tower Creek-Wabamun prospect.

Asset Backed Commercial Paper

Delphi has never held funds in asset-backed commercial paper (ABCP) and is not directly impacted by the current liquidity crunch. In July 2007, the U.S sub-prime mortgage market worsened and investors in Canadian ABCP became concerned there would be a fall-out in Canada as well with the potential for Canadian issuer trusts facing credit quality issues. In mid-August, a number of sponsors of non-bank ABCP announced it was not possible to place new ABCP due to unfavorable conditions. This resulted in numerous companies, including companies in the oil and gas sector, not being able to access their funds when the ABCP became ordinarily due resulting in a severe lack of liquidity. Delphi will continue to monitor the liquidity crunch and its potential impact on the oil and gas industry.

SEDAR Filing

Additional information about Delphi is available on the Canadian Securities Administrators' System for Electronic Distribution and Retrieval (SEDAR) at www.sedar.com and at the Company's website at www.delphienergy.ca.



DELPHI ENERGY CORP.
Consolidated Balance Sheets (unaudited)


September 30 December 31
($CDN thousands) 2007 2006
----------------------------------------------------------------------------
Assets
Current assets:
Cash 874 757
Accounts receivable 13,031 16,097
Prepaid expenses and deposits 1,114 1,460
Risk management asset (Notes 3 & 8) 2,039 348
----------------------------------------------------------------------------
17,058 18,662

Property, plant and equipment (Note 4) 293,100 295,906
Goodwill (Note 10) - 12,100
----------------------------------------------------------------------------
Total assets 310,158 326,668
----------------------------------------------------------------------------

Liabilities
Current liabilities:
Accounts payable and accrued liabilities 22,313 21,492
Current portion of future income taxes 702 -
----------------------------------------------------------------------------
23,015 21,492
Long term debt (Note 5) 90,000 115,000
Future income taxes 30,877 23,776
Asset retirement obligations (Note 6) 8,700 7,951
----------------------------------------------------------------------------
Total liabilities 152,592 168,219

Shareholders' equity
Share capital (Note 7) 148,910 139,108
Contributed surplus (Note 7) 7,146 5,627
Retained earnings 1,510 13,714
----------------------------------------------------------------------------
Total shareholders' equity 157,566 158,449
----------------------------------------------------------------------------
Total liabilities and shareholders' equity 310,158 326,668
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Contractual obligations and commitments (Note 9)

See accompanying notes to the consolidated financial statements.



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

Three Months Ended Nine Months Ended
($CDN thousands, except per unit September 30 September 30
amounts) 2007 2006 2007 2006
----------------------------------------------------------------------------

Revenue:
Petroleum and natural gas sales 23,853 21,587 70,582 71,446
Realized gain/(loss) on risk
management activities 695 - 719 (185)
----------------------------------------------------------------------------
24,548 21,587 71,301 71,261
Royalties (3,437) (2,663) (10,488) (10,921)
Unrealized gain/(loss) on risk
management activities (154) - 1,691 645
----------------------------------------------------------------------------
20,957 18,924 62,504 60,985

Expenses:
Operating 4,352 4,035 12,987 11,967
Transportation 1,530 1,733 4,761 4,828
General and administrative 648 502 2,261 1,583
Stock-based compensation (Note 7) 431 315 745 2,174
Interest 1,981 1,752 6,070 4,228
Depletion, depreciation and accretion 13,774 9,506 35,455 29,101
Impairment of goodwill (Note 10) - - 12,100 -
----------------------------------------------------------------------------
22,716 17,843 74,379 53,881

----------------------------------------------------------------------------
Earnings/(loss) before taxes (1,759) 1,081 (11,875) 7,104

Taxes:
Future/(recovery) (411) 423 329 491
----------------------------------------------------------------------------
(411) 423 329 491

----------------------------------------------------------------------------
Net earnings/(loss) and comprehensive
income/(loss) (1,348) 658 (12,204) 6,613
Retained earnings, beginning of period 2,858 12,766 13,714 6,811
----------------------------------------------------------------------------
Retained earnings, end of period 1,510 13,424 1,510 13,424
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Earnings/(loss) per share (Note 7)
Basic (0.02) 0.01 (0.18) 0.12
Diluted (0.02) 0.01 (0.18) 0.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.



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

Three Months Ended Nine Months Ended
September 30 September 30
($CDN thousands) 2007 2006 2007 2006
----------------------------------------------------------------------------

Cash flow from operating activities
Operations:
Net earnings/(loss) (1,348) 658 (12,204) 6,613
Add non cash items:
Depletion, depreciation and accretion 13,774 9,506 35,455 29,101
Impairment of goodwill - - 12,100 -
Stock-based compensation 431 315 745 2,174
Unrealized loss/(gain) on risk
management activities 154 - (1,691) (645)
Future/(recovery) taxes (411) 423 329 491
Expenditures on asset retirement
obligations (11) (65) (457) (405)
Change in non-cash working capital
(Note 11) (1,541) (12,027) 4,095 5,325
----------------------------------------------------------------------------
11,048 (1,190) 38,372 42,654

Cash flow from financing activities
Issue of common shares, net of issue
costs - - 32 286
Issue of flow-through common shares,
net of issue costs - (48) 16,877 23,297
Increase/(decrease) in bank debt (12,900) 18,289 (25,000) 66,589
----------------------------------------------------------------------------
(12,900) 18,241 (8,091) 90,172
Cash flow used in investing
activities
Capital expenditures (14,626) (27,886) (34,933) (153,228)
Acquisition of petroleum and natural
gas properties - - (10,871) -
Disposition of petroleum and natural
gas properties 15,502 1,331 15,502 17,051
Change in non-cash working capital
(Note 11) 1,850 9,504 138 3,351
----------------------------------------------------------------------------
2,726 (17,051) (30,164) (132,826)

Increase in cash and cash equivalents 874 - 117 -
Cash and cash equivalents, beginning
of period - - 757 -
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period 874 - 874 -
----------------------------------------------------------------------------

Interest paid 1,796 1,618 5,496 3,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.



DELPHI ENERGY CORP.
Notes to Consolidated Financial Statements
As at and for the periods ended September 30, 2007 and 2006 (unaudited)
(all tabular amounts are expressed in thousands of CDN dollars, except per
unit amounts)


NOTE 1: DESCRIPTION OF BUSINESS

Delphi Energy Corp. ("the Company" or "Delphi") is incorporated under the Business Corporations Act (Alberta) and is a public company listed on the Toronto Stock Exchange. Delphi is primarily engaged in the exploration for and development and production of natural gas 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, 2006, except as described in Note 3. The disclosures provided below are incremental to those included with the annual financial statements. The interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto in the Company's Annual Report for the year ended December 31, 2006. The preparation of financial statements in accordance with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results may differ from these estimates.

NOTE 3: CHANGE IN ACCOUNTING POLICIES

1) Effective January 1, 2007, the Company adopted the new Canadian accounting standards for financial instruments - recognition and measurement; financial instruments - presentation and disclosure, hedging and comprehensive income. The Company has adopted these standards prospectively and as such the comparative financial statements have not been restated. The adoption of these standards had no effect on opening retained earnings or accumulated other comprehensive income.

a) Financial instruments - recognition and measurement:

The new standard prescribes when a financial asset, financial liability or non-financial derivative is to be recognized on the balance sheet and at what amount, requiring fair value or cost-based measures under different circumstances. Financial instruments must be classified into one of the following five categories: held-for-trading, held-to-maturity, loans and receivables, available-for-sale financial assets or other financial liabilities. All financial instruments, including derivatives and non-financial derivatives are measured in the balance sheet at fair value except for loans and receivables, held to maturity investments and other financial liabilities which are measured at amortized cost determined using the effective interest rate method. The accounting for subsequent changes in fair value will depend on initial classification, as follows: held-for-trading financial assets are measured at fair value and changes in fair value are recognized in net earnings; available-for-sale financial instruments are measured at fair value with changes in fair value recorded in other comprehensive income until the investment is derecognized or impaired at which time the amounts are recorded in net earnings.

Upon adoption of these standards, the Company classified its cash as held-for-trading, which is measured at fair value. Accounts receivable are classified as loans and receivables, which are measured at amortized cost. Accounts payable and long term debt are classified as other financial liabilities, which are measured at amortized cost.

b) Derivatives:

All derivative instruments, including embedded derivatives, are recorded on the balance sheet at fair value unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivative instruments are recorded in earnings unless cash flow hedge accounting is used, in which case changes in fair value are recorded in other comprehensive income. The Company has a risk management program whereby the commodity price associated with a portion of its future production is fixed in order to mitigate cash flow volatility resulting from fluctuating commodity prices. The Company sells forward a portion of its future production and enters into a combination of fixed price physical sale contracts with customers and fixed price contracts with financial counterparties. The Company has elected not to use cash flow hedge accounting on its fixed price contracts with financial counterparties resulting in all changes in fair value being recorded in the statement of earnings. The Company has elected to account for its physical commodity 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. Prior to adoption of the new standards, physical receipt and delivery contracts did not fall within the definition of a financial instrument and were also accounted for as executory contracts.

c) Other comprehensive income

The new standards require a new statement of comprehensive income, which is comprised of net earnings and other comprehensive income which, for the Company, related to changes in gains or losses on derivatives designated as cash flow hedges. The Company has combined this new statement with the statement of earnings.

d) Effective interest rate method

Transaction costs attributable to financial instruments classified as other than held-for-trading are included in the recognized amount of the related financial instrument and recognized over the life of the resulting financial instrument.

2) New accounting standards have been issued which will require additional disclosure in the Company's financial statements commencing January 1, 2008 about the Company's financial instruments as well as its capital resources and how they are managed.



NOTE 4: PROPERTY, PLANT AND EQUIPMENT

Accumulated
depletion and Net book
As at September 30, 2007 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas properties $ 309,863 $ 101,950 $ 207,913
Production equipment 103,251 18,406 84,845
Furniture, fixtures and office equipment 781 439 342
----------------------------------------------------------------------------
$ 413,895 $ 120,795 $ 293,100
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2006
----------------------------------------------------------------------------
Petroleum and natural gas properties $ 285,168 $ 71,331 $ 213,837
Production equipment 95,892 14,087 81,805
Furniture, fixtures and office equipment 639 375 264
----------------------------------------------------------------------------
$ 381,699 $ 85,793 $ 295,906
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On September 12, 2007 Delphi closed a transaction whereby the Company's 50 percent working interest in the Bigfoot area in North East British Columbia was exchanged for certain assets in the Hythe area located in North West Alberta and $14.5 million in cash.

As at September 30, 2007, costs in the amount of $13.1 million (December 31, 2006 - $35.8 million) representing unproved properties were excluded from the depletion calculation and estimated future development costs of $11.3 million (December 31, 2006 - $21.7 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. The Company performed a separate impairment review of assets excluded from the ceiling test and determined that no impairment has occurred.

The Company capitalized $1.7 million (September 30, 2006 - $1.5 million) of general and administrative costs directly related to exploration and development activities.

NOTE 5: LONG TERM DEBT

The Company has a revolving facility for $115.0 million with a syndicate of Canadian chartered banks. The facility is a 364 day committed revolving facility with a one year term out provision. The credit facility bears interest based on a sliding scale tied to the Company's trailing debt to cash flow: from a minimum of the bank's prime rate to a maximum of the bank's prime rate plus 1.0 percent.

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

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

NOTE 6: ASSET RETIREMENT OBLIGATIONS

The Company's asset retirement obligations result from working interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations, over the next three to twenty years, is approximately $18.7 million. A credit-adjusted risk-free rate of 8.0 percent and an inflation rate of 2.5 percent were used to calculate the estimated fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below.

September 30 December 31
2007 2006
----------------------------------------------------------------------------
Balance, beginning of period $ 7,951 $ 7,394
Liabilities incurred 1,017 606
Liabilities sold (264) (183)
Liabilities settled (457) (503)
Accretion expense 453 637
----------------------------------------------------------------------------
Balance, end of period $ 8,700 $ 7,951
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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:

September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Outstanding Outstanding
shares shares
(000's) Amount (000's) Amount
----------------------------------------------------------------------------
Balance, beginning of period 60,663 $ 139,108 55,254 $ 123,692
Issue of flow-through common
shares 7,350 18,007 5,209 25,003
Exercise of stock options 57 83 200 305
Allocated from contributed
surplus - 24 - 145
Share issue costs - (1,181) - (1,725)
Future tax effect of share
issue costs - 369 - 528
Tax benefit renounced to
shareholders - (7,500) - (8,840)
----------------------------------------------------------------------------
Balance, end of period 68,070 $ 148,910 60,663 $ 139,108
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

On June 29, 2006, the Company issued 5.2 million flow-through common shares at a price of $4.80 per share for gross proceeds of $25.0 million.

The Company has incurred the necessary qualifying exploration expenditures to satisfy the terms of the flow-through shares issued in 2005. 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. At September 30, 2007 the Company has an obligation to spend approximately $5.5 million on qualifying exploration expenditures by December 31, 2007 to satisfy the obligation relating to the issuance of flow-through shares in 2006. The Company has an obligation to incur qualifying exploration expenditures of $18.0 million by December 31, 2008 to satisfy the obligation relating to the issuance of flow-through shares in 2007.

(c) Stock options:

The Company has established a stock option plan under which it has granted options to acquire common shares to certain officers, directors, employees and key consultants. The plan provides for the granting of options equal to ten percent of the issued and outstanding common shares of the Company. Options issued under the plan have a term of five years to expiry and vest over a two-year period starting on the date of the grant. The exercise price of each option equals the 5 day weighted average of the closing market price of the Company's common shares, immediately preceding the date of the grant. As at September 30, 2007 there were 2.4 million options to purchase shares outstanding. During the month of August, the Board of Directors accepted and approved the cancellation of 3.1 million stock options. In 2007, the Company has granted 1.5 million stock options to employees, excluding officers, and key consultants under the existing stock option plan.



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

September 30, 2007 December 31, 2006
------------------------------------------------
Weighted Weighted
Outstanding average Outstanding average
options exercise options exercise
(000's) price (000's) price
----------------------------------------------------------------------------
Balance, beginning of period 4,229 $ 3.40 2,629 $ 2.37
Granted 1,460 1.58 1,800 4.69
Cancelled (3,192) 4.08 - -
Exercised (57) 1.45 (200) 1.53
----------------------------------------------------------------------------
Balance, end of period 2,440 $ 1.47 4,229 $ 3.40
----------------------------------------------------------------------------
Exercisable at end of period 1,467 $ 1.39 2,641 $ 2.81
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes information about the stock options
outstanding and exercisable at September 30, 2007.

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
----------------------------------------------------------------------------
$0.99 344 $ 0.99 0.4 344 $ 0.99
$1.45 - 1.79 2,081 1.54 3.6 1,118 1.47
$1.79 - 2.00 15 1.93 4.7 5 1.93
----------------------------------------------------------------------------
Total 2,440 $ 1.47 3.2 1,467 $ 1.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(d) Stock-based compensation:

For the nine months ended September 30, 2007, Delphi recorded non-cash compensation expense of $0.7 million. The Company capitalized $0.8 million (September 30, 2006 - $0.6 million) of stock-based compensation directly related to exploration and development activities.

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 $0.90 per share. The assumptions used in the Black-Scholes model to determine fair value were as follows:



Period ended September 30 2007 2006
----------------------------------------------------------------------------
Risk free interest rate (%) 5.0 5.0
Expected life (years) 5.0 5.0
Expected volatility (%) 61.0 45.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(e) Contributed surplus:

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

September 30 December 31
2007 2006
----------------------------------------------------------------------------
Balance, beginning of period $ 5,627 $ 2,380
Stock-based compensation costs 1,543 3,392
Reclassification to common shares on
exercise (24) (145)
----------------------------------------------------------------------------
Balance, end of period $ 7,146 $ 5,627
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(f) Earnings/(loss) per share:

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

Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Basic 68,070 60,662 66,461 57,171
Diluted 68,179 61,584 66,711 58,037
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


NOTE 8: FINANCIAL INSTRUMENTS

(a) Fair value of financial instruments:

The Company's exposure under its financial instruments is limited to financial assets and liabilities, all of which are included in these financial statements. The fair values of financial assets and liabilities that are included in the balance sheet approximate their carrying amounts.

(b) Credit risk:

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

(c) Foreign currency exchange risk:

The Company is exposed to foreign currency fluctuations as crude oil and natural gas prices are referenced to U.S. dollar denominated prices.

(d) Interest rate risk:

The Company is exposed to interest rate risk to the extent that bank debt is at a floating rate of interest.

(e) Commodity price risk management:

The Company has a price risk management program whereby the commodity price associated with a portion of its future production is fixed. The Company sells forward a portion of its future production and enters into a combination of fixed price sale contracts with customers and commodity swap agreements with financial counterparties. The forward contracts are subject to market risk from fluctuating commodity prices and exchange rates.

As at September 30, 2007, the Company has fixed the price applicable to future production through the following contracts:



Type of Quantity Canadian Price
Time Period Commodity Contract Contracted (CDN$/unit)
----------------------------------------------------------------------------
April 2007 - $8.75 floor/
October 2007 Natural Gas Physical 3,000 GJ/d $9.55 ceiling
April 2007 - $8.00 floor/
October 2007 Natural Gas Physical 4,000 GJ/d $8.92 ceiling
April 2007 -
October 2007 Natural Gas Physical 2,000 mmbtu/d $8.94 fixed
April 2007 - $6.50 floor/
October 2007 Natural Gas Physical 2,000 GJ/d $8.15 ceiling
April 2007 - $6.50 floor/
October 2007 Natural Gas Financial 2,000 GJ/d $9.00 ceiling
April 2007 -
October 2007 Natural Gas Financial 1,500 GJ/d $7.09 fixed
April 2007 -
October 2007 Natural Gas Financial 1,500 GJ/d $7.10 fixed
November 2007 - $6.50 floor/
December 2007 Natural Gas Financial 2,000 GJ/d $10.45 ceiling
November 2007 - $9.00 floor/
March 2008 Natural Gas Physical 3,000 GJ/d $9.98 ceiling
November 2007 -
March 2008 Natural Gas Physical 2,000 mmbtu/d $11.07 fixed
November 2007 - $7.75 floor/
March 2008 Natural Gas Physical 2,000 GJ/d $9.03 ceiling
November 2007 - $8.00 floor/
March 2008 Natural Gas Physical 2,000 GJ/d $10.02 ceiling
November 2007 -
March 2008 Natural Gas Financial 1,500 GJ/d $8.55 fixed
November 2007 -
March 2008 Natural Gas Physical 1,500 GJ/d $8.55 fixed
April 2008 -
October 2008 Natural Gas Physical 4,000 GJ/d $7.21 fixed
April 2008 -
October 2008 Natural Gas Physical 3,000 GJ/d $7.61 fixed
April 2008 -
March 2009 Natural Gas Physical 2,000 GJ/d $7.30 fixed
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NOTE 9: CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The Company is committed, under contracts of varying lengths, for the utilization of gathering, processing and pipeline capacity on a major natural gas processing and gathering system in North East British Columbia. The future minimum commitments are as follows:



----------------------------------------------------------------------------
2007 $ 1,152
2008 4,429
2009 4,111
2010 4,087
2011 3,661
2012 - 2015 $ 6,938
----------------------------------------------------------------------------


NOTE 10: GOODWILL

The Company reviewed the valuation of goodwill as of March 31, 2007 based upon the latest available information including the market capitalization of the Company as indicated by the Company's share price. Based upon this review, an impairment of goodwill of $12.1 million was recorded as a non-cash charge to earnings in the first quarter of 2007.



NOTE 11: CHANGES IN NON-CASH WORKING CAPITAL ITEMS

For the period ended September 30 2007 2006
----------------------------------------------------------------------------
Change in working capital item:
Accounts receivable $ 3,066 $ 703
Prepaid expenses and deposits 346 121
Accounts payable and accrued liabilities 821 7,852
----------------------------------------------------------------------------
Total change in non-cash working capital $ 4,233 $ 8,676
Relating to:
Operating activities 4,095 5,325
Financing activities - -
Investing activities 138 3,351
----------------------------------------------------------------------------
$ 4,233 $ 8,676
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Contact Information

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