Delphi Energy Corp.
TSX : DEE

Delphi Energy Corp.

March 19, 2008 22:11 ET

Delphi Energy Reports Record Fourth Quarter 2007 Production and Positions for Continued Growth

CALGARY, ALBERTA--(Marketwire - March 19, 2008) - Delphi Energy Corp. ("Delphi" or the "Company") (TSX:DEE) is pleased to announce its financial and operational results for the year ended December 31, 2007.

2007 Highlights

- Achieved record production of 5,868 barrels of oil equivalent per day (boe/d) in the fourth quarter of 2007, an increase of 18 percent over the same period in 2006. Production has increased 36 percent over the past three quarters. Production averaged 5,323 boe/d in 2007.

- Added 4.3 million boe (3.5 million net of revisions) of proved plus probable reserves through drilling, recompletions and optimizations in 2007.

- Achieved finding and development costs on proved plus probable reserve additions, net of revisions and including future development capital, of $13.11 per boe, resulting in a recycle ratio of 2.3. The recycle ratio, determined by dividing the operating netback per boe by the finding and development costs per boe, allows the Company to measure the amount received per barrel of oil equivalent compared to the cost to find it.

- Generated fourth quarter funds from operations (cash flow) of $13.7 million ($0.20 per share), a 16 percent increase over the $11.8 million in the comparative quarter of 2006.

- Earned $1.7 million in the fourth quarter compared to $0.3 million in the comparable period of 2006.

- Reduced net debt 15 percent to $100.7 million at December 31, 2007 from $118.2 million at the end of 2006, resulting in a net debt to annualized fourth quarter funds from operations ratio of 1.8 times compared with 2.5 times at the end of the prior year. This is in the mid-range of Delphi's peer group.

- Achieved hedging gains of $10.8 million through the Company's risk management program, increasing the Company's average realized natural gas price by $1.10 per thousand cubic feet, 17 percent higher than the benchmark AECO price in 2007.



Operational Highlights

Three Months Ended Twelve Months Ended
December 31 December 31
% %
Production 2007 2006 Change 2007 2006 Change
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Natural gas (mcf/d) 30,610 24,919 23 26,886 25,706 5
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Crude oil (bbls/d) 346 388 (11) 429 476 (10)
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Natural gas liquids (bbls/d) 420 441 (5) 413 468 (12)
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Total (boe/d) 5,868 4,982 18 5,323 5,228 2
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Financial Highlights ($ thousands except per unit amounts)

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
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Petroleum and natural gas
sales 26,632 22,928 16 97,933 94,189 4
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Per boe 49.33 50.02 (1) 50.41 49.36 2
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Funds from operations 13,747 11,817 16 48,481 49,551 (2)
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Per boe 25.46 25.78 (1) 24.97 25.97 (4)
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Per share - Basic 0.20 0.19 5 0.72 0.85 (15)
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Per share - Diluted 0.20 0.19 5 0.72 0.84 (14)
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Net earnings 1,732 290 497 (10,472) 6,903 -
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Per boe 3.20 0.63 408 (5.38) 3.62 -
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Per share - Basic 0.03 - - (0.16) 0.12 -
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Per share - Diluted 0.03 - - (0.16) 0.12 -
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Capital expenditures
before dispositions 16,991 12,124 40 62,795 165,352 (62)
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Dispositions - (17,867) - (15,502) (34,918) (56)
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Net capital expenditures 16,991 (5,743) - 47,293 130,434 (64)
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Debt plus working capital
deficit 100,658 118,178 (15)
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Total assets 311,735 326,668 (5)
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Shares outstanding
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Basic 68,070 60,663 12
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Diluted 73,550 64,892 13
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MESSAGE TO SHAREHOLDERS

Delphi enjoyed significant success in 2007, in an environment of weak and volatile natural gas prices. The Company achieved its goals of delivering measurable growth, increasing financial flexibility and ensuring the Company remains well positioned for sustainable organic growth.

The Company executed its 2007 capital program as planned. The development program was refocused on Delphi's large inventory of robust conventional growth opportunities. The Company chose to defer expenditures on its the Bigfoot, British Columbia resource play where profitability is much more sensitive to natural gas prices and development costs. In September 2007, Delphi swapped Bigfoot for conventional assets in the Hythe area in Alberta. The Company successfully deployed exploration capital in its new areas at Noel, British Columbia, and Red Rock, Alberta. Capital was also allocated to the acquisition of an additional 10.5 percent working interest in the Company's prolific Tower Creek Leduc well, currently producing 23 million cubic feet per day of sour gas (approximately 800 boe/d net).

Delphi maintains a competitive advantage within its core areas as operator, controlling more than 80 percent of its production, field gathering and processing infrastructure. During 2007, the Company operated more than 95 percent of its capital program. Synergies exist between all of the Company's core areas and operational and technical expertise. The Company's producing assets can be characterized as natural gas focused with medium to long-life deep basin production profiles and a low cost structure, which results in superior economic netbacks and recycle ratios.

The Company drilled 14 (8.1 net) wells in 2007 with an 80 percent success rate. This resulted in record production volumes during the fourth quarter of 2007 and proved and probable reserve additions, net of revisions, in 2007 of 3.5 million barrels of oil equivalent, replacing production by 178 percent. The 2007 net capital expenditures of $47.3 million were less than cash flow of $48.5 million.

Delphi averaged 5,868 barrels of oil equivalent per day during the fourth quarter, up 18 percent from the comparative quarter in 2006, and 5,323 boe/d for 2007, up two percent over 2006.

Finding and development costs on proved plus probable reserve additions inclusive of future development costs and revisions were $13.11 per boe, generating a recycle ratio of 2.3. Excluding prior period revisions, finding and development costs in 2007 on proved plus probable reserve additions inclusive of future development costs were $10.63 per boe. All-in finding, development and acquisition costs on the 2007 net capital program were $21.49 per boe. The capital efficiency of the 2007 development and exploration program was very strong as a result of the shift in capital spending back to the Company's operated conventional assets with more robust economics and smaller infrastructure capital requirements.

The Company also strengthened its position to deliver long-term sustainable growth through the strategic swap of its non-operated interest in the unconventional natural gas resource play at Bigfoot for an operated high working interest position at Hythe. The Hythe assets are characterized as multi-zone, conventional, deep basin natural gas assets with significant future development and exploration potential. These are similar to Bigstone assets in North West Alberta that have been successfully developed over the past three years at less than $16.00 per boe, consistently generating a recycle ratio greater than 2.0 times. Production at Bigstone has tripled since acquiring the asset in 2005 with total capital of only 90 percent of the cash flow generated over that period.

The Hythe/Bigfoot transaction, although neutral on a production basis, was a net disposition of reserves by the Company for proceeds of $15.1 million. Therefore, offsetting the proved plus probable reserves additions from the 2007 capital program, was a net disposition of 1.6 mmboe resulting from the acquisition, swap and disposition activity during 2007.

Proved plus probable reserves at December 31, 2007 were 17.3 mmboe, equal to the comparative period in 2006, as reserve additions were partially offset by dispositions.

Canadian natural gas prices averaged $6.44 per mcf at AECO during 2007, down only slightly from $6.61 per mcf in 2006, but down 21 percent from $8.81 per mcf during 2005. Delphi continued to benefit from its risk management program during 2007, realizing $8.05 per mcf from its natural gas sales, a 25 percent premium to the average AECO natural gas price in 2007. The Company's operating netback during 2007 averaged $30.76 per boe and over the past three years has averaged $30.50 per boe with a variance year-to-year of no more than $0.25 per boe. Delphi's risk management program continues to be an integral part of the Company's strategy, designed to ensure cash flow remains predictable and available to execute the planned capital programs, mitigating uncertain and volatile future natural gas prices.

Operational Review

Delphi averaged 5,323 boe/d in 2007, weighted 92 percent to natural gas and natural gas liquids. During the year, the Company drilled 14 wells (8.1 net), with a success rate of 80 percent. The Company's drilling program was focused in Bigstone, the Company's largest asset. Bigstone generated approximately 2,800 boe/d net in 2007 compared with 2,524 boe/d in 2006 and 1,000 boe/d in 2005 when Delphi acquired the property. The multi-zone nature of the property has been a major factor in achieving a 98 percent success rate on 41 wells (31 net) drilled in the area since Delphi acquired the property through to the end of 2007.

The majority of the prospects on the Bigstone lands have the potential to encounter up to seven productive zones, resulting in higher productivity multiple completions in each new well drilled. The Bigstone property offers significant development upside for natural gas through step-out drilling in Cretaceous aged formations at depths of up to 2,800 metres, including the Dunvegan, Viking and Gething formations. Additional development opportunities for oil exist in the Cardium interval at approximately 1,800 metres. Delphi participated in six wells (2.8 net) in Bigstone in 2007, resulting in four gas wells (2.3 net) and two oil wells (0.5 net). Also contributing to a large development drilling inventory is the recently approved downspacing provisions, which allows the Company to drill multiple wells per section. Delphi has identified approximately 40 locations in the area, providing an inventory of drilling prospects for the next three to four years.

Delphi's recently acquired land base in the Hythe area is three times the size of the Company's Bigstone land base, providing a dominant footprint for expansive growth in the Peace River Arch. Geologically, Hythe is similar to Bigstone and in the Hythe area there are up to 12 potentially productive zones.

At Hythe, Delphi has focused its initial activities on well and gathering system optimization, workovers and recompletions, resulting in cost-efficient production increases. When Delphi acquired the Hythe assets they were producing approximately 400 boe/d of natural gas and by year end, Delphi had increased production to 650 boe/d. The Company anticipates additional production gains as ongoing optimization projects are completed. Delphi participated in one successful well (0.5 net) at Hythe in the fourth quarter of 2007 and will ramp up activity significantly in 2008.

At Noel, the Company drilled and completed two 2,400 metre wells in the third quarter of 2007 targeting multi-zone sweet gas and light oil targets in the Falher, Cadotte, Paddy, Dunvegan and Cardium formations. The first well (0.8 net) resulted in four potentially productive intervals. Delphi restricted completion operations on the well to two intervals due to the high deliverability encountered, with the two intervals testing at a combined initial rate of 5,800 mcf/d. The remaining two intervals are expected to be completed at a later date. The second well (0.6 net) was completed in three intervals with a combined initial test rate of 3,600 mcf/d. Production from the two wells commenced in mid-November with December production averaging 375 boe/d net.

Delphi's 2006 Leduc natural gas discovery at Tower Creek 02-21-55-27W5 was equipped, tied-in and commenced production in late June 2007. The well continues to produce at gross raw rates of 23 mmcf/d (800 boe/d net) and through the end of 2007 had cumulative production of approximately 3.3 billion cubic feet of natural gas. During July 2007, Delphi purchased an additional 10.5 percent working interest in the well, well-site facilities and nearby lands for $10.5 million, increasing Delphi's working interest to 30.7 percent.

Reserves Summary

GLJ Petroleum Consultants Ltd. ("GLJ"), the Company's independent petroleum engineering firm, has evaluated Delphi's crude oil, natural gas and natural gas liquids reserves as at December 31, 2007 and prepared a reserves report in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities." Following is summary information detailed in the GLJ reserves report at December 31, 2007 as compared to December 31, 2006.




December 31, 2007 December 31, 2006
Oil &
Gas NGLs Total % of Total
Reserves(1) (mcf) (mbbls) (mboe)(2) Proved (mboe)(2) % Change
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Proved
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Producing 47,845 1,079 9,053 80 7,861 17
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Non-producing 7,711 115 1,400 12 2,266 (38)
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Undeveloped 4,452 152 894 8 1,262 (29)
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Total proved 60,008 1,346 11,347 100 11,389 -
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Probable 31,100 730 5,913 5,922 -
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Total proved plus
probable 91,108 2,076 17,260 17,311 -
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Notes:
(1) Delphi's reserves represent the operated and non-operated working
interest share of reserves before deduction of royalties and include
any royalty interests of the Company.

(2) Oil equivalent amounts have been calculated using a conversion rate
of six thousand cubic feet of natural gas to one barrel of oil (6:1).


Net Present Value of Reserves

The estimated future net revenues associated with Delphi's reserves at December 31, 2007 based on the GLJ January 1, 2008 price forecast are summarized in the following table.



Future net revenues before income taxes
discounted at a rate of:
($ thousands)(1) 0% 5% 8% 10%
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Proved
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Producing 227,600 187,373 170,084 160,464
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Non-producing 34,108 26,962 23,797 22,018
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Undeveloped 15,902 11,834 10,074 9,099
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Total proved 277,610 226,169 203,955 191,581
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Probable 149,890 101,509 83,551 74,265
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Total proved plus probable 427,500 327,678 287,506 265,846
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Note:
(1) The estimated future net revenues are before the deduction of estimated
future site restoration costs but are reduced for estimated future
abandonment costs for reserve wells and estimated capital for future
development associated with the reserves.


Reserve Life Index

The reserve life index of Delphi has been calculated by using average 2007 production of 5,323 boe/d.



Proved plus probable reserves at December 31, 2007 (mboe) 17,260
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2007 production (mboe) 1,943
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Reserve life index (years) 8.9
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Reserves Reconciliation

The following reconciliation of Delphi's reserves compares changes in the Company's reserves as at December 31, 2006 to the reserves as at December 31, 2007, each evaluated in accordance with National Instrument 51-101 definitions.




Proved
Proved Probable plus probable
(mboe) (mboe) (mboe)
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Reserves at December 31, 2006 11,389 5,922 17,311
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Exploration and development additions 2,460 1,802 4,262
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Revisions (180) (628) (808)
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Acquisitions 1,816 726 2,542
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Dispositions (2,195) (1,909) (4,104)
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Production (1,943) - (1,943)
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Reserves at December 31, 2007 11,347 5,913 17,260
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Finding and Development Costs

Finding and development costs in 2007 and over the past three years were as follows:



2007 2005-2007
Proved plus Proved plus
($ thousands except per boe data) probable probable
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Exploration and development expenditures 51,924 277,283
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Acquisitions and dispositions - net (4,631) 7,050
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Change in future development costs (FDC) (6,641) 17,253
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Finding and development costs ($/boe)
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Exploration and development, without FDC 15.03 22.22
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Exploration and development, with FDC 13.11 23.60
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Exploration, development, acquisitions and
dispositions, without FDC 25.00 22.40
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Exploration, development, acquisitions and
dispositions, with FDC 21.49 23.76
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Net Asset Value

The net asset value of the Company at December 31, 2007 has been calculated as follows:



($ thousands except per share data) December 31, 2007
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Value of proved plus probable reserves discounted at 8% 287,506
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Undeveloped land(1) 10,379
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Mark-to-market value of hedging contracts 4,074
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In-the-money option proceeds(2) 3,759
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Total asset value 305,718
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Bank debt plus working capital deficiency (100,658)
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Net asset value 205,060
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Basic shares outstanding and in-the-money options 70,550,491
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Net asset value per share 2.91
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Notes:
(1) Undeveloped land is based on the estimated land value in Seaton-Jordan
& Associates Ltd. land valuation report.
(2) In-the-money option proceeds are based on the closing December 31,
2007 share price of $1.83.
(3) The Company estimates it has approximately $182 million of tax
deductions available to offset future taxable income.


Financial Review

Despite lower natural gas prices in 2007 compared with 2006, Delphi's funds from operations for 2007 remained steady at $48.5 million ($0.72 per basic share) compared with $49.6 million ($0.85 per basic share) in 2006. This result was achieved in part due to the Company's effective risk management program, which resulted in hedging gains of $10.8 million, increasing the Company's average realized natural gas price by $1.10 per mcf, 17 percent higher than the benchmark AECO price in 2007. Although operating costs averaged $8.99 per boe for 2007, fourth quarter operating costs of $8.29 per boe are expected to be more reflective of the cost structure going forward. Cash netbacks were down slightly at $24.97 per boe compared to $25.97 per boe in the previous year. In the fourth quarter, net earnings were $1.7 million compared to $0.3 million for the comparative quarter. The Company's net loss of $10.5 million for 2007 was primarily as a result of a $12.1 million ($8.2 million after tax) impairment of goodwill in the first quarter of 2007.

In 2007, Delphi incurred total capital expenditures of $62.8 million, with 61 percent of the capital being directed at increasing production and reserves through drilling operations and optimization projects in core areas. The capital program was financed through funds from operations and proceeds from the disposition of Bigfoot.

With the addition of recent contracts, Delphi's risk management positions for 2008 and 2009 are as follows:



January - April - November - April -
March October March October
2008 2008 2008/2009 2009
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Production hedged (mmcf/d) 11.5 15.3 13.2 1.9
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Percentage of production(i) 36% 48% 41% 6%
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Price floor (Cdn $/mcf) $9.12 $7.97 $8.03 $7.83
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Price ceiling (Cdn $/mcf) $9.95 $8.09 $8.42 $7.83
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(i) based on 32 mmcf/d


OUTLOOK

Delphi expects to spend approximately $50.0 million in 2008 - approximately 85 to 90 percent of anticipated 2008 cash flow - drilling 20 to 25 wells. The majority of the capital will be directed towards drilling and completion activities in the Bigstone, Hythe, and Noel core areas. For 2008, production is forecast to average between 6,000 boe/d to 6,200 boe/d, a 15 percent increase over 2007. First quarter production is expected to average 6,000 boe/d.

The Company has had an active winter capital program, spending approximately $24.0 million drilling 11 wells (8.2 net) with 100 percent success, as well as completing several workover, recompletion, pipeline and facility projects. Drilling is now finished with several completion and pipeline operations still ongoing. Four of the new wells are now on production and estimated on-stream dates for the remaining new wells range from mid-second quarter to mid-third quarter.

Delphi has a significant inventory of defined and repeatable conventional prospects concentrated within its core areas of operation. The multi-zone nature of Delphi's core areas and recently approved downspacing provisions contribute to the Company's large development drilling inventory. Delphi continues to pursue emerging technologies to enhance recoveries of existing reserves as well as untapped natural gas resources within the Company's current land holdings.

The Company currently trades at discount of about a 30 percent to its net asset value per share estimated to be $2.91 (discounted eight percent before tax), based on its December 31, 2007 proved plus probable reserves, as evaluated by GLJ Petroleum Consultants, which reflects only a portion of the value and growth potential of the Company.

Delphi is optimistic as to the long-term market fundamentals of natural gas. Natural gas prices have strengthened recently with prices reaching levels not seen in two years. The Company has taken advantage of this recent move in natural gas prices by increasing its hedged position to approximately 44 percent of current production for 2008 at an average price of $8.21 per mcf.

The talented and enthusiastic Delphi team has expanded by 25 percent during 2007 and is well positioned to continue to execute its proven growth strategies through 2008 and beyond.

CONFERENCE CALL

A conference call is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Thursday, March 20, 2008. The conference call number is 1-877-323-2010 or 416-695-6617. 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.

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

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

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

Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation.

Additional information on these and other factors that could affect the Company's operations or financial results are included in reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). The forward-looking statements and information contained in this press release are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

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

Management Discussion and Analysis

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

The management discussion and analysis has been prepared by management and reviewed and approved by the Board of Directors of Delphi Energy Corp. ("Delphi" or "the Company"). The discussion and analysis is a review of the financial results of the Company based upon accounting principles generally accepted in Canada. Its focus is primarily a comparison of the financial performance for the three and twelve months ended December 31, 2007 and 2006 and should be read in conjunction with the audited financial statements and accompanying notes for the year ended December 31, 2007and 2006. The discussion and analysis has been prepared as of March 18, 2008.

Operational and Financial Highlights

Delphi Energy Corp. achieved strong production growth in 2007 with average daily production increasing on a quarter over quarter basis throughout the year from an average of 4,322 barrels of oil equivalent per day (boe/d) in the first quarter to 5,868 boe/d in the fourth quarter, an increase of 36 percent over the year. Fourth quarter sales volumes represent record quarterly production for the Company. Average annual production volumes increased to 5,323 boe/d, an increase of two percent compared to 2006. Natural gas production comprised 84 percent of the Company's average production.

Several accomplishments were achieved in 2007 through the Company's capital program including:

- the continued growth in production of its core area of Bigstone, Alberta to over 3,000 boe/d at the end of 2007 from 2,300 boe/d in December, 2006;

- the swap of the Company's 50 percent working interest, Jean Marie resource play at Bigfoot, British Columbia in exchange for 84 sections of primarily operated, multi-zone, conventional natural gas on average 74 percent working interest lands with infrastructure and production at Hythe, Alberta and cash of $15.1 million;

- production growth at Hythe, Alberta to 650 boe/d from 400 boe/d at the time of acquisition in September, 2007;

- the production start-up and the acquisition of an additional 10.5 percent working interest in the long-life natural gas production at Tower Creek, Alberta; and

- the expansion of opportunities in the deep gas basin with the addition of drill ready farm-in opportunities at Noel, British Columbia and Red Rock, Alberta.

Funds from operations in 2007 were $48.5 million or $0.72 per basic share, compared to $49.6 million or $0.85 per basic share in 2006, maintaining strong cash netbacks in a challenging natural gas price environment. Delphi's risk management program continued to significantly contribute to funds from operations providing the Company with the ability to execute on its capital program. Gains on physical and financial hedges were $10.8 million representing 22 percent of funds from operations and $5.54 per barrel of oil equivalent (boe) on a cash netback basis.

The Company's financial position strengthened significantly in 2007 providing greater financial flexibility going into 2008 to execute its capital program and participate in farm-in, joint venture or acquisition opportunities. At December 31, 2007 the Company had net debt of $100.7 million down from $118.2 million at December 31, 2006. On an annualized fourth quarter funds from operations basis, Delphi improved its debt to cash flow ratio to 1.8 times from 2.5 times at the end of 2006.



Business Environment

Benchmark Prices

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
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Natural gas
NYMEX (US $/mmbtu) 6.97 6.65 5 6.97 6.75 3
AECO (CDN $/mcf) 6.15 6.90 (11) 6.44 6.61 (3)
Crude oil
West Texas Intermediate (US
$/bbl) 90.68 59.95 51 72.31 66.22 9
Edmonton Light (CDN $/bbl) 86.42 65.45 32 76.35 72.77 5
Foreign exchange rate
Canadian to US dollar 0.98 1.14 (14) 1.08 1.14 (5)
US to Canadian dollar 1.02 0.88 16 0.93 0.88 6
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Natural Gas

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

In 2007, it was again a challenging year for natural gas prices. While United States natural gas storage levels were reduced significantly from strong late-winter withdrawals, LNG imports to the U.S. were significantly higher than average throughout the spring and summer, due to strong U.S. pricing relative to global market prices, more than offsetting lower Canadian supply levels. By early August natural gas storage levels surpassed the record levels of 2006 resulting in a sharp decrease in the price of natural gas. Since reaching the high in August, the injections from LNG imports have been below average levels. Canadian natural gas prices were also negatively affected by the surge in the Canadian dollar relative to the United States dollar. During the year, the AECO average daily spot price ranged from a high of $8.27 per mcf to a low of $4.33 per mcf. For internal forecasting purposes, looking toward 2008, Delphi anticipates AECO natural gas prices will average approximately $7.00 per thousand cubic feet (mcf).

Crude Oil

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

In contrast to natural gas prices, 2007 was another excellent year for crude oil prices which continued to increase, reaching over U.S. $110.00 per barrel early in 2008, on continued strong global demand, production disruptions, never ending geopolitical unrest in major producing regions and the recent devaluation of the U.S. dollar. The outlook for oil remains bullish despite concerns of a U.S. recession resulting from the sub-prime mortgage and related asset backed commercial paper fallout. For Canadian producers the significant gain in oil prices throughout the year was partially offset by a strong increase in the Canadian dollar which moved to parity for the first time since the mid - 70's. The Canadian dollar continues to remain around parity with the U.S. dollar. For internal forecasting purposes, Delphi anticipates WTI to average between U.S. $80.00 to $90.00 per barrel and the Canadian dollar to remain at, or near, par with the U.S. dollar throughout 2008.

Prices for heavy oil and other lesser quality crude oils trade at a discount or differential to light crude oil due to the additional costs in the refining process. The average differential in 2007 was $22.83 per barrel compared to $21.23 per barrel in 2006. The differential varied from a low of $13.68 per barrel to a high of $41.01 per barrel. The increase in the average differential and stronger Canadian dollar was more than offset by higher light oil prices resulting in Bow River crude prices increasing to $53.52 per barrel from $51.54 per barrel in 2006.

Industry Cost of Services

Early in 2007, the oilfield services sector was under pressure with strong demand for equipment through the winter drilling season while facing labour shortages to operate the equipment, a continuation of the rapid pace and hyper-inflation of 2006, leaving no time to maintain or service the equipment. Commodity prices, both crude oil and natural gas, remained robust and increasing through the early part of the year. Oil and gas producers incurred high day rates for drilling, completion and pipeline operations often working with crews that had less experience than was desirable. While crude oil prices continued to increase throughout the remainder of the year, natural gas prices decreased to an average low in the third quarter not seen since 2002. In addition, the Government of Alberta proposed changes to its royalty regime in September 2007 to become effective January 1, 2009.

The proposed royalty changes and low natural gas prices caused the capital markets to pull back from investing in most junior oil and natural gas producers. Oil and natural gas producers reduced capital programs due to lower funds from operations and were faced with the inability to raise equity in the capital markets. Oilfield service companies followed by reducing their rates to keep as many crews busy as possible. Through the latter half of the year well stimulations were being completed for 40 to 50 percent less than peak rates and average drilling day rates decreased 15 to 20 percent. For oil and gas producers lower costs have continued through the 2007/2008 winter drilling season with a significant improvement in the skill level of the oilfield crews and fewer equipment breakdowns due to maintenance of the equipment through the summer and fall of 2007.

Financial Strategy

The Company maintains an active risk management program as an integral part of its overall financial strategy to mitigate volatility in funds from operations resulting from fluctuating commodity prices. The strategy takes advantage of the upward swings in natural gas prices as a result of the changes in demand/supply fundamentals and/or the movement of significant financial assets invested in the natural gas market as a pure commodity play. Delphi's risk management program continues to consist of both fixed price contracts and costless collars, which provide downside protection and the opportunity to share in the upside if market prices increase above the floor price. Currently, Delphi has hedged approximately 44 percent of its before-royalty natural gas production at a predominantly AECO based average floor price of $8.21 per mcf for 2008. Delphi has a strategy of hedging between 40 to 50 percent of its natural gas production as long as demand/supply fundamentals indicate volatile markets in the future. As the Company's leverage improves and/or demand/supply fundamentals move toward equilibrium or reduced supply, Delphi will manage its hedging program accordingly to take advantage of exposure to higher natural gas commodity prices.

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

Maintaining or improving strong operating netbacks per boe through the risk management program and the control of costs associated with production operations, allows the Company to pursue its planned capital program with greater confidence that financial flexibility will be maintained while incurring capital expenditures to grow production volumes. With the expectation of a pricing environment very similar to the past two years, the Company expects to maintain an operating netback per boe in the $29.00 - $31.00 range as it has in the past three years despite the swings in AECO spot pricing. The risk management program has been and will continue to be an integral part of ensuring strong netbacks.

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

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

Selected Information

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




Dec. 31 Sept.30 Jun. 30 Mar. 31
2007 2007 2007 2007
----------------------------------------------------------------------------
Production
Natural gas (mcf/d) 30,610 28,196 26,967 21,658
Oil (bbl/d) 346 579 423 366
Natural gas liquids (bbl/d) 420 422 461 346
----------------------------------------------------------------------------
Barrels of oil equivalent (boe/d) 5,868 5,700 5,379 4,322
Financial
($ thousands except per unit
amounts)
Petroleum and natural gas revenue 26,632 24,548 24,779 21,974
Funds from operations 13,747 12,600 11,469 10,665
Per share - basic 0.20 0.19 0.17 0.17
Per share - diluted 0.20 0.18 0.17 0.17
Net earnings (loss) 1,732 (1,348) 797 (11,653)
Per share - Basic 0.03 (0.02) 0.01 (0.18)
Per share - Diluted 0.03 (0.02) 0.01 (0.18)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Dec. 31 Sept. 30 Jun. 30 Mar. 31
2006 2006 2006 2006
----------------------------------------------------------------------------
Production
Natural gas (mcf/d) 24,919 25,403 28,797 23,695
Oil (bbl/d) 388 444 531 544
Natural gas liquids (bbl/d) 441 412 503 518
----------------------------------------------------------------------------
Barrels of oil equivalent (boe/d) 4,982 5,090 5,834 5,011
Financial
($ thousands except per unit
amounts)
Petroleum and natural gas revenue 22,928 21,587 25,865 23,809
Funds from operations 11,817 10,902 14,452 12,380
Per share - basic 0.19 0.18 0.26 0.22
Per share - diluted 0.19 0.18 0.26 0.22
Net earnings (loss) 290 658 4,768 1,187
Per share - Basic - 0.01 0.09 0.02
Per share - Diluted - 0.01 0.09 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production for the last eight consecutive quarters reflects the following events: The increase in production volumes for the second quarter of 2006 were from Bigfoot in North East British Columbia as wells were placed on stream followed by a reduced capital program leading to production declines and the disposition of several minor, non-operated properties in the latter half of 2006. In 2007 success at Bigstone, Alberta throughout the year and Noel, British Columbia in the third quarter complemented the mid-year start up of production at Tower Creek, Alberta resulting in consistent quarter over quarter production growth. Revenue and funds from operations reflected the cycle of natural gas prices and production volumes. Natural gas prices over the past two years have reflected the cyclical nature of demand. Higher prices in the winter months reflecting demand for heating weaken through the summer months as production is placed in storage for the upcoming heating season demand. In the first quarter of 2007, net earnings were significantly reduced by the impairment of goodwill in the amount of $12.1 million.



2007 2006 2005
----------------------------------------------------------------------------
Revenue 97,933 94,189 80,880
Net earnings/(loss) (10,472) 6,903 6,677
Total assets 311,735 326,668 244,666
Bank debt plus working capital 100,658 118,178 61,020
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Drilling Results

Three Months Ended Twelve Months Ended
December 31 December 31
Gross Net Gross Net
----------------------------------------------------------------------------
Natural gas wells 1.0 1.0 9.0 6.0
Oil wells - - 2.0 0.5
Dry holes 2.0 1.2 3.0 1.6
----------------------------------------------------------------------------
Total wells 3.0 2.2 14.0 8.1
Success rate (%) 33 45 79 80
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company had another successful year with the drill bit resulting in a drilling success rate of 80 percent. The Company has in excess of one hundred drilling locations identified within its core areas of operations.



Capital Invested

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Land (26) 535 - 204 3,578 (94)
Seismic (30) - - 407 10,070 (96)
Drilling and completions 13,188 3,544 272 38,417 86,473 (56)
Equipping and facilities 3,693 7,646 (52) 10,635 62,137 (83)
Property acquisition - - - 10,871 1,188 815
Capitalized expenses 578 368 57 2,261 1,825 24
Other (412) 31 - - 81 -
----------------------------------------------------------------------------
Capital invested 16,991 12,124 40 62,795 165,352 (62)
Proceeds on dispositions - (17,867) - (15,502) (34,918) (56)
----------------------------------------------------------------------------
Total capital invested 16,991 (5,743) - 47,293 130,434 (64)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Delphi had a very successful capital program in a challenging environment. With a net capital program less than funds from operations, Delphi achieved significant growth in production, strong capital efficiency metrics and an improvement in its financial position.

In 2007, Delphi's net capital expenditure program was $47.3 million, a significant reduction from the capital incurred compared to the prior year due to the $91.4 million capital requirement in the Bigfoot area of North East British Columbia in 2006. The majority (61 percent) of 2007 capital expenditures before dispositions were directed at increasing production and reserves through drilling operations and optimization projects in core areas. The Company also acquired an additional 10.5 percent working interest in the Tower Creek 2-21 Leduc exploration discovery and completed the construction and commissioning of the associated pipeline and facilities, with production commencing mid year. During the year, Delphi undertook the strategic swap of its 50 percent working interest, resource play at Bigfoot, British Columbia in exchange for 84 sections of operated, multi-zone, conventional natural gas at Hythe, Alberta and cash of $15.1 million. Highlights of the swap transaction, at the time of acquisition, were as follows:



Hythe, Alberta Bigfoot, British Columbia
----------------------------------------------------------------------------
Land 39,000 net acres 35,229 net acres
Processing plant 10.9 percent ownership in 70 No plant interest
mmcf/d plant
Gathering system 120 kilometers of gas 52 kilometers of gas
gathering system gathering system
Production 400 boe/d 400 boe/d
Formations Multizone Cretaceous Jean Marie
Access Year round Primarily winter
Operator Delphi Energy Corp. Joint Venture Partner
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Natural gas (mcf/d) 30,610 24,919 23 26,886 25,706 5
Crude oil (bbl/d) 346 388 (11) 429 476 (10)
Natural gas liquids (bbl/d) 420 441 (5) 413 468 (12)
----------------------------------------------------------------------------
Total (boe/d) 5,868 4,982 18 5,323 5,228 2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production for the twelve months ended December 31, 2007 averaged 5,323 boe/d, an increase of two percent over the comparative period primarily due to the start up of production at Tower Creek and the successful drilling program at Bigstone, Alberta offsetting lower than average annual production in the first quarter of the year. With the disposition of 250 boe/d and minimal capital directed at drilling in late 2006, production for the first quarter of 2007 averaged 4,322 boe/d. From the first quarter average Delphi managed to grow quarter over quarter production primarily through the drill bit exiting the year at 5,900 boe/d. Fourth quarter production average was a 36 percent increase over the first quarter average, proving the strength of the Company's core assets and ability to grow organically. The success was achieved in adding production at less than $25,000 per flowing boe in its core areas. Delphi believes it can continue to add production at these attractive metrics. The Company's production portfolio for the year was weighted 84 percent to natural gas, eight percent to crude oil and eight percent to natural gas liquids. Production for the three months ended December 31, 2007 increased 18 percent over the prior year's comparative period. The significant growth is attributed to drilling and optimization success in the core areas of Bigstone and Hythe, Alberta and Noel, British Columbia and the start up of production at Tower Creek.

Natural gas volumes increased to 30.6 mmcf/d in the fourth quarter of 2007, representing a 23 percent increase over the comparative period in 2006. Annual production of natural gas in 2007 was 5 percent greater than the prior year.

Crude oil production was 11 percent and 10 percent lower respectively, for the three and twelve months ended December 31, 2007, as compared to the comparative periods in 2006 due to natural declines and minimal capital investment towards adding new production.

Natural gas liquids were five percent and 12 percent lower respectively, for the three and twelve months ended December 31, 2007, as compared to the comparative periods in 2006 due to leaner natural gas streams on targeted zones in Bigstone.




Realized Sales Prices

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
AECO ($/mcf) 6.15 6.90 (11) 6.44 6.61 (3)
Heating content and marketing
($/mcf) 0.40 0.39 3 0.51 0.32 59
Gain on physical contracts
($/mcf) 0.80 1.12 (29) 0.95 1.12 (15)
Gain/(loss) on financial
contracts ($/mcf) 0.26 - - 0.15 (0.02) -
----------------------------------------------------------------------------
Realized gas price ($/mcf) 7.61 8.41 (10) 8.05 8.03 -
Realized oil price ($/bbl) 71.10 47.09 51 61.28 53.19 15
Realized natural gas liquids
price ($/bbl) 76.03 48.55 57 62.28 56.25 11
----------------------------------------------------------------------------
Total realized sales price
($/boe) 49.33 50.02 (1) 50.41 49.36 2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and twelve months ended December 31, 2007, Delphi continued to benefit 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. For the quarter, the risk management program increased the average price received by approximately $1.06 per mcf with physical contracts adding $0.80 per mcf and financial contracts adding $0.26 per mcf. For the year ended December 31, 2007, the average realized gas price was virtually unchanged from the comparable year. The inelasticity of the average price received is directly related to Delphi's effective risk management program. In addition, the Company continues to receive higher than the AECO spot price on natural gas sales due to the high heating content of its natural gas production and the sale of approximately 3,500 million british thermal units (mmbtu) per day on the Alliance pipeline which is priced at the Chicago Monthly Index. The risk management program increased the average price received for the twelve months ended December 31, 2007 by $1.10 per mcf.

The following table outlines the premium Delphi realized on natural gas compared to the average quarterly AECO price due to the effective risk management program, quality of production and gas marketing arrangements.



Dec. 31 Sept.30 Jun. 30 Mar. 31
2007 2007 2007 2007
----------------------------------------------------------------------------
Natural Gas Price ($/mcf)
Delphi realized 7.61 7.20 8.20 9.61
AECO average 6.15 5.14 7.06 7.40
----------------------------------------------------------------------------
Premium to AECO 24% 40% 16% 30%
----------------------------------------------------------------------------


Dec. 31 Sept. 30 Jun. 30 Mar. 31
2006 2006 2006 2006
----------------------------------------------------------------------------
Natural Gas Price ($/mcf)
Delphi realized 8.41 7.20 7.59 8.54
AECO average 6.90 6.04 6.00 7.51
----------------------------------------------------------------------------
Premium to AECO 22% 19% 27% 14%
----------------------------------------------------------------------------


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

Risk Management Activities

Delphi enters into both financial and physical commodity contracts as part of its risk management program to manage commodity price fluctuations to ensure sufficient cash is generated to fund its capital program particularly when commodity prices are extremely volatile. Delphi makes a concerted effort to hedge production volumes at prices greater than the upper limit of the historical three to five year AECO price range of $5.25 to $8.40 per mcf and is quick to react to price aberrations such as those experienced at the end of 2005. Another component of the risk management program is to layer fixed price contracts in over a period of time, as opposed to locking in a significant portion of volumes at any one point in time, to take advantage of unexpected price spikes. For natural gas production, Delphi has hedged approximately 44 percent of its before-royalty natural gas production at a predominately AECO based average floor price of $8.21 per mcf for 2008.

With respect to financial contracts, which are derivative financial instruments, management has elected not to use hedge accounting and consequently records the fair value of its natural gas financial contracts 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 year ended December 31, 2007 of $0.8 million and an unrealized non-cash loss of $0.9 million on financial contracts in the fourth quarter of 2007. 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:

Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
November 2007 Natural
- March 2008 Gas Physical 3,000 GJ/d $9.00 floor/$9.98 ceiling
November 2007 Natural
- March 2008 Gas Physical 2,000 mmbtu/d U.S. $10.28 fixed
November 2007 Natural
- March 2008 Gas Physical 2,000 GJ/d $7.75 floor/$9.03 ceiling
November 2007 Natural
- March 2008 Gas Physical 2,000 GJ/d $8.00 floor/$10.02 ceiling
November 2007 Natural
- March 2008 Gas Financial 1,500 GJ/d $8.55 fixed
November 2007 Natural
- March 2008 Gas Physical 1,500 GJ/d $8.55 fixed
April 2008 - Natural
October 2008 Gas Physical 4,000 GJ/d $7.21 fixed
April 2008 - Natural
October 2008 Gas Physical 3,000 GJ/d $7.61 fixed
April 2008 - Natural
October 2008 Gas Physical 2,000 mmbtu/d U.S. $8.00 fixed
April 2008 - Natural
October 2008 Gas Financial 1,000 GJ/d $8.07 fixed
April 2008 - Natural
October 2008 Gas Financial 1,000 GJ/d $8.07 fixed
April 2008 - Natural
October 2008 Gas Financial 1,000 GJ/d $7.75 floor/$9.55 ceiling
April 2008 - Natural
December 2008 Gas Physical 2,000 GJ/d $7.82 fixed
April 2008 - Natural
March 2009 Gas Physical 2,000 GJ/d $7.30 fixed
November 2008 Natural
- March 2009 Gas Physical 4,000 GJ/d $7.46 fixed
November 2008 Natural
- March 2009 Gas Physical 2,000 GJ/d $7.62 fixed
November 2008 Natural
- March 2009 Gas Physical 2,000 GJ/d $7.00 floor/$8.05 ceiling
November 2008 Natural
- March 2009 Gas Physical 2,000 mmbtu/d U.S. $9.00 fixed
November 2008 Natural
- March 2009 Gas Financial 1,000 GJ/d $8.00 floor/$11.07 ceiling
April 2009 - Natural
October 2009 Gas Physical 1,000 GJ/d $7.08 fixed
April 2009 - Natural
October 2009 Gas Physical 1,000 mmbtu/d U.S. $8.18 fixed
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On January 1, 2007 the Company adopted the new accounting standards regarding the accounting for financial instruments. Under these new standards, 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.



Revenue

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Natural gas 20,696 19,277 7 77,495 75,523 3
Crude oil 2,263 1,681 35 9,596 9,242 4
Natural gas liquids 2,938 1,970 49 9,388 9,609 (2)
Realized gain/(loss) on
financial contracts 735 - - 1,454 (185) -
----------------------------------------------------------------------------
Total 26,632 22,928 16 97,933 94,189 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The increase in revenue for the twelve months ended December 31, 2007, over the comparative period, is attributed to the increase in production volumes and a minimal change in the realized natural gas price. For the fourth quarter, revenue increased 16 percent over the comparative period due to an 18 percent increase in production volumes offset by a 10 percent decrease in the realized natural gas price.



Royalties

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Total 4,092 2,810 46 14,580 13,731 6
Per boe 7.58 6.13 24 7.50 7.20 4
Percent of total revenue 15.4 12.3 25 14.9 14.6 2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company pays royalties to provincial governments (Crown), freeholders, which can be individuals or companies, and other oil and gas operators that own surface or mineral rights. Crown royalty rates are calculated on a sliding scale based on commodity prices and individual well production rates. Royalty rates can change due to price fluctuations or changes in production volumes on a well by well basis subject to a minimum and maximum rate restriction ascribed by the Crown. For the twelve months ended December 31, 2007, royalties as a percentage of revenue increased due to the elimination of the Alberta Royalty Tax Credit (ARTC), a tax rebate from the Alberta government for eligible crown royalties paid in the year subject to a maximum of $0.5 million in 2006. During the quarter, the royalty rate increased 25 percent over the comparable period due to increased volumes from the Bigstone area which has a higher than corporate average royalty rate. For the three and twelve months ended December 31, 2007, Delphi realized approximately $3.1 million and $10.8 million in hedging gains, included in revenue, but on which royalties are not paid. Delphi pays royalties based on the provincial reference price, not the prices received, resulting in Delphi not paying royalties on the hedging gains, consistent with the comparable periods in 2006. Delphi is expecting royalties as a percentage of revenue, before hedging, to be between 18 and 20 percent in 2008.



Operating Expenses

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Total 4,477 3,859 16 17,464 15,826 10
Per boe 8.29 8.42 (2) 8.99 8.29 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Operating expenses on a per boe basis for the twelve months ended December 31, 2007, increased eight percent over the comparative period due to a higher level of workover and maintenance activity in Delphi's core areas. Additionally, in the first half of the year, the Company had operating cost adjustments from prior years related to several non operated properties. As expected, due to the increase in production volumes and a corporate focus on cost reduction, operating costs decreased significantly from the first half of 2007 and are expected to decrease further in 2008.

Operating costs on a per boe basis for the quarter decreased two percent over the comparative period in 2006. This reduction is a result of increased volumes from the Company's core areas of Bigstone and Hythe. Bigstone, which represents 55 percent of average production, has very efficient costs of approximately $5.25 per boe.



Transportation Expenses

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Total 1,387 1,627 (15) 6,148 6,455 (5)
Per boe 2.57 3.55 (28) 3.16 3.38 (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

On a per boe basis, transportation costs for the three and twelve months ended December 31, 2007 decreased 28 and seven percent respectively over the comparative periods. The decrease is attributed to higher production volumes with fixed firm service commitment fees for production and lower transportation costs at Hythe, Alberta than the Bigfoot area. Effective November 1, 2007 Delphi transferred a portion of its excess processing and transmission capacity to third party producers resulting in further reductions in transportation costs. Delphi expects transportation costs for 2008 to be consistent with or slightly less than the fourth quarter of 2007.



General and Administrative

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
General and administrative
costs 2,319 1,339 73 6,957 5,498 27
Overhead recoveries (196) (137) 43 (711) (1,081) (34)
Salary allocations (688) (413) 67 (2,550) (2,045) 25
----------------------------------------------------------------------------
Net 1,435 789 82 3,696 2,372 56
Per boe 2.66 1.72 55 1.90 1.24 53
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On a per boe basis, general and administrative (G&A) costs for the twelve months ended December 31, 2007 increased 53 percent over the comparative period in 2006. The increase is due to decreased overhead recoveries and increased office rent and direct personnel costs. 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 delivering strong growth and believes a strong technical team is paramount to achieve this goal. Delphi expanded its team in 2007 with the addition of a VP Operations, a senior exploitation engineer and two senior geologists. For 2008, Delphi is expecting G&A per boe to decrease slightly as additional production volumes are achieved.



Stock-based Compensation

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Total 552 317 74 1,297 2,491 (48)
Per boe 1.02 0.69 48 0.67 1.31 (49)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 twelve months ended December 31, 2007, decreased 48 percent due to the cancellation of certain stock options in which the Company recognized the unvested portion of the stock-based compensation. In addition, the Company granted 4.5 million stock options to employees, officers, and key consultants under the existing stock option plan. During the three and twelve months ended December 31, 2007, Delphi capitalized $0.6 million and $1.4 million of stock-based compensation associated with exploration and development activities.



Interest

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Total 1,491 2,026 (26) 7,561 6,254 21
Per boe 2.76 4.42 (38) 3.89 3.28 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In 2007, interest costs increased 21 percent due to higher interest rates, Part XII.6 tax associated with the flow-through financing in 2006 and higher average debt levels. The Part XII.6 tax is a monthly finance charge payable to the Canada Revenue Agency until flow-through obligations have been satisfied. For the three months ended December 31, 2007, interest costs were 38 percent lower than the comparative period due to lower average debt levels and lower Part XII.6 tax. Delphi anticipates interest per boe will continue to decrease in 2008 as average debt levels remain constant and additional production is brought on stream.



Depletion, Depreciation and Accretion

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Depletion and depreciation 13,960 11,090 26 48,962 39,727 23
Accretion expense 185 173 7 638 637 -
----------------------------------------------------------------------------
Total 14,145 11,263 26 49,600 40,364 23
Per boe 26.20 24.58 7 25.53 21.15 21
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Depletion, depreciation, and accretion per boe for the three and twelve months ended December 31, 2007 increased seven and 21 percent due to higher cost proved reserve additions. With the recently completed Hythe transaction and success at Bigstone and Noel, Delphi is in an excellent position to add proved reserves at metrics below the Company's current depletion rate. The increase in total depletion and depreciation versus the comparative periods is a result of increased production levels and a higher per boe rate.

Accretion expense of asset retirement obligations relates to the passing of time until the Company estimates it will retire its assets and restore the asset locations to a condition which meets or exceeds environmental standards. Due to the long term nature of certain assets of the Company, this accretion expense is estimated to extend over a term of three to 20 years. The Company uses a credit adjusted risk-free rate of eight percent for the purpose of calculating the fair value of its asset retirement obligations and hence the accretion expense. The accretion expense for the twelve months ended December 31, 2007 remained consistent with the comparative period.

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's assets.



Taxes

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Current 3 - - 3 - -
Future (reduction) (3,608) 295 - (3,279) 786 -
----------------------------------------------------------------------------
Total (3,605) 295 - (3,276) 786 -
Per boe (6.68) 0.64 - (1.69) 0.41 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The provision for income taxes in the financial statements for the three and twelve months ended December 31, 2007, differs from the result that would have been obtained by applying the combined federal and provincial tax rates to the Company's loss, before tax, 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 currently. Delphi does not anticipate it will be cash taxable until 2009 or later based on current commodity prices.



Funds from Operations

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Net earnings 1,732 290 497 (10,472) 6,903 -
Non-cash items:
Depletion, depreciation
and accretion 14,145 11,263 26 49,600 40,364 23
Impairment of goodwill - - - 12,100 - -
Unrealized gain on risk
management activities 926 (348) - (765) (993) (23)
Stock-based compensation
expense 552 317 74 1,297 2,491 (48)
Future income taxes
(reduction) (3,608) 295 - (3,279) 786 -
----------------------------------------------------------------------------
Funds from operations 13,747 11,817 16 48,481 49,551 (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and twelve months ended December 31, 2007 funds from operations were $13.7 million ($0.20 per basic share) and $48.5 million ($0.72 per basic share) compared to $11.8 million ($0.19 per basic share) and $49.6 million ($0.85 per basic share) in 2006.

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

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



Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Funds from operations:
Non-GAAP 13,747 11,817 16 48,481 49,551 (2)
Settlement of asset
retirement obligations (93) (98) (5) (550) (503) 9
Change in non-cash working
capital 7,040 (2,223) - 11,135 3,102 259
----------------------------------------------------------------------------
Cash flow from operating
activities: GAAP 20,694 9,496 118 59,066 52,150 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net Earnings/Loss

For the three and twelve months ended December 31, 2007, Delphi recorded earnings of $1.7 million and a net loss of $10.5 million, respectively, compared to net earnings of $0.3 million and $6.9 million in the comparative periods of 2006. Earnings for the twelve 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 the net loss.



Netback Analysis

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Barrels of oil equivalent
($/boe)
Realized sales price 49.33 50.02 (1) 50.41 49.36 2
Royalties, net of ARTC 7.58 6.13 24 7.50 7.20 4
Operating expenses 8.29 8.42 (2) 8.99 8.29 8
Transportation 2.57 3.55 (28) 3.16 3.38 (7)
----------------------------------------------------------------------------
Operating netback 30.89 31.92 (3) 30.76 30.49 1
G&A 2.66 1.72 55 1.90 1.24 53
Interest 2.76 4.42 (38) 3.89 3.28 19
Current taxes 0.01 - - - - -
----------------------------------------------------------------------------
Cash netback 25.46 25.78 (1) 24.97 25.97 (4)
Unrealized (gain)/loss on
financial contracts 1.72 (0.76) - (0.39) (0.52) (25)
Stock-based compensation
expense 1.02 0.69 48 0.67 1.31 (49)
Depletion, depreciation and
accretion 26.20 24.58 7 25.53 21.15 21
Impairment of goodwill - - - 6.23 - -
Future income taxes
(recovery) (6.68) 0.64 - (1.69) 0.41 -
----------------------------------------------------------------------------
Net earnings (loss) 3.20 0.63 408 (5.38) 3.62 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Approximately 84 percent of Delphi's production is natural gas and therefore Delphi's cash netbacks are primarily driven by the price received for natural gas.



Liquidity and Capital Resources

Funding

Three Months Ended Twelve Months Ended
December 31, 2007 December 31, 2007
----------------------------------------------------------------------------
Sources:
Funds from operations 13,747 48,481
Disposition of petroleum and
natural gas properties - 15,502
Issue of common shares, net of
issue costs - 16,882
Cash 847 757
Change in non-cash working capital 10,490 14,723
----------------------------------------------------------------------------
25,084 96,345

Uses:
Capital expenditures 16,991 51,924
Acquisition of petroleum and
natural gas properties - 10,871
Expenditures on site restoration
and reclamation 93 550
----------------------------------------------------------------------------
17,084 63,345

Increase / (decrease) in bank debt (8,000) (33,000)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and twelve months ended December 31, 2007, Delphi primarily funded its capital program through a combination of funds from operations, the issuance of flow-through common shares and funds received from the Bigfoot/Hythe swap transaction.

On March 1, 2007, Delphi issued 7,350,000 flow-through common shares at an issue price of $2.45 per common share for aggregate proceeds of $18.0 million.

Share Capital

At December 31, 2007, the Company had 68.1 million common shares outstanding (December 31, 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 twelve months ended December 31, 2007.



Three Months Ended Twelve Months Ended
December 31, 2007 December 31, 2007
----------------------------------------------------------------------------
Weighted Average Common Shares
Basic 68,070 66,835
Diluted 68,070 66,983
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 March 17, 2008 the Company had 68.4 million common shares outstanding and 5.4 milllion stock options outstanding.

Bank Debt plus Working Capital Deficit

At December 31, 2007, the Company had $82.0 million outstanding on its credit facility and a working capital deficit of $18.7 million for total debt plus working capital deficit of $100.7 million excluding the financial asset of $1.1 million relating to the unrealized gain on financial commodity contracts. Net debt levels have decreased 15 percent from December 31, 2006. Delphi anticipates spending less than projected funds from operations on capital expenditures during 2008.

The capital intensive nature of the industry will generally result in the Company having a working capital 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 from operations ratio: 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.

Contractual Obligations

The Company has a 364 day committed revolving credit facility with a syndicate of Canadian chartered banks which is available until April 30, 2008, the term out date. The term out date may be extended for an additional 364 days upon approval by the banks. Following the term out date, the facilities would become non-revolving for a one year term, at which time the balance outstanding will be due and payable. The Company believes the term will be extended for an additional 364 day period by April 30, 2008.

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



The future minimum commitments are as follows:

2008 2009 2010 2011 2012
----------------------------------------------------------------------------
Bank debt (1) - 82,000 - - -
Gas transmission and treatment 3,500 3,573 3,530 3,187 1,699
Office Lease 582 589 603 609 623
Operating leases on field equipment 35 - - - -
----------------------------------------------------------------------------
Total 4,117 86,162 4,133 3,796 2,322
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2007, the Company had incurred the necessary qualifying exploration expenditures to satisfy the terms of the flow through shares issued in 2006. Although the Company believes it has incurred the necessary qualifying expenditures, these amounts may be subject to audit and subsequent interpretation by the Canada Revenue Agency. The Company has an obligation to incur an additional $14.5 million in qualifying exploration expenditures by December 31, 2008 to satisfy the obligation relating to the issuance of flow-through shares in 2007.

Guarantees and Off-Balance Sheet Arrangements

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

Critical Accounting Estimates

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

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

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

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

- Estimated capital expenditures on projects that are in progress;

- Estimated fair value of derivative contracts;

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

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

Changes in Accounting Policies and Filing Requirements

Internal Control over Financial Reporting

On March 30, 2007, the Canadian Securities Administrators published a replacement for Multilateral Instrument 52-109 Certification of Disclosure in Issuer's Annual and Interim Filings (MI 52-109). The proposed National Instrument 52-109 (NI 52-109) represents an approach designed to balance the costs associated with internal control reporting and certification requirements with the benefit from increasing management's focus on, and accountability for, the quality of Internal Controls over Financial Reporting (ICOFR). The significant changes will cause certifying officers, the CEO and CFO, to certify in the annual certificates that they have evaluated the effectiveness of ICOFR at the financial year end and that they have disclosed in the annual MD&A their conclusions about the effectiveness of ICOFR. There is also no requirement to evaluate the effectiveness of the ICOFR against a suitable framework or to file management and auditor internal control audit reports regarding the ICOFR. The proposed NI 52-109 is expected to be effective December 31, 2008. Delphi will continue with its evaluation of ICOFR to ensure it meets the requirements for proposed certification effective December 31, 2008.

Financial Instruments

Effective January 1, 2007, the Company adopted the new Canadian accounting standards Section 3855 - Financial Instruments - Recognition and Measurement; Section 3861 - Financial Instruments - Presentation and Disclosure, Section 3865 - Hedges and Section 1530 - Comprehensive Income. The standards require all financial instruments other than held-to-maturity investments, loans and receivables and other financial liabilities to be included on the balance sheet at fair value. Held-to-maturity investments, loans and receivables and other financial liabilities are measured at their amortized cost. These standards also create a new Statement of Comprehensive Income for the changes in the fair value of derivative financial instruments. 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 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 3862 - Financial Instruments - Disclosures and Section 3863 - Financial Instruments -Presentation which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Company did adopt these standards on January 1, 2008.

Capital Disclosures

Effective December 31, 2007 Delphi adopted Section 1535, the new recommendations of the CICA for disclosure of the Company's objectives, policies and processes for managing capital. See note 7 of the Company's audited financial statements.

International Financial Reporting Standards

On February 13, 2008, Canada's Accounting Standards Board confirmed January 1, 2011 as the effective date for the convergence of Canadian GAAP to International Financial Reporting Standards. Delphi will continue to monitor the progress of the Canadian Securities Administrators plan for transition. Due to the extended period of time until implementation, Delphi has not yet determined the effects on its financial position or results of operations.

Corporate Governance

Overview

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

Disclosure Controls and Procedures

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

2008 Outlook

Strategy

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

2008 Capital Activities

The capital program for 2008 has been established at an estimated $50.0 million for the drilling of approximately 15 to 18 net wells. The Company has allocated approximately one-third of its capital to each of Bigstone and Hythe with the remaining one-third allocated to other areas throughout the year. The majority of the expenditures through the winter drilling season will be allocated to Bigstone. In the latter half of the year, the majority of the capital will be directed towards Hythe, once the technical teams have had sufficient time to evaluate the multi-zone nature of this significant land base. Positive results from the capital program, coupled with moderating industry service and equipment costs and secure financial resources, continue to be the main drivers of Delphi's capital investing decision making in the context of natural gas prices and the proposed Alberta royalty regime changes. Delphi is well positioned to internally finance its capital program through funds from operations and available bank lines, if necessary.

2008 Production Guidance

For 2008, the Company has forecast average production volumes to be in the 6,000 to 6,200 boe/d range, an increase of 15 percent over the average production volumes in 2007. First quarter production is expected to average approximately 6,000 boe/d. Further quarterly production guidance will be made available throughout the year. The volumes will continue to be dominated by natural gas production of approximately 80 to 85 percent.

Alberta Royalty Review

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

Additional Information

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

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

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

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

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

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

AUDITORS' REPORT TO THE SHAREHOLDERS

We have audited the consolidated balance sheets of Delphi Energy Corp. as at December 31, 2007 and 2006 and the consolidated statements of earnings/(loss), comprehensive income/(loss) and retained earnings and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

("Signed")

KPMG LLP,

Chartered Accountants

Calgary, Canada

March 19, 2008



DELPHI ENERGY CORP.
Consolidated Balance Sheets
As at December 31

($ thousands) 2007 2006
----------------------------------------------------------------------------
Assets
Current assets
Cash - 757
Accounts receivable 12,604 16,097
Prepaid expenses and deposits 2,752 1,460
Risk management asset (Note 9) 1,113 348
----------------------------------------------------------------------------
16,469 18,662

Property, plant and equipment (Note 4) 295,266 295,906
Goodwill (Note 11) - 12,100
----------------------------------------------------------------------------
Total assets 311,735 326,668
----------------------------------------------------------------------------

Liabilities
Current liabilities
Accounts payable and accrued liabilities 34,014 21,492

Long term debt (Note 5) 82,000 115,000
Future income taxes (Note 8) 28,162 23,776
Asset retirement obligations (Note 6) 7,183 7,951
----------------------------------------------------------------------------
Total liabilities 151,359 168,219

Shareholders' equity
Share capital (Note 7) 148,898 139,108
Contributed surplus (Note 7) 8,236 5,627
Retained earnings 3,242 13,714
----------------------------------------------------------------------------
Total shareholders' equity 160,376 158,449
----------------------------------------------------------------------------
Total liabilities and shareholders' equity 311,735 326,668
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Commitments (Note 10)

See accompanying notes to the consolidated financial statements.


Approved by the Board of Directors,



("Signed") ("Signed")
Henry R. Lawrie Lamont C. Tolley
Director Director



DELPHI ENERGY CORP.
Consolidated Statements of Earnings/(Loss), Comprehensive Income/(Loss)
and Retained Earnings
For the years ended December 31

($ thousands, except per unit amounts) 2007 2006
----------------------------------------------------------------------------

Revenue
Petroleum and natural gas sales 96,479 94,374
Realized gain/(loss) on risk management activities 1,454 (185)
----------------------------------------------------------------------------
97,933 94,189
Royalties (14,580) (13,731)
Unrealized gain on risk management activities 765 993
----------------------------------------------------------------------------
84,118 81,451

Expenses
Operating 17,464 15,826
Transportation 6,148 6,455
General and administrative 3,696 2,372
Stock-based compensation (Note 7) 1,297 2,491
Interest 7,561 6,254
Depletion, depreciation and accretion 49,600 40,364
Impairment of goodwill (Note 11) 12,100 -
----------------------------------------------------------------------------
97,866 73,762
----------------------------------------------------------------------------

Earnings/(loss) before taxes (13,748) 7,689

Taxes (Note 8)
Current 3 -
Future/(reduction) (3,279) 786
----------------------------------------------------------------------------
(3,276) 786

Net earnings/(loss) and comprehensive income/(loss) (10,472) 6,903
Retained earnings, beginning of year 13,714 6,811
----------------------------------------------------------------------------
Retained earnings, end of year 3,242 13,714
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net earnings/(loss) per share (Note 7)
Basic (0.16) 0.12
Diluted (0.16) 0.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.



DELPHI ENERGY CORP.
Consolidated Statements of Cash Flows
For the years ended December 31


($ thousands) 2007 2006
----------------------------------------------------------------------------

Cash flow from operating activities
Net earnings/(loss) (10,472) 6,903
Add non cash items:
Depletion, depreciation and accretion 49,600 40,364
Impairment of goodwill (Note 11) 12,100 -
Stock-based compensation 1,297 2,491
Unrealized gain on risk management activities (765) (993)
Future taxes/(reduction) (3,279) 786
Expenditures on asset retirement obligations (550) (503)
Change in non-cash working capital (Note 12) 11,135 3,102
----------------------------------------------------------------------------
59,066 52,150
Cash flow from financing activities
Issue of common shares, net of issue costs 16,882 23,583
Increase/(decrease) in bank debt (33,000) 73,300
----------------------------------------------------------------------------
(16,118) 96,883
Cash flow used in investing activities
Capital expenditures (51,924) (165,352)
Acquisition of petroleum and natural gas properties (10,871) -
Disposition of petroleum and natural gas properties 15,502 34,918
Change in non-cash working capital (Note 12) 3,588 (17,842)
----------------------------------------------------------------------------
(43,705) (148,276)

Increase in cash and cash equivalents (757) 757
Cash and cash equivalents, beginning of year 757 -
----------------------------------------------------------------------------
Cash and cash equivalents, end of year - 757
----------------------------------------------------------------------------

Interest paid 7,087 5,585
Taxes paid 3 220
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


DELPHI ENERGY CORP.
Notes to Consolidated Financial Statements
As at and for the years ended December 31, 2007 and 2006
(all tabular amounts are expressed in thousands of dollars, except per unit
amounts)


NOTE 1: DESCRIPTION OF BUSINESS

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

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements of Delphi have been prepared by management in accordance with accounting principles generally accepted in Canada. The preparation of financial statements in conformity 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. Actual results may differ from these estimates.

(a) Principles of consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. Any reference to the Company refers to the Company and its subsidiaries. All inter-company transactions have been eliminated.

(b) Petroleum and natural gas operations

The Company follows the full cost method of accounting whereby all costs associated with the exploration for and development of petroleum and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical costs, lease rental costs on non-producing properties, costs of both productive and unproductive drilling and production equipment. Gains or losses are not recognized upon disposition of petroleum and natural gas properties unless crediting the proceeds against accumulated costs would result in a change in the depletion rate of 20% or more.

The accumulated costs, less the costs of acquisition of unproved properties, are depleted using the unit-of-production method based upon total proved reserves before royalties as determined by independent evaluators. Natural gas reserves and production are converted into equivalent barrels of oil at 6:1 based upon the estimated relative energy content.

The costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of impairment is added to the costs subject to depletion.

The Company is required to perform a ceiling test at least annually to assess the carrying amount of oil and gas assets. The costs are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves using forecast prices and the lower of cost and market of unproved properties exceed the carrying amount of the petroleum and natural gas assets. If the carrying amount of the petroleum and natural gas assets is assessed to not be recoverable, an impairment loss is recognized to the extent that the carrying amount exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. This approach incorporates risks and uncertainties in the expected future cash flows, which are discounted using a risk free rate.

Depreciation of furniture and office equipment is provided using the declining balance method based upon estimated useful lives of 20% to 50%.

(c) Joint operations

Substantially all of the Company's exploration, development and production activities are conducted jointly with others and the financial statements reflect the Company's proportionate interest in such activities.

(d) 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 will be charged to income in the period of the impairment.

(e) Asset retirement obligations

The Company recognizes the fair value of an asset retirement obligation as a liability at the time it incurs a legal obligation for the future abandonment and reclamation costs associated with its petroleum and natural gas operations. Asset retirement obligations are initially measured at their fair value and subsequently adjusted to reflect the passage of time (accretion) and any changes to the estimated cash flows underlying the obligation. The associated asset retirement cost is capitalized as part of property, plant and equipment and amortized to earnings using the unit of production method over estimated proved reserves consistent with the depletion and depreciation of the underlying asset.

(f) Stock-based compensation

The Company records a compensation cost for all stock options granted to employees, directors or key consultants over the vesting period of the options based on the fair value method. The compensation cost is a charge to earnings or capitalized as a cost of exploration and development activities with an offsetting increase to contributed surplus on the balance sheet. Consideration paid by employees, directors or key consultants upon exercise of the stock options and the amount previously recognized in contributed surplus are recorded as share capital. The Company has not incorporated an estimated forfeiture rate for stock options that will not vest, rather, the Company accounts for actual forfeitures as they occur.

(g) Future income taxes

The Company follows the tax liability method of accounting for income taxes. Under this method, estimated future income tax assets and liabilities are determined based upon differences between the carrying amount as reported on the balance sheet and the tax basis of assets and liabilities and measured using substantively enacted tax rates and laws expected to be in effect when the differences are expected to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in earnings in the period in which the change occurs. A valuation allowance is recognized against any future income tax assets if it is considered more likely than not that the asset will not be realized.

(h) Flow-through shares

The resource expenditure deductions for income tax purposes related to exploration and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. To recognize the foregone tax benefits to the Company, the future income tax liability and share capital are adjusted by the estimated cost of the renounced tax deduction on the date of renouncement.

(i) Per share information

Basic per share amounts are computed by dividing the net earnings by the weighted average number of common shares outstanding for the year. Diluted per share amounts reflect the potential dilution that would occur if securities or other contracts to issue common shares were exercised or converted to common shares. Diluted per share information is calculated using the treasury stock method that assumes any proceeds received by the Company upon the exercise of in-the-money stock options, plus the unamortized stock based compensation cost, would be used to buy back common shares at the average market price for the period. Anti-dilutive options or instruments are not included in the calculation.

(j) Financial instruments

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 retrospectively. The adoption of these standards had no effect on opening retained earnings or accumulated other comprehensive income.

i) 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: changes in fair value of held-for-trading financial assets are recognized in net earnings; changes in fair value of available-for-sale financial instruments are 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 was measured at fair value. Accounts receivable were classified as loans and receivables and were measured at amortized cost. Accounts payable and long term debt were classified as other financial liabilities and were measured at amortized cost.

ii) 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 financial 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.

iii) 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, relates 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.

iv) 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 term of the resulting financial instrument.

(k) Measurement uncertainty

The amounts recorded for depletion and depreciation of petroleum and natural gas properties and equipment are based upon estimates of proved petroleum and natural gas reserves, production rates, commodity prices and future costs. The impairment test is based upon estimates of proved and, if applicable, probable reserves, production rates, petroleum and natural gas prices, future costs and other assumptions. The asset retirement obligations are based upon petroleum and natural gas reserves, future costs, expected inflation rates and other assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes to estimates in future periods could be material.

(l) Cash and cash equivalents

The Company considers deposits in banks, certificates of deposit and short-term investments with original maturities of three months or less as cash and cash equivalents. Bank borrowings are considered to be financing activities.

(m) Revenue recognition

Crude oil and natural gas revenues are recognized in earnings when title passes from the Company to its customer.

NOTE 3: CHANGE IN ACCOUNTING POLICIES

Effective January 1, 2007 the Company adopted new disclosure standards with respect to capital management.

Effective January 1, 2008 new accounting standards will require additional disclosure about the Company's financial instruments to be included in the financial statements. The guidance prescribes an increased importance on risk disclosures associated with realized and unrealized financial instruments and how such risks are managed. In addition, the guidance outlines revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial instruments.



NOTE 4: PROPERTY, PLANT AND EQUIPMENT

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

As at 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 $15.1 million in cash.

As at December 31, 2007, costs in the amount of $10.8 million (December 31, 2006 - $35.8 million) representing unproved properties were excluded from the depletion calculation and estimated future development costs of $15.7 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 depletion and determined that no impairment has occurred.

The Company capitalized $2.3 million (December 31, 2006 - $1.8 million) of general and administrative costs directly related to exploration and development activities.

The Company performed a ceiling test calculation at December 31, 2007 to assess the recoverable value of property, plant and equipment, which indicated no write down was required. The future commodity prices used in the impairment test were based on December 31, 2007 commodity price forecasts of the Company's independent reserve engineers adjusted for differentials specific to the Company's reserves. The following table summarizes the future benchmark prices the Company used in the impairment test.



---------------------------------------------------------------------------
Natural Gas Natural Gas Liquids Crude Oil
---------------------------------------------------------------------------
West
Texas Edmon- Bow
Henry AECO Pentanes Inter- ton River
Hub Spot Propane Butane Plus mediate Light Hardisty
---------------------------------------------------------------------------
(US$/ (CDN$/ (CDN$/ (CDN$/ (CDN$/ (US$/ (CDN$/ (CDN$/
mmbtu) mmbtu) bbl) bbl) bbl) bbl) bbl) bbl)

2008 7.40 6.75 58.30 72.88 92.92 92.00 91.10 63.77
2009 8.20 7.55 55.74 69.68 88.84 88.00 87.10 60.97
2010 8.25 7.60 53.18 66.48 84.76 84.00 83.10 58.17
2011 8.35 7.60 51.90 64.88 82.72 82.00 81.10 56.77
2012 8.35 7.60 51.90 64.88 82.72 82.00 81.10 56.77
2013 8.35 7.60 51.90 64.88 82.72 82.00 81.10 57.58
2014 8.55 7.80 51.90 64.88 82.72 82.00 81.10 58.39
2015 8.72 7.97 51.90 64.88 82.72 82.00 81.10 59.20
2016 8.89 8.14 51.91 64.89 82.74 82.02 81.12 60.03
2017 9.06 8.31 52.97 66.21 84.42 83.66 82.76 61.24
There
after (1)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) A percentage increase of 2% represents the change in future prices each
year after 2017 to the end of the reserve life.


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 $16.3 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.



As at December 31 2007 2006
---------------------------------------------------------------------------
Balance, beginning of year $ 7,951 $ 7,394
Liabilities incurred 1,017 606
Liabilities disposed (1,873) (183)
Liabilities settled (550) (503)
Accretion expense 638 637
---------------------------------------------------------------------------
Balance, end of year $ 7,183 $ 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

2007 2006
---------------------------------------------------------------------------
Outstanding Outstanding
shares shares
As at December 31 (000's) Amount (000's) Amount
---------------------------------------------------------------------------
Balance, beginning of year 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 - 39 - 145
Share issue costs - (1,208) - (1,725)
Future tax effect of
share issue costs - 369 - 528
Tax benefit renounced
to shareholders - (7,500) - (8,840)
---------------------------------------------------------------------------
Balance, end of year 68,070 $ 148,898 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 2006. Although the Company believes it has incurred the necessary qualifying expenditures, these amounts may be subject to audit and subsequent interpretation by the Canada Revenue Agency. The Company has an obligation to incur qualifying exploration expenditures of $18.0 million by December 31, 2008 to satisfy the obligation relating to the issuance of flow-through shares in 2007, of which $14.5 million remains to be incurred as at December 31, 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 December 31, 2007 there were 5.5 million options to purchase shares outstanding.

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



2007 2006
------------------------------------------------
Weighted Weighted
Outstanding average Outstanding average
options exercise options exercise
As at December 31 (000's) price (000's) price
---------------------------------------------------------------------------
Balance, beginning of year 4,229 $ 3.40 2,629 $ 2.37
Granted 4,500 1.67 1,800 4.69
Cancelled (121) 3.92 - -
Forfeited (3,070) 4.09 - -
Exercised (57) 1.45 (200) 1.53
---------------------------------------------------------------------------
Balance, end of year 5,481 $ 1.60 4,229 $ 3.40
---------------------------------------------------------------------------
Exercisable at end of year 2,481 $ 1.52 2,641 $ 2.81
---------------------------------------------------------------------------
---------------------------------------------------------------------------



The following table summarizes information about the stock options
outstanding and exercisable at December 31, 2007.

Options outstanding Options exercisable
--------------------------------- ----------------------
Weighted
Weighted average Weighted
Outstanding average remaining average
Range of Options exercise term Exercisable exercise
exercise price (000's) price (years) (000's) price
---------------------------------------------------------------------------
$0.99 344 $ 0.99 0.2 344 $ 0.99
$1.45 - 1.79 5,122 1.64 4.0 2,132 1.61
$1.80 - 2.00 15 1.93 4.5 5 1.93
---------------------------------------------------------------------------
Total 5,481 $ 1.60 4.0 2,481 $ 1.52
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(d) Stock-based compensation

The Company accounts for its stock-based compensation using the fair value method for all stock options. For the year ended December 31, 2007 Delphi recorded non-cash compensation expense of $1.3 million. The Company capitalized $1.3 million (December 31, 2006 - $0.9 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 $0.96 per share. The assumptions used in the Black-Scholes model to determine fair value were as follows:



Year ended December 31 2007 2006
---------------------------------------------------------------------------
Risk free interest rate (%) 5.0 5.0
Expected life (years) 5.0 5.0
Expected volatility (%) 53.0 45.0
---------------------------------------------------------------------------
---------------------------------------------------------------------------



(e) Contributed surplus

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

As at December 31 2007 2006
---------------------------------------------------------------------------
Balance, beginning of year $ 5,627 $ 2,380
Stock-based compensation costs 2,648 3,392
Reclassification to common shares on
exercise of stock options (39) (145)
---------------------------------------------------------------------------
Balance, end of year $ 8,236 $ 5,627
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(f) Net earnings/(loss) per share

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

Year ended December 31 2007 2006
---------------------------------------------------------------------------
Basic 66,835 58,051
Diluted 66,983 58,845
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The reconciling item between the basic and diluted weighted average common shares outstanding is stock options. In 2007, the majority of stock options were anti-dilutive and therefore excluded from the diluted weighted average shares outstanding.

(g) Capital management

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

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

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

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

At December 31, 2007 net debt, excluding risk management assets or liabilities, was $100.7 million and funds from operations was $48.5 million resulting in a net debt to funds from operations ratio of 2.1 times, down from 2.4 times at December 31, 2006. On an annualized fourth quarter 2007 basis, funds from operations would be $55.0 million resulting in a net debt to funds from operations ratio of 1.8 times. The Company is focused on achieving its internal target range for this ratio of 1.3 to 1.5 times.

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

NOTE 8: TAXES

(a) Expected tax rate

The provision for income taxes in the financial statements differs from the result that would have been obtained by applying the combined federal and provincial tax rates to the Company's earnings before taxes.

The difference results from the following items:



Year ended December 31 2007 2006
---------------------------------------------------------------------------
Earnings (loss) before income taxes $ (13,748) $ 7,689
Statutory tax rate 32.46% 34.74%
Expected income tax expense (4,463) 2,671
Crown charges - 126
Resource allowance - (4)
Alberta royalty tax credit - (74)
Stock-based compensation 421 865
Attributed Canadian Royalty Income (ACRI) 96 (226)
Reduction in future income tax rates (3,634) (3,019)
Impairment of goodwill 3,928 -
Other 376 447
---------------------------------------------------------------------------
Total taxes $ (3,276) $ 786
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(b) Future tax liability

The tax effect of temporary differences that give rise to significant portions of the future tax assets and liabilities at December 31, 2007 and 2006 are presented below:



As at December 31 2007 2006
---------------------------------------------------------------------------
Future income tax assets:
Asset retirement obligations $ 1,885 $ 2,385
ACRI 270 367
Risk management asset (332) (121)
Non capital losses 4,142 -
Share issue costs 1,160 1,569
Future income tax liabilities:
Property, plant and equipment (35,287) (27,976)
---------------------------------------------------------------------------
Net future income tax liability $ (28,162) $ (23,776)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


NOTE 9: FINANCIAL INSTRUMENTS

(a) 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 December 31, 2007, the Company has fixed the price applicable to future production through the following contracts:



Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
---------------------------------------------------------------------------
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 US $10.28 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
November 2008 -
March 2009 Natural Gas Physical 4,000 GJ/d $7.46 fixed
November 2008 - $7.00 floor/
March 2009 Natural Gas Physical 2,000 GJ/d $8.05 ceiling
---------------------------------------------------------------------------
---------------------------------------------------------------------------



The Company entered into the following contracts subsequent to December 31,
2007:

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


(b) Fair value of financial instruments

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

(c) 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.

(d) 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.

(e) Interest rate risk

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

NOTE 10: CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The Company is committed to future minimum payments for natural gas transmission and processing and operating leases on compression equipment and office space. The Company's extendible term credit facility is available on a revolving basis until April 30, 2008, the term-out date. The term out date may be extended for a further 364 day period upon approval by the banks. Following the term-out date, the facilities would be available on a non-revolving basis for a one year term. The Company believes the term will be extended for an additional 364 day period. Without assuming the renewal of the credit facilities, payments required under these commitments for each of the next five years are: 2008-$4.1 million; 2009-$86.2 million; 2010-$4.1 million; 2011-$3.8 million; 2012-$2.3 million.

NOTE 11: 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 12: CHANGES IN NON-CASH WORKING CAPITAL ITEMS

Year ended December 31 2007 2006
---------------------------------------------------------------------------
Change in working capital item:
Accounts receivable $ 3,493 $ 1,810
Prepaid expenses and deposits (1,292) 9,710
Accounts payable and accrued liabilities 12,522 (26,260)
---------------------------------------------------------------------------
Total change in non-cash working capital 14,723 (14,740)
Relating to:
Operating activities 11,135 3,102
Financing activities - -
Investing activities 3,588 (17,842)
---------------------------------------------------------------------------
$ 14,723 $ (14,740)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Contact Information

  • Delphi Energy Corp.
    David J. Reid
    President & CEO
    (403) 265-6171
    or
    Delphi Energy Corp.
    Brian Kohlhammer
    V.P. Finance & CFO
    (403) 265-6171
    (403) 265-6207 (FAX)
    Email: info@delphienergy.ca
    Website: www.delphienergy.ca