Delphi Energy Corp.
TSX : DEE

Delphi Energy Corp.

March 18, 2009 20:23 ET

Delphi Energy Achieves Record Fourth Quarter 2008 Results

CALGARY, ALBERTA--(Marketwire - March 18, 2009) - Delphi Energy Corp. (TSX:DEE) ("Delphi" or the "Company") is pleased to announce its financial and operational results for the year ended December 31, 2008.

2008 Highlights

- Achieved record production of 6,708 barrels of oil equivalent per day (boe/d) in the fourth quarter of 2008, marking the seventh consecutive quarter of production growth. Annual production increased 19 percent to average 6,345 boe/d, compared to 5,323 boe/d last year.

- Generated record funds from operations of $68.7 million ($0.94 per basic share), a 42 percent increase over $48.5 million ($0.72 per basic share) in the previous year.

- Drilled 23 (16.7 net) wells with an overall success rate of 96 percent.

- Increased total proved reserves by 33 percent to 15.1 million barrels of oil equivalent and total proved plus probable reserves by 28 percent to 22.0 million barrels of oil equivalent. Total proved plus probable reserves per basic share outstanding increased by 10 percent.

- Increased net asset value by 22 percent to $3.16 per share based on the before tax net present value of total proved plus probable reserves discounted at ten percent.

- Increased the Company's undeveloped land position by 40 percent to approximately 125,400 net acres.

- Increased the Company's natural gas hedge position to 50 percent of current 2009 production at an average floor price of $7.42 per mcf, 64 percent higher than the current forward AECO strip.

- Increased the Company's financial flexibility as of December 31, 2008 by $6.5 million to $30.8 million of unutilized credit facilities as compared to December 31, 2007.

- Acquired crude oil and natural gas properties producing 650 boe/d for $38.0 million in the Peace River Arch area of northwest Alberta and northeast British Columbia.

- Closed an equity offering of 6,316,000 common shares at $2.85 per share and 3,530,000 flow-through common shares at $3.40 per share for proceeds of approximately $30.0 million (net proceeds of $28.0 million).



Operational Highlights
Three Months Ended Year Ended
December 31 December 31
% %
Production 2008 2007 Change 2008 2007 Change
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Natural gas (mcf/d) 35,545 30,610 16 33,236 26,886 24
Crude oil (bbl/d) 431 346 25 390 429 (9)
Natural gas liquids (bbl/d) 353 420 (16) 416 413 1
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Total (boe/d) 6,708 5,868 14 6,345 5,323 19
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Financial Highlights
($ thousands except
per unit amounts)
Three Months Ended Year Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Petroleum and
natural gas sales 30,160 26,632 13 135,402 97,933 38
Per boe 48.87 49.33 (1) 58.31 50.41 16
Funds from
operations 13,473 13,747 (2) 68,657 48,481 42
Per boe 21.83 25.46 (14) 29.57 24.97 18
Per share - Basic 0.18 0.20 (10) 0.94 0.72 31
Per share - Diluted 0.18 0.20 (10) 0.93 0.72 29
Net earnings (loss) (959) 1,732 - 5,094 (10,472) -
Per boe (1.56) 3.20 - 2.19 (5.38) -
Per share - Basic (0.01) 0.03 - 0.07 (0.16) -
Per share - Diluted (0.01) 0.03 - 0.07 (0.16) -
Capital invested 15,660 16,991 (8) 76,779 51,924 48
Disposition of properties - - - (8,450)(15,502) (45)
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Net capital invested 15,660 16,991 (8) 68,329 36,422 88
Acquisition of properties 174 - 100 38,120 10,871 251
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Total capital 15,834 16,991 (7)106,449 47,293 125
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December December %
31, 2008 31, 2007 Change
----------------------------------------------------------------------------
Debt plus working capital deficiency (1) 109,237 100,658 9
Total assets 364,538 311,740 17
Shares outstanding (000's)
Basic 79,067 68,070 16
Diluted 83,798 73,551 14
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(1) excludes risk management asset and the related current future income tax
liability.


MESSAGE TO SHAREHOLDERS

Delphi enjoyed another successful year in 2008, accomplishing its goals of delivering operational and financial growth, maintaining financial flexibility and ensuring the Company remains well positioned for sustainable long term organic growth in any business environment.

These are challenging times as the global recession deepens and commodity prices remain under pressure. Delphi is well positioned to operate effectively in these challenging times. The Company has entered this recession in a position of strength and will come out the other side with momentum for continued and accelerated growth. It is Delphi's employees with their skill and untiring dedication, management with their leadership and years of experience and the Board of Directors with their stewardship and support that make the difference.

Operational results in 2008 are highlighted by record production volumes and record reserve growth. Production during 2008 averaged 6,345 barrels of oil equivalent per day (boe/d), representing a 19 percent increase from 5,323 boe/d in 2007. The Company also achieved record production and seven consecutive quarters of production growth during the fourth quarter of 2008 averaging 6,708 boe/d. Total proved reserves increased by 33 percent to 15.1 million barrels of oil equivalent and total proved plus probable reserves by 28 percent to 22.0 million barrels of oil equivalent. The net asset value increased by 22 percent to $3.16 per share based on the before tax net present value of total proved plus probable reserves discounted at ten percent.

Financial results in 2008 are highlighted by record funds flow from operations (cash flow), strong earnings and increased financial flexibility. The Company reported record cash flow of $68.7 million ($0.94 per basic share) and earnings of $5.1 million ($0.07 per basic share) during 2008. Financial flexibility increased again during 2008 with debt and working capital improving to 78 percent of available bank facilities at December 31, 2008. Unutilized credit available on the Company's $140.0 million banking facilities increased to $30.8 million at year-end 2008, $6.5 million greater than at year-end 2007. The debt to trailing cash flow ratio at December 31, 2008 improved to 1.6 times from 2.1 at December 31, 2007.

Delphi has positioned itself to deliver long term sustainable growth. The Company's undeveloped land position increased 40 percent to 125,400 net acres during 2008. The high quality concentrated producing assets and undeveloped land base focused at Hythe and Bigstone in northwest Alberta continue to deliver predictable economic production and reserve growth. Conventional vertical well opportunities blended with complementary horizontal well resource plays continue to provide an effective balance between superior flowing barrel capital efficiencies of conventional opportunities with typically more attractive finding and development costs of resource style plays. Technological advances such as multi-stage fracs in horizontal wells and gas fracing techniques are being applied successfully to these multi-zone areas improving production rates, ultimate reserve recoveries and significantly increasing the drilling inventory for future growth. Delphi has also been active at Crown land sales over the past several months. The Company views the current business environment as an opportunistic entry point to accumulate strategic undeveloped land further strengthening Delphi's long term growth inventory.

OPERATIONAL REVIEW

Delphi maintains a competitive advantage within its core areas with operatorship and control of over 84 percent of its production, field gathering and processing infrastructure. Synergies exist between all of the core areas and amongst the operational and technical expertise of the team. 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 resulting in economic netbacks and recycle ratios.

During 2008, Delphi completed a net field capital program of $68.3 million, drilling 23 (16.7 net) wells with a 96 percent success rate. The Company operated over 90 percent of its capital program. The program was funded entirely from internally generated cash flow from operations of $68.7 million, consistent with the previous year and the Company's strategy.

Finding and development costs on proved and probable reserve additions, inclusive of future development capital, was $20.15 per boe generating a recycle ratio based on operating netbacks of 1.7 times. All-in finding, development and net acquisition costs on proved plus probable reserve additions for Delphi's total net capital program of $106.4 million, was $20.70 per boe with a very similar recycle ratio. The Company achieved a reserve replacement ratio of 212 percent during 2008 and increased its reserve life index to a robust 9.5 years.

Delphi's operational success during 2008 was a result of a continued focus on its large inventory of growth opportunities in the multi-zone core areas of Bigstone and Hythe, Alberta. With minimal infrastructure dollars required due to ownership in processing facilities and excess capacity, Delphi was able to direct 71 percent of its capital program towards drilling and completion operations to increase production and reserves.

The inventory of conventional vertical and resource-style horizontal drilling locations continues to increase with positive results through the first quarter 2009 drilling program. Continued drilling, recompletion and optimization success at Hythe, Alberta has resulted in production growth of this core area to over 2,000 boe/d, up 400 percent from 400 boe/d at the time of acquisition in September 2007.

OUTLOOK

In 2009, Delphi will proceed cautiously and prudently with respect to executing a growth plan funded from expected cash flow in this environment of weak commodity prices driven by the ongoing global recession and financial turmoil. Maintaining operational and financial flexibility while expanding the Company's long-term growth inventory in a low-cost environment will be key drivers in the capital spending decision process throughout 2009.

Since 2006, Delphi has successfully mitigated downside commodity price risk with an active natural gas hedging program. During 2009, the Company has again hedged approximately 50 percent of its natural gas production. An average floor price of $7.42 per mcf for these hedged natural gas volumes during 2009 represents a 64 percent premium to the current 2009 forward strip price of $4.54 per mcf.

The recently announced Alberta royalty incentive plan is a positive development for Delphi. The stimulus program applies to new wells drilled between April 1, 2009 and March 31, 2010 and includes a royalty credit ($200 per metre drilled) based on measured depth drilled. These credits can be used to immediately and directly offset total corporate royalties payable to the Crown. In addition, Crown royalties payable during the twelve month period for these new wells is capped at 5 per cent on the first 500 mmcf of natural gas or 50,000 bbls of crude oil. The calculated impact to Delphi on a typical well drilled in Hythe or Bigstone is approximately $900,000. The affect of this incentive program is material to both project economics and the Company's cash flow. With typical drilling and completion costs averaging approximately $2.5 million per well, the drilling program through the second half of 2009 is anticipated to be positively affected.

The Company expects to spend an estimated $35.0 to $50.0 million in 2009 drilling 10 to 14 net wells compared to 16.7 net wells during 2008. The majority of the capital will again be directed towards drilling and completion activities in the Bigstone and Hythe core areas. Delphi expects to drill and test two additional zones during 2009 using horizontal drilling and multi-stage fracing technologies given the encouraging operational results achieved on the first two horizontal wells drilled in Hythe.

Delphi continues to evaluate and pursue potential property acquisitions and swaps complementary to its existing core assets. The Company continuously evaluates its minor non-core assets for disposition.

Delphi is forecasting weak natural gas prices to persist through to at least the fourth quarter of 2009 and is assuming a 2009 average AECO natural gas price range of $4.25 to $5.50 per mcf. Given the impact of the hedge contracts in place, the Company's 2009 realized natural gas price would be approximately $6.35 to $6.95 per mcf. The planned 2009 capital program executed within forecast cash flow is expected to result in production volumes of approximately 6,500 to 7,000 barrels of oil equivalent per day, and takes into account scheduled facility maintenance outages during the second quarter affecting approximately 330 barrels of oil equivalent per day in the Hythe, Bigstone, and Tower Creek areas.

Bank debt including working capital at the end of 2009 is estimated to be at or below the December 31, 2008 amount of $109.2 million.

Delphi remains confident in its ability to achieve continued per share growth during these challenging times and is excited about the 2009 drilling program. The expanding inventory of drilling locations and growth prospects being generated gives rise to continued optimism for growth well beyond 2009.

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

CONFERENCE CALL

A conference call is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Thursday, March 19, 2009. The conference call number is 1-866-300-4047 or 416-641-6137. A brief presentation by David Reid, President and CEO and Brian Kohlhammer, VP Finance & CFO will be followed by a question and answer period.

If you are unable to participate in the conference call, a taped broadcast will be available until March 26, 2009. To access the replay, dial 1-800-408-3053 or 416-695-5800. The passcode is 3282102. Delphi's annual and fourth quarter 2008 financial statements and management's discussion and analysis are available on Delphi's website at www.delphienergy.ca and will be available on SEDAR at www.sedar.com within 24 hours.

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

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

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

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

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

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

MANAGEMENT DISCUSSION AND ANALYSIS

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

The management discussion and analysis has been prepared by management and reviewed and approved by the Board of Directors of Delphi Energy Corp. ("Delphi" or "the Company"). The discussion and analysis is a review of the financial results of the Company based upon accounting principles generally accepted in Canada. Its focus is primarily a comparison of the financial performance for the three and twelve months ended December 31, 2008 and 2007 and should be read in conjunction with the audited financial statements and accompanying notes for the years ended December 31, 2008 and 2007. The discussion and analysis has been prepared as of March 17, 2009.

DELPHI'S BUSINESS

Delphi is a public company primarily engaged in the acquisition, exploration for and development and production of crude oil, natural gas and natural gas liquids from properties located in Western Canada. Delphi's operations are principally concentrated in three core regions: (i) northwest Alberta, (ii) northeast British Columbia, and (iii) east central Alberta with an overall focus on natural gas production. The Company has three primary core areas at Bigstone, Hythe and Tower Creek, all located in northwest Alberta which comprise approximately 5,000 boe/d of production.

OPERATIONAL AND FINANCIAL HIGHLIGHTS

Delphi achieved record production in 2008 with average daily volumes of 6,345 barrels of oil equivalent per day (boe/d), an increase of 19 percent compared to 2007. Production volumes increased on a quarter over quarter basis throughout the year from an average of 6,056 boe/d in the first quarter to 6,708 boe/d in the fourth quarter, an increase of 11 percent. Fourth quarter sales volumes represent record production for the Company. Natural gas production comprised 87 percent of the Company's average production.

Several accomplishments were achieved in 2008 through the Company's capital program including:

- the continued growth in production of its core area of Hythe, Alberta to over 1,600 boe/d from 400 boe/d at the time of acquisition in September 2007;

- an increase in total proved reserves of 33 percent to 15.1 million barrels of oil equivalent and an increase in total proved plus probable reserves of 28 percent to 22.0 million barrels of oil equivalent;

- drilling of 23 (16.7 net) wells with an overall success rate of 96 percent and drilling three (2.5 net) natural gas wells resulting in a 100 percent success rate in the fourth quarter;

- an increase in total proved plus probable reserves per basic share outstanding of 10 percent; and

- the acquisition of approximately 650 boe/d and 35,000 net acres of undeveloped land in the Peace River Arch area of northwest Alberta and northeast British Columbia.

Funds flow from operations in 2008 was $68.7 million or $0.94 per basic share, compared to $48.5 million or $0.72 per basic share in 2007, primarily as a result of higher average oil and natural gas prices for the year and growth in production volumes. For the year ended December 31, 2008, the Company recognized approximately $0.1 million in realized gains on financial and physical hedging contracts. For the three months ended December 31, 2008, Delphi recognized approximately $1.6 million in realized gains on Canadian dollar denominated physical contracts, included in natural gas revenue, and recognized a realized gain of approximately $0.4 million on financial contracts and U.S. dollar denominated physical contracts.

On July 17, 2008, the Company closed an equity offering of 6,316,000 common shares at $2.85 per share and 3,530,000 flow-through common shares at $3.40 per share for proceeds of approximately $30.0 million (net proceeds of $28.0 million). In late July 2008, the Company completed the acquisition of oil and natural gas properties for $38.0 million, after closing adjustments, in the Peace River Arch area of northwest Alberta and northeast British Columbia. The acquisition was funded by the net proceeds of the equity offering and the Company's credit facilities.

Delphi's financial position continues to remain strong at the end of 2008, providing financial flexibility to execute its 2009 capital program and participate in farm-in, joint venture or acquisition opportunities. At December 31, 2008, the Company had net debt of $109.2 million on total credit facilities of $140.0 million, providing excess financial capacity of approximately $30.8 million. On an annualized fourth quarter funds from operations basis, Delphi's net debt to cash flow ratio was 2.0 times. Net debt includes bank debt plus working capital deficiency excluding the risk management asset/liability and the related current future income taxes.

The current credit facilities were confirmed by the Company's lenders upon completion of their semi-annual review in October, 2008. The annual credit review by the Company's lenders is expected to be completed by May 31, 2009. This detailed review will be based upon the Company's December 31, 2008 reserves engineering report and will take into consideration current production and the results of the winter drilling program. The borrowing base is determined using the Company's year-end engineering report, primarily proved producing reserves, which increased 21 percent over the previous year and the outlook for commodity prices.



BUSINESS ENVIRONMENT

Benchmark Prices
Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
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Natural Gas
NYMEX (US $/mmbtu) 6.83 7.03 (3) 8.92 6.91 29
AECO (CDN $/mcf) 6.70 6.15 9 8.16 6.44 27
Crude Oil
West Texas Intermediate
(US $/bbl) 58.73 90.68 (35) 99.65 72.31 38
Edmonton Light (CDN $/bbl) 63.21 86.42 (27) 102.16 76.35 34
Foreign Exchange
Canadian to US dollar 1.21 0.98 23 1.06 1.08 (2)
US to Canadian dollar 0.82 1.02 (20) 0.94 0.93 1
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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 from time to time. The increase in capacity of natural gas liquefaction and regasification facilities has resulted in natural gas in North America becoming a global commodity with influences from world weather conditions and global supply in the form of liquefied natural gas (LNG) delivered to the United States.

While partially influenced by the strength of crude oil price changes, natural gas price changes are predominantly based on supply and demand fundamentals in the North American market. In the first quarter, with global natural gas prices considerably higher than the prices in the United States, LNG imports to the U.S. throughout the winter were less than average and significantly less than the peak imports during the summer of 2007. Cold winter weather persisted to the end of March 2008 in the major natural gas consuming regions of Central Canada and the northeast United States. By the end of the natural gas withdrawal season, an increase of over 400 billion cubic feet had been taken out of natural gas storage compared to the previous withdrawal season. Natural gas in storage in the United States had been drawn down below five year average levels, a key measure of supply.

In the second quarter, LNG imports to the United States continued to remain below the historical average, also well below the record injections in the spring of 2007, as world prices for natural gas provided greater economic returns to offshore LNG producers than the U.S. market prices. The continuing increase in crude oil prices through to the end of the second quarter also had a positive effect on the rise in natural gas prices reaching a high of $11.77 per mcf for AECO near the end of the second quarter.

In the third quarter, the collapse of all commodity prices began on the heels of financial and economic turmoil in the credit and capital markets. More specifically in the case of natural gas, hurricane activity in the Gulf of Mexico was minimal, domestic U.S. natural gas production continued to grow thereby increasing storage levels and summer temperatures were moderate resulting in lower demand for the generation of electricity through natural-gas fired power plants to operate air conditioners. During the third quarter, the AECO average daily spot price ranged from a high of $11.83 per mcf early in the quarter to a low of $5.79 per mcf at the end of the third quarter.

In the fourth quarter of 2008, natural gas prices rose from the lows in the third quarter and were between $6.00 and $7.00 per mcf until the end of the year. Prices were stabilizing in anticipation of normal withdrawals of natural gas from storage to meet winter heating demand. The U.S. Midwest and Central Canada were experiencing continuous cold weather resulting in reasonable winter heating demand. However, the U.S. Northeast, representing the largest proportion of winter heating demand, experienced above average temperatures and industrial demand was also less than normal due to the economic uncertainty. AECO averaged $6.70 per mcf in the fourth quarter but has been on a steady decline since the end of the year.

For internal forecasting purposes, Delphi is expecting a volatile natural gas market in 2009 and anticipates AECO to average between $4.25 and $5.50 per mcf. Delphi continues to monitor the variables affecting the price of natural gas in order to ensure its capital program is in line with expected funds flow from operations.

Crude Oil

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

2008 began as another excellent year for crude oil prices which continued to increase, reaching over U.S. $100.00 per barrel by the end of the first quarter, on continued strong global demand, production disruptions, never ending geopolitical unrest in major producing regions and the devaluation of the U.S. dollar. The outlook for the price of oil was bullish despite its lofty heights.

The second quarter of 2008 maintained the momentum for crude oil prices which continued to increase, approaching U.S. $145.00 per barrel late in the second quarter, for the same reasons as in the previous quarter. The outlook for oil remained strong despite growing concerns over the U.S. and global economies.

Through the third and fourth quarters of 2008 the price for crude oil suffered its free fall as the U.S. banking system imploded and the prospects of a global recession gripped the world, significantly reducing demand for all commodities other than gold. Crude oil experienced a low of U.S. $33.87 on December 19, 2008, a drop of 77 percent from the high in July of U.S. $145.29 per barrel. WTI averaged U.S. $99.65 per barrel for the year and U.S. $58.73 per barrel for the three months ended December 31, 2008. For the year, the average WTI price was 38 percent higher than in 2007 but in the fourth quarter, WTI was 35 percent lower than the comparative quarter in 2007.

For Canadian producers the realized price of light crude oil for most of the year was very similar to the price of West Texas Intermediate due to the Canadian dollar remaining around parity with the U.S. dollar. In the fourth quarter of 2008, however, the value of the Canadian dollar decreased against its U.S. counterpart as the demand for the United States dollar rose significantly as investors viewed the U.S. dollar as a relatively low-risk investment (safe haven) during these uncertain times. This positive effect to the price of oil for Canadian producers was partially offset by a widening basis differential between U.S. and Canadian markets.

Prices for heavy oil and other lesser quality crude oils trade at a discount or differential to light crude oil due to the additional costs involved in the refining process. The average differential in 2008 was $17.76 per barrel compared to $22.83 per barrel in 2007. The decrease in the average differential and higher light oil prices, resulted in Bow River crude prices averaging $84.40 per barrel compared to $53.52 per barrel in 2007.

For internal forecasting purposes, Delphi anticipates WTI to average between U.S. $40.00 to $60.00 per barrel for 2009 with the Canadian dollar to remain between $1.15 and $1.30 per U.S. dollar.

Industry Cost of Services

For oil and natural gas producers, lower costs of oilfield services were experienced throughout 2008. The drop in commodity prices in the latter half of the year in combination with the New Royalty Framework effective January 1, 2009 have had a significant negative effect on cash flow available for capital programs and hence drilling and field activity. Drilling contractors and oilfield service companies have had to reduce the rates charged for equipment and labour in order to remain competitive. The overall uncertainty in the credit and capital markets has also led to reduced demand for oilfield services and equipment heading into the winter drilling season.

FINANCIAL STRATEGY

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

Delphi has a strategy of hedging approximately 40 to 50 percent of its natural gas production as long as demand/supply fundamentals indicate volatile markets in the future. Currently, Delphi has hedged approximately 50 percent of its before-royalty natural gas production at a predominantly AECO based average floor price of $7.42 per mcf for 2009. This compares to the current forward 2009 strip commodity price for AECO of $4.54 per mcf. The following natural gas hedges are in place to support the Company's cash flow.



Jan-Mar Apr-Oct Nov-Mar Apr-Dec
2009 2009 2009/2010 2010 2009 2010
----------------------------------------------------------------------------
Production hedged (mmcf/d) 15.8 19.0 13.1 6.6 17.9 7.6
Percentage of
production(1) 44% 53% 36% 18% 50% 21%
Price floor (Cdn $/mcf) $7.66 $7.38 $7.51 $6.39 $7.42 $6.88
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(1) based on 36 mmcf/d


The fair value of the outstanding hedges is estimated to be approximately $13.2 million as of March 5, 2009.

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

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

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

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

Delphi continues to be focused on reducing its leverage and improving its financial flexibility through net debt reduction or increasing funds flow growth resulting in a lower net debt to annualized quarterly funds from operations ratio. The Company continues to be focused on achieving its internal target range for this ratio of 1.3 to 1.5 times. In a low price environment, the Company's objective would be to reduce or at least maintain the net debt balance by undertaking a capital program within cash flow.



SELECTED INFORMATION

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

Dec. Sept. Jun. Mar. Dec. Sept. Jun. Mar.
31 30 30 31 31 30 30 31
2008 2008 2008 2008 2007 2007 2007 2007
----------------------------------------------------------------------------
Production
Natural gas
(mcf/d) 35,545 33,691 31,898 31,777 30,610 28,196 26,967 21,658
Oil (bbl/d) 431 372 368 387 346 579 423 366
Natural gas
liquids (bbl/d) 353 421 517 372 420 422 461 346
----------------------------------------------------------------------------
Barrels of oil
equivalent
(boe/d) 6,708 6,409 6,202 6,056 5,868 5,700 5,379 4,322
Financial
($ thousands
except per unit
amounts)
Petroleum and
natural gas
revenue 30,160 34,461 38,569 32,212 26,632 24,548 24,779 21,974
Funds from
operations 13,473 18,160 19,965 17,059 13,747 12,600 11,469 10,665
Per share
- basic 0.18 0.24 0.29 0.25 0.20 0.19 0.17 0.17
Per share
- diluted 0.18 0.23 0.28 0.25 0.20 0.18 0.17 0.17
Net earnings
(loss) (959) 6,743 49 (739) 1,732 (1,348) 797 (11,653)
Per share
- basic (0.01) 0.09 - (0.01) 0.03 (0.02) 0.01 (0.18)
Per share
- diluted (0.01) 0.09 - (0.01) 0.03 (0.02) 0.01 (0.18)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

Natural gas prices over the past two years have reflected the cyclical nature of demand. Higher prices in the winter months, reflecting demand for heating, weaken through the summer months as production is placed in storage for the upcoming heating season demand. In the first quarter of 2007, net earnings were significantly reduced by the impairment of goodwill in the amount of $12.1 million. Natural gas prices in the second quarter of 2008 did not follow the cyclical trend expected, as prices continued to increase coming out of the winter heating season due to concerns over natural gas supply in storage and the continued increase in crude oil prices. In 2008, the Company achieved record funds flow of $68.7 million or $0.94 per basic share due to continued production growth and increased natural gas and crude oil prices.



2008 2007 2006
----------------------------------------------------------------------------
Revenue 135,402 97,933 94,189
Net earnings/(loss) 5,094 (10,472) 6,903
Total assets 364,538 311,740 326,668
Bank debt plus working capital 109,237 100,658 118,178
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The increase in revenue from 2007 to 2008 was due to production increasing from 5,323 boe/d to 6,345 boe/d as well as high realized prices in the second and third quarters of 2008. The change in net earnings (loss) from 2006 to 2007 was primarily due to the impairment of goodwill recorded in March 2007. The increase in total assets from 2007 to 2008 relates partly to the Peace River Arch acquisition undertaken in July 2008, as well as a successful 2008 capital program.



DRILLING RESULTS

Three Months Ended Twelve Months Ended
December 31, 2008 December 31, 2008
Gross Net Gross Net
----------------------------------------------------------------------------
Natural gas wells 3.0 2.5 20.0 14.6
Oil wells - - 2.0 2.0
Dry holes - - 1.0 0.1
----------------------------------------------------------------------------
Total wells 3.0 2.5 23.0 16.7
Success rate (%) 100 100 96 99
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company had another successful year with the drill bit resulting in a
drilling success rate of 96 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
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Land 612 (26) - 742 204 264
Seismic 44 (30) - 766 407 88
Drilling and completions 9,282 13,188 (30) 53,672 38,417 40
Equipping and facilities 4,725 3,693 28 17,572 10,635 65
Capitalized expenses 839 578 45 3,273 2,261 45
Other 158 (412) - 754 - 100
----------------------------------------------------------------------------
Capital invested 15,660 16,991 (8) 76,779 51,924 48
Disposition of properties - - - (8,450) (15,502) (45)
----------------------------------------------------------------------------
Net capital invested 15,660 16,991 (8) 68,329 36,422 88
Acquisition of properties 174 - 100 38,120 10,871 251
----------------------------------------------------------------------------
Total capital 15,834 16,991 (7) 106,449 47,293 125
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In 2008, Delphi's net capital expenditure program was $106.4 million, an increase of 125 percent over 2007 due to an increase in drilling and completions, facility upgrades completed in core areas and the Peace River Arch acquisition which closed mid 2008. The net field capital program of $68.3 million was funded entirely from internally generated cash flow, consistent with prior years and the Company's strategy. Approximately 71 percent of capital invested in 2008 was directed at drilling and completions to increase the Company's production and reserve base.



PRODUCTION

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Natural gas (mcf/d) 35,545 30,610 16 33,236 26,886 24
Crude oil (bbls/d) 431 346 25 390 429 (9)
Natural gas liquids (bbls/d) 353 420 (16) 416 413 1
----------------------------------------------------------------------------
Total (boe/d) 6,708 5,868 14 6,345 5,323 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production for the twelve months ended December 31, 2008 averaged 6,345 boe/d representing an increase of 19 percent over the comparative period primarily due to the successful drilling and optimization programs at Bigstone and Hythe and the closing of the acquisition in the Peace River Arch area by the end of July, 2008. Delphi continues to achieve steady growth and delivered its seventh consecutive quarter of production growth in the fourth quarter of 2008. The Bigstone and Hythe areas continue to lead the way in production and growth contributing 63 percent of Delphi's fourth quarter volumes. Production at Hythe, Alberta has grown from 400 boe/d at the time of acquisition in September 2007 to over 1,600 boe/d. A significant undeveloped land base, multi-zone potential and the successful application of emerging technologies continue to provide material growth opportunities in existing and new play concepts. The Company's production portfolio for the year was weighted 87 percent to natural gas, six percent to crude oil and seven percent to natural gas liquids. Production for the three months ended December 31, 2008 increased to 6,708 boe/d, 14 percent higher than the comparative period.

Natural gas volumes increased to 33.2 mmcf/d in 2008, representing a 24 percent increase over 2007. Fourth quarter production of natural gas in 2008 was 16 percent greater than the prior year. The increase in natural gas volumes for the quarter and the year were largely as a result of the growth in production volumes at Hythe, Alberta.

Crude oil production for 2008 was nine percent less than the previous year, primarily due to a minor disposition during the year and natural production declines. For the fourth quarter of 2008, crude oil production was 25 percent higher than the comparative period due to oil discoveries at Hythe and Bigstone through the year. Natural gas liquids production remained unchanged from the previous year despite the growth in natural gas production, primarily as a result of increased natural gas production at Hythe, which has a lower liquids-rich content.



REALIZED SALES PRICES
Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
AECO ($/mcf) 6.70 6.15 9 8.16 6.44 27
Heating content and marketing
($/mcf) 0.83 0.40 108 0.59 0.51 16
Gain (loss) on physical
contracts ($/mcf) 0.50 0.80 (38) (0.01) 0.95 -
Gain (loss) on financial
contracts ($/mcf) 0.11 0.26 (58) 0.02 0.15 (87)
----------------------------------------------------------------------------
Realized natural gas price
($/mcf) 8.14 7.61 7 8.76 8.05 9

Realized oil price ($/bbl) 54.55 71.10 (23) 89.88 61.28 47

Realized natural gas liquids
price ($/bbl) 28.11 76.03 (63) 80.49 62.28 29
----------------------------------------------------------------------------
Total realized sales price
($/boe) 48.87 49.33 (1) 58.31 50.41 16
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and twelve months ended December 31, 2008, Delphi's risk management program realized a gain of $2.0 million and $0.1 million, respectively. For the fourth quarter, the realized gain was $0.61 per mcf with physical contracts contributing a gain of $0.50 per mcf and financial contracts contributing a gain of $0.11 per mcf. For the year ended December 31, 2008, the average realized natural gas price was nine percent higher than 2007. This increase was primarily due to the heating content of the Company's natural gas and marketing arrangements.

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

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



Dec. Sept. Jun. Mar. Dec. Sept. Jun. Mar.
31 30 30 31 31 30 30 31
2008 2008 2008 2008 2007 2007 2007 2007
----------------------------------------------------------------------------
Natural Gas Price
Delphi realized
($/mcf) 8.14 8.28 9.77 8.91 7.61 7.20 8.20 9.61
AECO average
($/mcf) 6.70 7.73 10.22 7.97 6.15 5.14 7.06 7.40
Premium(discount)
to AECO 21% 7% (4%) 12% 24% 40% 16% 30%
Hedging gain
(loss) ($000's) 1,985 (67) (3,153) 1,371 2,996 3,875 1,130 2,780
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

The average realized price per boe increased 16 percent to $58.31 per boe in 2008 as compared to $50.41 per boe in the previous year. The average realized price per boe for the fourth quarter was virtually unchanged from the comparative period.

RISK MANAGEMENT ACTIVITIES

Delphi enters into both financial and physical commodity contracts as part of its risk management program to manage commodity price fluctuations designed to ensure sufficient cash is generated to fund its capital program particularly when commodity prices are extremely volatile. Delphi makes a concerted effort to hedge production volumes at prices greater than the upper limit of the historical three to five year AECO price range of $5.25 to $8.40 per mcf and is quick to react to price aberrations such as those experienced at the end of 2005 and the summer of 2008. Another component of the risk management program is to layer in contracts over a period of time, as opposed to locking in a significant portion of volumes at any one point in time, to take advantage of unexpected price spikes. For natural gas production, Delphi has hedged approximately 50 percent of its before-royalty natural gas production at a predominately AECO based average floor price of $7.42 per mcf for 2009.

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

The Company recognized an unrealized non-cash gain on risk management activities for the year ended December 31, 2008 of $0.6 million and an unrealized non-cash gain of $0.6 million on financial contracts in the fourth quarter of 2008. The fair values of these contracts are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the contracts outstanding at the end of the period having regard to forward prices and market values provided by independent sources. Due to the inherent volatility in commodity prices, actual amounts realized may differ from these estimates.

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



Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
April 2008 -
March 2009 Natural Gas Physical 2,000 GJ/d $7.30 fixed
November 2008 -
March 2009 Natural Gas Physical 4,000 GJ/d $7.46 fixed
November 2008 -
March 2009 Natural Gas Financial 2,000 GJ/d $7.62 fixed
November 2008 -
March 2009 Natural Gas Physical 2,000 GJ/d $7.00 floor/
$8.05 ceiling
November 2008 -
March 2009 Natural Gas Physical 2,000 mmbtu/d U.S. $9.00 fixed
November 2008 -
March 2009 Natural Gas Financial 1,000 GJ/d $8.00 floor/
$11.07 ceiling
April 2009 -
October 2009 Natural Gas Physical 1,000 GJ/d $7.08 fixed
April 2009 -
October 2009 Natural Gas Physical 2,000 GJ/d $8.25 floor/
$10.00 ceiling
April 2009 -
October 2009 Natural Gas Physical 1,000 mmbtu/d U.S. $8.18 fixed
April 2009 -
October 2009 Natural Gas Physical 2,000 GJ/d $8.59 fixed
April 2009 -
October 2009 Natural Gas Physical 2,000 GJ/d $6.70 floor plus
50% greater than $6.70
April 2009 -
March 2010 Natural Gas Physical 3,000 GJ/d $7.52 fixed
April 2009 -
March 2010 Natural Gas Physical 2,000 GJ/d $6.80 floor plus
50% greater than $6.80
November 2009 -
March 2010 Natural Gas Physical 2,000 GJ/d $7.75 floor/
$8.70 ceiling
November 2009 -
March 2010 Natural Gas Physical 2,000 GJ/d $7.26 floor plus
50% greater than $7.26
November 2009 -
March 2010 Natural Gas Physical 2,000 GJ/d $7.65 floor plus
50% greater than $7.65
April 2010 -
December 2010 Natural Gas Physical 3,000 GJ/d $6.25 floor/
$7.47 ceiling
April 2010 -
December 2010 Natural Gas Physical 4,000 GJ/d $5.93 floor plus
50% greater than $5.93
February 2009 -
December
2009(i) Natural Gas Financial 3,500 GJ/d $6.00 Put
March 2009 -
December
2009(i) Natural Gas Physical 3,500 GJ/d $6.00 Put
January 2010 -
December
2010(i) Natural Gas Financial 3,500 GJ/d $7.40 Call
January 2010 -
December
2010(i) Natural Gas Physical 3,500 GJ/d $7.15 Call
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) The Company has acquired two natural gas put contracts at $6.00 per
gigajoule on 3,500 gigajoules per day each for the periods February 1,
2009 through December 31, 2009, and March 1, 2009 through December 31,
2009, respectively. These puts were paid for with the sale of natural
gas calls on 7,000 gigajoules per day at an average price of $7.28 per
gigajoule for the period January 1, 2010 through December 31, 2010.


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



REVENUE
Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Natural gas (including
physical hedges) 26,623 20,696 29 106,284 77,495 37
Crude oil 2,163 2,263 (4) 12,830 9,596 34
Natural gas liquids 913 2,769 (67) 12,255 9,168 34
Sulphur 93 169 (45) 3,755 220 1,607
Realized gain on risk
management 368 735 (50) 278 1,454 (81)
----------------------------------------------------------------------------
Total 30,160 26,632 13 135,402 97,933 38
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The 38 percent increase in revenue for the twelve months ended December 31, 2008, over the comparative period, is attributed to the 19 percent increase in production volumes and the 16 percent increase in realized sales price per boe. For the three months ended December 31, 2008, revenue increased 13 percent over the comparative period due to a 14 percent increase in production volumes and a one percent decrease in the realized sales price per boe. During 2008, sulphur prices soared as demand for fertilizers increased around the world. Delphi received $3.8 million from the sale of sulphur during the year, primarily associated with production at its Tower Creek well. As a result of the slowing economies around the world, sulphur prices have fallen significantly resulting in sales of only $0.1 million in the fourth quarter despite ongoing production at Tower Creek.



ROYALTIES

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Total 5,267 4,092 29 25,827 14,580 77
Per boe 8.53 7.58 13 11.12 7.50 48
Percent of revenue
including realized hedges 17.5 15.4 14 19.1 14.9 28
Percent of revenue excluding
realized hedges 18.7 17.4 7 19.1 15.1 26
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company pays royalties to provincial governments (Crown), freeholders, which can be individuals or companies, and other oil and gas operators that own surface or mineral rights. Crown royalty rates are calculated on a sliding scale based on commodity prices and individual well production rates. Royalty rates can change due to price fluctuations or changes in production volumes on a well by well basis subject to a minimum and maximum rate restriction ascribed by the Crown. For the three months and year ended December 31 2008, royalties as a percentage of revenue increased over the comparative period due to Tower Creek being off royalty holiday, significant hedge gains in the comparative period on which no royalties were paid and increased commodity prices realized in 2008. Delphi is expecting royalties as a percentage of revenue, before hedging, to be between 17 and 20 percent in 2009.

On October 25, 2007, the Government of Alberta announced the New Royalty Framework (NRF). The NRF established new royalties for oil and natural gas which are based on commodity prices, well production volumes and well depths for natural gas wells. The NRF rates apply to both new and existing production and became effective on January 1, 2009. On March 3, 2009, the Alberta Government announced royalty incentives to promote oilfield activity in light of the current economic environment. The calculated affect to Delphi on a typical well drilled in Hythe or Bigstone is estimated to be approximately $0.9 million, material to both project economics and the Company's cash flow.



OPERATING EXPENSES

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Total 6,585 4,477 47 24,092 17,464 38
Per boe 10.67 8.29 29 10.37 8.99 15
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Operating expenses on a per boe basis for the twelve months ended December 31, 2008, increased 15 percent over the comparative period due to a high level of workover and maintenance activity and the increase in industry costs experienced throughout most of 2008. In addition, earlier in the year the Company incurred significant cost adjustments for the prior year from the facility operator on the newly acquired Hythe property. Operating expenses on a per boe basis for the three months ended December 31, 2008, increased 29 percent over the comparative period due to higher costs of fuel and power and contract operating fees primarily associated with the acquisition of properties and facilities in the Peace River Arch acquisition.

Delphi is focused on cost reduction and anticipates lower 2009 operating costs per boe as volumes increase at core areas and the industry experiences an expected reduction in field costs. Delphi expects operating costs to be $9.75 to $10.25 per boe in 2009.



TRANSPORTATION EXPENSES

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Total 2,320 1,387 67 6,944 6,148 13
Per boe 3.76 2.57 46 2.99 3.16 (5)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 twelve months ended December 31, 2008 decreased by five percent over the comparative period due to higher production volumes with fixed firm service fees for production and lower transportation costs at Hythe, Alberta. Effective November 1, 2007 and again on November 1, 2008, Delphi transferred a portion of its excess processing and transmission capacity in northeast British Columbia to third parties resulting in further reductions in transportation costs.

For the three months ended December 31, 2008, transportation costs on a per boe basis increased 46 percent over the same period in 2007. This increase is primarily attributed to a one time payment in the quarter of approximately $0.6 million ($1.04 per boe for the fourth quarter and $0.28 per boe for the year) to transfer excess processing and transmission capacity to a third party. The transfer will save approximately $2.7 million in transportation costs over the next three years and will result in lower transportation costs on a go forward basis. Delphi expects transportation costs to be between $2.50 and $2.75 per boe in 2009.



GENERAL AND ADMINISTRATIVE

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
General and administrative
costs 2,377 2,319 3 9,352 6,957 34
Overhead recoveries (291) (196) 48 (1,173) (711) 65
Salary allocations (636) (688) (8) (3,400) (2,550) 33
----------------------------------------------------------------------------
Net 1,450 1,435 1 4,779 3,696 29
Per boe 2.35 2.66 (12) 2.06 1.90 8
----------------------------------------------------------------------------


On a per boe basis, general and administrative (G&A) costs for the twelve months ended December 31, 2008 increased eight percent over the comparative period in 2007. The increase is due to additional technical staff hired year over year and additional rental expense for office space. 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 delivering strong growth and believes a strong technical team is paramount to achieve this goal. Delphi expanded its team in 2008 with the addition of two senior exploitation engineers and a new land manager. For 2009, Delphi is expecting G&A per boe to be approximately the same as in 2008.



STOCK-BASED COMPENSATION

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Stock-based compensation 314 1,105 (72) 2,114 2,649 (20)
Capitalized costs (55) (553) (90) (1,120) (1,352) (17)
----------------------------------------------------------------------------
Net 259 552 (53) 994 1,297 (23)
Per boe 0.42 1.02 (59) 0.43 0.67 (36)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees, directors and key consultants of the Company. The fair value of all options granted is estimated at the date of grant using the Black-Scholes option pricing model. The non-cash compensation expense for the twelve months ended December 31, 2008, decreased 23 percent. During the three and twelve months ended December 31, 2008, Delphi capitalized $0.1 million and $1.1 million, respectively, of stock-based compensation associated with exploration and development activities.



INTEREST

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Total 1,065 1,491 (29) 5,103 7,561 (33)
Per boe 1.73 2.76 (38) 2.20 3.89 (44)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and twelve months ended December 31, 2008, interest expense on a per boe basis decreased 38 percent and 44 percent over the comparable periods due to lower interest costs from reduced interest rates and higher production volumes. Delphi anticipates interest per boe will continue to decrease in 2009 as average debt levels remain relatively consistent with the prior year, interest rates continue to decline to generate economic growth and additional production is brought on stream. The reduction in interest costs as a result of lower interest rates is expected to be, at least partially, offset by an increase in the Company's credit spread associated with its credit facilities due to the increased cost of funds being incurred by the Company's lenders.



DEPLETION, DEPRECIATION AND ACCRETION

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Depletion and depreciation 15,333 13,960 10 61,095 48,962 25
Accretion expense 200 185 8 650 638 2
----------------------------------------------------------------------------
Total 15,533 14,145 10 61,745 49,600 24
Per boe 25.17 26.20 (4) 26.59 25.53 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Depletion, depreciation, and accretion per boe for the twelve months ended December 31, 2008 increased four percent. With continued success at Bigstone and Hythe, Delphi is in an excellent position to add proved reserves at metrics below the Company's current depletion rate. The Company experienced a decrease in depletion per boe during the fourth quarter of 2008 due to significant reserve additions being recognized in the quarter upon completion of the 2008 engineering report. 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 interest 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, 2008 remained consistent with the comparative year.



TAXES

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Current - 3 - - 3 -
Future (reduction) (798) (3,608) (78) 1,432 (3,279) -
----------------------------------------------------------------------------
Total (798) (3,605) (78) 1,432 (3,276) -
Effective rate
Per boe (1.29) (6.68) (81) 0.62 (1.69) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The provision for income taxes in the financial statements for the twelve months ended December 31, 2008, was $1.4 million. The significant change in taxes is due to an improvement in earnings before taxes. Delphi does not anticipate it will be cash taxable before 2011.



FUNDS FROM OPERATIONS

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Net earnings (loss) (959) 1,732 - 5,094 (10,472) -
Non-cash items:
Depletion, depreciation
and accretion 15,533 14,145 10 61,745 49,600 24
Impairment of goodwill - - - - 12,100 (100)
Unrealized loss on risk
management activities (562) 926 - (608) (765) (21)
Stock-based compensation
expense 259 552 (53) 994 1,297 (23)
Future income taxes
(reduction) (798) (3,608) (78) 1,432 (3,279) -
----------------------------------------------------------------------------
Funds from operations 13,473 13,747 (2) 68,657 48,481 42
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and twelve months ended December 31, 2008, funds from operations were $13.5 million ($0.18 per basic share) and $68.7 million ($0.94 per basic share) compared to $13.7 million ($0.20 per basic share) and $48.5 million ($0.72 per basic share) in the comparative period.

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



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

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Funds from operations:
Non-GAAP 13,473 13,747 (2) 68,657 48,481 42
Settlement of asset
retirement obligations (312) (93) 235 (312) (550) (43)
Change in non-cash working
capital 5,646 7,040 (20) (5,022) 6,777 -
----------------------------------------------------------------------------
Cash flow from operating
activities: GAAP 18,807 20,694 (9) 63,323 54,708 16
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NET EARNINGS

For the three and twelve months ended December 31, 2008, Delphi recorded a net loss of $1.0 million and net earnings of $5.0 million, respectively. Net earnings were affected by non-cash items such as depletion, depreciation and accretion, unrealized gain or loss on risk management activities, stock-based compensation and future income taxes. These non-cash items represent the majority of the significant difference between funds from operations and net earnings.



NETBACK ANALYSIS

Three Months Ended Twelve Months Ended
December 31 December 31
% %
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Barrels of oil equivalent
($/boe)
Realized sales price 48.87 49.33 (1) 58.31 50.41 16
Royalties, net of ARTC 8.53 7.58 13 11.12 7.50 48
Operating expenses 10.67 8.29 29 10.37 8.99 15
Transportation 3.76 2.57 46 2.99 3.16 (5)
----------------------------------------------------------------------------
Operating netback 25.91 30.89 (16) 33.83 30.76 10
G&A 2.35 2.66 (12) 2.06 1.90 8
Interest 1.73 2.76 (38) 2.20 3.89 (44)
Current taxes - 0.01 - - - -
----------------------------------------------------------------------------
Cash netback 21.83 25.46 (14) 29.57 24.97 18
Unrealized loss (gain) on
financial contracts (0.91) 1.72 - (0.26) (0.39) (33)
Stock-based compensation
expense 0.42 1.02 (59) 0.43 0.67 (36)
Depletion, depreciation and
accretion 25.17 26.20 (4) 26.59 25.53 4
Impairment of goodwill - - - - 6.23 (100)
Future income taxes
(reduction) (1.29) (6.68) (81) 0.62 (1.69) -
----------------------------------------------------------------------------
Net earnings (loss) (1.56) 3.20 - 2.19 (5.38) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

LIQUIDITY AND CAPITAL RESOURCES

Funding

Three Months Ended Twelve Months Ended
December 31, 2008 December 31, 2008
----------------------------------------------------------------------------
Sources:
Funds from operations 13,473 68,657
Disposition of petroleum and
natural gas properties - 8,450
Issue of common shares - 18,001
Issue of flow-through common shares - 12,002
Exercise of stock options - 1,532
Change in non-cash working capital 2,590 4,461
----------------------------------------------------------------------------
16,063 113,103

Uses:
Cash and cash equivalents 1,286 5,282
Share issue costs 32 2,010
Capital expenditures 15,660 76,779
Acquisition of petroleum and natural
gas properties 173 38,120
Expenditures on asset retirement obligations 312 312
----------------------------------------------------------------------------
17,463 122,503

----------------------------------------------------------------------------
Increase in bank debt 1,400 9,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the year ended December 31, 2008 Delphi funded its capital program through a combination of funds from operations, the issuance of common shares, the issuance of flow-through common shares and an increase in its bank debt.

Share Capital

At December 31, 2008, the Company had 79.1 million common shares outstanding (December 31, 2007 - 68.1 million). The common shares of Delphi trade on the TSX under the symbol DEE. The following table summarizes outstanding share data for the three and twelve months ended December 31, 2008.



Three Months Ended Twelve Months Ended
December 31, 2008 December 31, 2008
----------------------------------------------------------------------------
Weighted Average Common Shares
Basic 79,067 73,381
Diluted 79,068 74,024
Trading Statistics (1)
High $ 1.67 $ 3.43
Low $ 0.79 $ 0.79
Average daily, volume 430,637 282,945
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Trading statistics based on closing price


As at March 17, 2009, the Company had 79.1 million common shares outstanding and 6.8 milllion stock options outstanding.

Bank Debt plus Working Capital Deficiency

At December 31, 2008, the Company had $91.4 million outstanding on its credit facility and a working capital deficiency of $17.8 million for total debt plus working capital deficiency of $109.2 million excluding the financial asset of $1.7 million relating to the unrealized gain on financial commodity contracts and the current future income tax liability of $0.5 million. Delphi anticipates spending less than projected funds from operations on capital expenditures during 2009.

The capital intensive nature of the industry will generally result in the Company having a working capital deficiency. As at March 17, 2009, the Company has a revolving facility for $130.0 million with a syndicate of Canadian chartered banks. The facility is a 364 day committed revolving facility which is available until May 31, 2009, the term-out date. The term-out date may be extended for an additional 364 days upon approval by the banks. Following the term-out date, the facilities would become non-revolving for a one year term, after which time the balance outstanding would be due and payable. 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 plus 0.5 percent to a maximum of the bank's prime rate plus 2.0 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 0.75 percent higher than the revolving term facility.

The current credit facilities were confirmed by the Company's lenders upon completion of their semi-annual review in October, 2008. The annual credit review by the Company's lenders is expected to be completed by May 31, 2009. This detailed review will be based upon the Company's December 31, 2008 reserves engineering report and will take into consideration current production and the results of the winter drilling program. The borrowing base is determined using the Company's year-end engineering report, primarily proved producing reserves, which increased 21 percent over the previous year and the outlook for commodity prices.

Contractual Obligations

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



The future minimum commitments are as follows:

2009 2010 2011 2012 2013
----------------------------------------------------------------------------
Gathering, processing and
transmission 3,484 4,173 3,868 2,833 1,845
Office and equipment lease 1,018 1,023 1,029 775 390
----------------------------------------------------------------------------
Total 4,492 5,196 4,897 3,608 2,235
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 control systems and comparing past estimates to actual results.

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

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

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

- Capital expenditures on projects that are in progress;

- Fair value of derivative contracts;

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

NEW ACCOUNTING STANDARDS

Financial Instruments - Disclosure

Effective January 1, 2008 the Company adopted CICA section 3862 - Financial Instruments - Disclosure which requires additional disclosure about the Company's financial instruments to be included in the financial statements. The recommendations prescribe an increased importance on risk disclosures associated with recognized and unrecognized financial instruments and how such risks are managed. In addition, the recommendations outline revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial instruments. These additional disclosures are included in Note 9 of the Company's audited 2008 annual consolidated financial statements.

Details of the Company's accounting policies for the recognition and measurement of financial instruments and the basis for which revenues and expenses are recognized are disclosed in Note 2 of the Company's audited 2008 annual consolidated financial statements.

Capital Management

Effective December 31, 2007, the Company adopted new disclosure standards with respect to capital management.

International Financial Reporting Standards (IFRS)

In February 2008, the Accounting Standards Board of the Canadian Institute of Chartered Accountants confirmed that IFRS will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises. Effective January 1, 2011, the Company will be required to prepare its consolidated financial statements in accordance with International Financial Reporting Standards (IFRS), with appropriate comparative figures for the year ended December 31, 2010.

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

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

CORPORATE GOVERNANCE

Overview

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

Disclosure Controls and Procedures and Internal Controls over Financial Reporting

Disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the issuer's management, including its President and Chief Executive Officer and Vice President, Finance and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Company's President and Chief Executive Officer and Vice President, Finance and Chief Financial Officer have concluded, based on their evaluation as of December 31, 2008 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.

An evaluation and testing was performed under the direction of the President and Chief Executive Officer and the Vice President, Finance and Chief Financial Officer, of the effectiveness of the Company's internal controls over financial reporting as defined in the Multilateral Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings. The assessment was based on the Internal Controls - Integrated Framework issued by the Committee of Sponsoring Organizations. Based on that evaluation, the President and Chief Executive Officer and the Vice President, Finance and Chief Financial Officer have concluded that the design and operation of the Company's internal controls over financial reporting were effective as at December 31, 2008.

The Company notes that while it believes the disclosure controls and procedures and internal controls over financial reporting provide a reasonable level of assurance that they are effective, it does not expect that the disclosure controls and procedures and internal controls will prevent all errors and fraud. A control system is designed to provide reasonable, not absolute, assurance that the objectives of the control system are met.

2009 OUTLOOK

Corporate Strategy

Delphi emphasizes a full-cycle approach to its business and strives for internally generated development opportunities as a means of enhancing its production base and ultimately creating value for shareholders. Delphi's goal is to become a dominant natural gas developer and explorer focused in northwest Alberta and northeast British Columbia. The objective is to develop an inventory of opportunities and undeveloped land base from which production and reserves can be added independent of acquisition activity. In that regard, the Company's ability to add production through the drill bit creates a competitive advantage over those competitors that rely on acquisitions to build or maintain their production base. Currently, Delphi has identified over one hundred drilling locations, 3 to 5 years drilling inventory, on its core areas.

Capital Activities

With the current uncertainty in commodity prices and the economy, Delphi will fund its capital program from internally generated cash flow from operations. Delphi's Board of Directors have approved a capital program ranging between $17.0 to $22.0 million for the first half of 2009, with the objective of preserving the Company's financial flexibility in these uncertain economic times and maintaining the flexibility to pursue and capture strategic growth opportunities attractively priced in this environment. A larger capital program for the second half of the year is expected, however, that will be dependent upon commodity price expectations at that time. Total capital for the year is expected to be between $35.0 to $50.0 million.

The capital program for the first six months of the year includes the drilling of four (3.75 net) wells with the majority of the capital allocated to the Company's two main areas, Bigstone and Hythe including the drilling of a horizontal well at Hythe utilizing multistage fracturing techniques to enhance production and reserves.

Financial Strategy

The Company is well positioned to endure the current weak economic environment with high quality producing assets, a large inventory of economic projects and a 2009 cash flow stream protected with 50 percent of the Company's current natural gas production hedged at an average floor price 64 percent greater than the current 2009 strip price. Net debt at the end of 2008 is approximately $109.2 million on total credit facilities of $140.0 million, providing excess financial capacity of approximately $30.8 million. Delphi expects to maintain or slightly reduce the net debt by the end of 2009 by spending no more than cash flow from operations. Maintaining operational and financial flexibility, combined with expanding the Company's long-term growth inventory in a low-cost environment, will be key drivers in the capital spending decision process throughout 2009.

ADDITIONAL INFORMATION

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

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

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

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

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

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

AUDITORS' REPORT TO THE SHAREHOLDERS

We have audited the consolidated balance sheets of Delphi Energy Corp. as at December 31, 2008 and 2007 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, 2008 and 2007 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 17, 2009



DELPHI ENERGY CORP.
Consolidated Balance Sheets
As at December 31

(Stated in thousands of dollars) 2008 2007
----------------------------------------------------------------------------
Assets
Current assets
Cash 1,029 5
Accounts receivable 14,522 12,604
Prepaid expenses and deposits 2,928 2,752
Risk management asset (Note 9) 1,721 1,113
----------------------------------------------------------------------------
20,200 16,474

Property, plant and equipment (Note 4) 344,338 295,266
----------------------------------------------------------------------------
Total assets 364,538 311,740
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities
Current liabilities
Outstanding cheques 105 4,363
Future income taxes (Note 8) 501 332
Accounts payable and accrued liabilities 36,211 29,656
----------------------------------------------------------------------------
36,817 34,351

Long term debt (Note 5) 91,400 82,000
Future income taxes (Note 8) 33,655 27,830
Asset retirement obligations (Note 6) 9,730 7,183
----------------------------------------------------------------------------
171,602 151,364

Shareholders' equity
Share capital (Note 7) 174,995 148,898
Contributed surplus (Note 7) 9,605 8,236
Retained earnings 8,336 3,242
----------------------------------------------------------------------------
Total shareholders' equity 192,936 160,376
----------------------------------------------------------------------------
Total liabilities and shareholders' equity 364,538 311,740
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Commitments (Note 10)
See accompanying notes to the consolidated financial statements.

Approved on behalf of the Board of Directors:

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


DELPHI ENERGY CORP.
Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss) and
Retained Earnings
Years ended December 31

(Stated in thousands of dollars, except per
share amounts) 2008 2007
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales 135,124 96,479
Realized gain on risk management activities
(Note 9) 278 1,454
----------------------------------------------------------------------------
135,402 97,933
Royalties (25,827) (14,580)
Unrealized gain on risk management activities
(Note 9) 608 765
----------------------------------------------------------------------------
110,183 84,118

Expenses
Operating 24,092 17,464
Transportation 6,944 6,148
General and administrative 4,779 3,696
Stock-based compensation (Note 7) 994 1,297
Interest 5,103 7,561
Depletion, depreciation and accretion 61,745 49,600
Impairment of goodwill - 12,100
----------------------------------------------------------------------------
103,657 97,866
----------------------------------------------------------------------------
Earnings (loss) before income taxes 6,526 (13,748)

Income taxes (Note 8)
Current - 3
Future (reduction) 1,432 (3,279)
----------------------------------------------------------------------------
1,432 (3,276)

----------------------------------------------------------------------------
Net earnings (loss) and comprehensive income (loss) 5,094 (10,472)
Retained earnings, beginning of the year 3,242 13,714
----------------------------------------------------------------------------
Retained earnings, end of the year 8,336 3,242
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Net earnings (loss) per share (Note 7)
Basic and diluted 0.07 (0.16)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


DELPHI ENERGY CORP.
Consolidated Statements of Cash Flows
Years ended December 31

(Stated in thousands of dollars) 2008 2007
----------------------------------------------------------------------------

Cash flow from operating activities
Net earnings (loss) 5,094 (10,472)
Add non-cash items:
Depletion, depreciation and accretion 61,745 49,600
Impairment of goodwill - 12,100
Stock-based compensation 994 1,297
Unrealized gain on risk management activities (608) (765)
Future income taxes (reduction) 1,432 (3,279)
Expenditures on asset retirement obligations (312) (550)
Change in non-cash working capital (Note 11) (5,022) 6,777
----------------------------------------------------------------------------
63,323 54,708
Cash flow from (used in) financing activities
Issue of flow-through common shares 12,002 18,007
Issue of common shares 18,001 -
Share issue costs (2,010) (1,208)
Exercise of stock options 1,532 83
Increase (decrease) in long term debt 9,400 (33,000)
----------------------------------------------------------------------------
38,925 (16,118)

----------------------------------------------------------------------------
Cash flow available for investing activities 102,248 38,590

Cash flow from (used in) investing activities
Capital expenditures (76,779) (51,924)
Acquisition of petroleum and natural gas properties (38,120) (10,871)
Disposition of petroleum and natural gas properties 8,450 15,502
Change in non-cash working capital (Note 11) 9,483 3,588
----------------------------------------------------------------------------
(96,966) (43,705)

----------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents 5,282 (5,115)
Cash and cash equivalents, beginning of the year (4,358) 757
----------------------------------------------------------------------------
Cash and cash equivalents, end of the year 924 (4,358)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash and cash equivalents is comprised of:
Cash 1,029 5
Outstanding cheques (105) (4,363)
----------------------------------------------------------------------------
924 (4,358)
----------------------------------------------------------------------------
Interest paid 5,149 7,087
Taxes paid - 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


DELPHI ENERGY CORP.

Notes to the Consolidated Financial Statements

As at and for the years ended December 31, 2008 and 2007

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

NOTE 1: DESCRIPTION OF BUSINESS

Delphi Energy Corp. ("the Company" or "Delphi") is incorporated under the Business Corporations Act (Alberta) and is a public company listed on the Toronto Stock Exchange. Delphi is primarily engaged in the exploration for and development and production of petroleum and natural gas from properties located in northwest Alberta and northeast 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, liabilities, shareholders' equity, revenue and expenses and disclosure of contingent assets and liabilities at the date of the financial statements. Actual results may differ from these estimates.

(a) Principles of consolidation

The consolidated financial statements include the accounts of the Company, its wholly owned subsidiary and a partnership. All inter-entity transactions and balances 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 percent 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 the Company's independent reserves engineers. 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 percent to 50 percent.

(c) Joint operations

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

(d) Goodwill

Goodwill, at the time of acquisition, represents the excess of the purchase price of a business over the fair value of the 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.

(e) Asset retirement obligations

The Company records the future cost associated with removal, site restoration and asset retirement costs of property, plant and equipment. The fair value of the liability for the Company's asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using the Company's credit adjusted risk-free interest rate and the corresponding amount is recognized by increasing the carrying amount of property, plant and equipment. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Actual costs incurred upon settlement of the retirement obligation are charged against the obligation to the extent of the liability recorded. The associated asset retirement cost included in property, plant and equipment is 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 is 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 an increase to 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 asset and 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 amounts

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

i) Financial instruments - recognition and measurement

Financial instruments are 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 depends on initial classification, as follows: changes in fair value of held-for-trading financial assets are recognized in net earnings and 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.

The Company classifies its cash as held-for-trading which is measured at fair value. Accounts receivable are classified as loans and receivables and are measured at amortized cost. Accounts payable and long term debt are classified as other financial liabilities and are measured at amortized cost.

ii) Derivatives

All derivative instruments, including embedded derivatives, are recorded on the balance sheet at fair value unless exempt from derivative accounting 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 by entering 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. Physical commodity sale contracts based in United States dollars include an embedded derivative associated with the foreign exchange rate. Due to this embedded derivative, the change in the fair value of these contracts are included in the statement of earnings.

iii) Other comprehensive income

The Company includes a 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 statement with the statement of earnings.

iv) Transaction costs

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 property, plant and equipment are based upon estimates of proved petroleum and natural gas reserves, production rates, commodity prices and future costs. The ceiling 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 future costs, expected inflation rates and other assumptions. The amounts for stock-based compensation are based on estimates of risk-free interest rates, expected lives and volatility. The fair value estimates for derivatives are based on expected future natural gas prices and volatility in those prices. Future income taxes are based on estimates as to timing of the reversal of temporary differences at tax rates substantively enacted in those years. 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 less outstanding cheques as cash and cash equivalents.

(m) Revenue recognition

Petroleum and natural gas sales are recognized in earnings when the title and risks pass from the Company to its customer.

(n) Comparative figures

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

NOTE 3: NEW ACCOUNTING STANDARDS

Financial Instruments - Disclosure

Effective January 1, 2008, the Company adopted CICA section 3862 - Financial Instruments - Disclosure which requires additional disclosure about the Company's financial instruments to be included in the financial statements. The recommendations prescribe an increased importance on risk disclosures associated with recognized and unrecognized financial instruments and how such risks are managed. In addition, the recommendations outline revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial instruments. These additional disclosures are included in Note 9.

Capital Management

Effective December 31, 2007, the Company adopted new disclosure standards with respect to capital management.

International Financial Reporting Standards

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



NOTE 4: PROPERTY, PLANT AND EQUIPMENT

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


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


For the year ended December 31, 2008, the Company capitalized $3.3 million (December 31, 2007 - $2.3 million) of general and administrative costs directly related to exploration and development activities.

As at December 31, 2008, costs in the amount of $3.4 million (December 31, 2007 - $10.8 million) representing unproved properties were excluded from the depletion calculation and estimated future development costs of $46.7 million (December 31, 2007 - $15.7 million) have been included in costs subject to depletion. All costs of unproved properties have been capitalized. Ultimate recoverability of these costs will be dependent upon finding proved oil and natural gas reserves.

On July 24, 2008, the Company closed an acquisition of crude oil and natural gas properties in northwest Alberta for total cash consideration of $38.0 million.

The Company performed a ceiling test calculation at December 31, 2008 to assess the recoverable value of property, plant and equipment, which indicated no write down was required. The future commodity prices used in the ceiling test were based on the December 31, 2008 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 ceiling test.



Natural Gas Crude Oil
AECO Delphi West Texas Edmonton Bow River Delphi
Henry Hub Spot Gas Intermediate Light Hardisty Oil
(US$ (CDN$ (CDN$ (US$ (CDN$ (CDN$ (CDN$
/mmbtu) /mmbtu) /mcf) /bbl) /bbl) /bbl) /bbl)
----------------------------------------------------------------------------
2009 7.00 7.58 7.56 57.50 68.61 51.44 56.49
2010 7.50 7.94 7.92 68.00 78.94 59.21 66.33
2011 8.00 8.34 8.32 74.00 83.54 63.49 70.84
2012 8.75 8.70 8.71 85.00 90.92 69.10 77.16
2013 9.20 8.95 8.98 92.01 95.91 72.89 81.12
2014 9.38 9.14 9.20 93.85 97.84 74.36 82.19
2015 9.57 9.34 9.41 95.73 99.82 75.86 83.36
2016 9.76 9.54 9.63 97.64 101.83 77.39 84.56
2017 9.96 9.75 9.85 99.59 103.89 78.96 91.01
2018 10.16 9.95 10.09 101.59 105.99 80.55 97.19
There +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr
after (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NOTE 5: LONG TERM DEBT

The Company has a revolving facility for $130.0 million with a syndicate of Canadian chartered banks. The facility is a 364 day committed revolving facility until May 31, 2009, the term-out date. The term-out date may be extended for a further 364 day period upon approval by the banks. Following the term-out date, the facilities would be available on a non-revolving basis for a one year term. The credit facility bears interest based on a sliding scale tied to the Company's trailing debt to cash flow ratio: from a minimum of the bank's prime rate plus 0.5 percent to a maximum of the bank's prime rate plus 2.0 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 0.75 percent higher than the revolving term facility. As at December 31, 2008, there is no amount drawn under this facility.

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

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 $21.4 million (December 31, 2007 - $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 2008 2007
----------------------------------------------------------------------------
Balance, beginning of the year 7,183 7,951
Liabilities incurred 271 1,017
Liabilities disposed (83) (1,873)
Liabilities acquired 2,021 -
Liabilities settled (312) (550)
Accretion expense 650 638
----------------------------------------------------------------------------
Balance, end of the year 9,730 7,183
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NOTE 7: SHARE CAPITAL

(a) Authorized

An unlimited number of common shares.

An unlimited number of preferred shares issuable in series.

(b) Common shares issued



2008 2007
Outstanding Outstanding
As at December 31 shares (000's) Amount shares (000's) Amount
----------------------------------------------------------------------------
Balance, beginning of the year 68,070 148,898 60,663 139,108
Issue of flow-through common
shares 3,530 12,002 7,350 18,007
Issue of common shares 6,316 18,001 - -
Exercise of stock options 1,151 1,532 57 83
Allocated from contributed
surplus - 745 - 39
Share issue costs - (2,010) - (1,208)
Future tax effect of share
issue costs - 585 - 369
Tax benefit renounced to
shareholders - (4,758) - (7,500)
----------------------------------------------------------------------------
Balance, end of the year 79,067 174,995 68,070 148,898
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

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

The Company has incurred the necessary qualifying exploration expenditures to satisfy the terms of the flow-through common shares issued in 2007. 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 $12.0 million by December 31, 2009 to satisfy the obligation relating to the issuance of flow-through shares in 2008. As at December 31, 2008, the Company had a remaining requirement to incur approximately $4.0 million of qualifying expenditures to fully satisfy this obligation.

(c) Stock options

The Company has established a stock option plan under which it has granted options to acquire common shares to certain officers, directors, employees and key consultants. The plan provides for the granting of options up to ten percent of the issued and outstanding common shares of the Company. Options issued under the plan have a term of five years to expiry and vest over a two-year period starting on the date of the grant. The exercise price of each option equals the 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, 2008 there were 4.7 million options to purchase shares outstanding.

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



2008 2007
Weighted Weighted
Outstanding average Outstanding average
options exercise options exercise
As at December 31 (000's) price (000's) price
----------------------------------------------------------------------------
Balance, beginning of the year 5,481 1.60 4,229 3.40
Granted 615 2.23 4,500 1.67
Cancelled (60) 1.55 (3,070) 4.09
Forfeited (154) 1.56 (121) 3.92
Exercised (1,151) 1.33 (57) 1.45
----------------------------------------------------------------------------
Balance, end of the year 4,731 1.75 5,481 1.60
----------------------------------------------------------------------------
Exercisable at end of the year 2,938 1.72 2,481 1.52
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes information about the stock options
outstanding and exercisable at December 31, 2008.

Options outstanding Options exercisable

Weighted
Weighted average
Outstanding average remaining Weighted
Range of options exercise term Exercisable average
exercise price (000's) price (years) (000's) exercise price
----------------------------------------------------------------------------
$ 0.97 - $1.54 100 1.24 4.3 50 1.33
$ 1.55 - $1.72 3,751 1.67 3.9 2,489 1.67
$ 1.73 - $2.15 660 1.80 3.9 325 1.79
$ 2.16 - $3.34 220 3.18 4.5 74 3.18
----------------------------------------------------------------------------
Total 4,731 1.75 3.9 2,938 1.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(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, 2008, Delphi recorded non-cash compensation expense of $1.0 million (December 31, 2007- $1.3 million). The Company capitalized $1.1 million (December 31, 2007 - $1.3 million) of stock-based compensation directly related to exploration and development activities. The future income tax liability associated with the capitalized stock-based compensation in the amount of $0.4 million (2007 - $0.5 million) has also been capitalized for the year.

During the year ended December 31, 2008, the Company granted 0.6 million options. The fair values of all options granted during the period are estimated at the date of grant using the Black-Scholes option pricing model. The weighted average fair value of options granted during the year was $1.13 per option (2007 - $0.96 per option). The assumptions used in the Black-Scholes model to determine fair value were as follows.



Years ended December 31 2008 2007
----------------------------------------------------------------------------
Risk-free interest rate (%) 4.6 5.0
Expected life (years) 5.0 5.0
Expected volatility (%) 52.0 53.0
----------------------------------------------------------------------------


(e) Contributed surplus

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

As at December 31 2008 2007
----------------------------------------------------------------------------
Balance, beginning of the year 8,236 5,627
Stock-based compensation expensed 994 1,296
Stock-based compensation capitalized 1,120 1,352
Reclassification to common shares on exercise of stock
options (745) (39)
----------------------------------------------------------------------------
Balance, end of the year 9,605 8,236
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(f) Net earnings (loss) per share

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

Years ended December 31 2008 2007
----------------------------------------------------------------------------
Basic 73,381 66,835
Diluted 74,024 66,983
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The reconciling item between the basic and diluted weighted average common shares outstanding is stock options. In 2008, 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 operating activities before expenditures on asset retirement obligations and change in non-cash working capital from operating activities. This ratio represents the time period required to repay the Company's net debt from funds generated from operations on the assumption there are no further capital expenditures incurred and funds from operations remain constant. The measure is often calculated on a historic annual basis and on an annualized most recent quarter basis to provide a more current view of the Company's capital structure.

At December 31, 2008 net debt, excluding risk management assets or liabilities, was $109.2 million and funds from operations was $68.7 million resulting in a net debt to funds from operations ratio of 1.6 times, down from 2.1 times at December 31, 2007. On an annualized fourth quarter 2008 basis, funds from operations would be $53.9 million resulting in a net debt to funds from operations ratio of 2.0 times. The Company is focused on achieving its internal target range for this ratio of approximately 1.5 times.

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

NOTE 8: INCOME TAXES

(a) Expected income 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 income tax rates to the Company's earnings before income taxes.

The difference relates to the following items:



Years ended December 31 2008 2007
----------------------------------------------------------------------------
Earnings (loss) before income taxes 6,526 (13,748)
Statutory tax rate 29.84% 32.46%
Expected income tax expense 1,946 (4,463)
Stock-based compensation 297 421
Reduction in future income tax rates (882) (3,634)
Impairment of goodwill - 3,928
Other 71 472
----------------------------------------------------------------------------
Total income tax expense (recovery) 1,432 (3,276)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(b) Future income tax liability

The income tax effect of temporary differences that give rise to significant portions of the future income tax assets and liabilities are presented below:



As at December 31 2008 2007
----------------------------------------------------------------------------
Future income tax assets:
Asset retirement obligations 2,441 1,885
Attributed Canadian Royalty Income 270 270
Non capital losses 1,894 4,142
Share issue costs 1,067 1,160
Future income tax liabilities:
Risk management asset (501) (332)
Property, plant and equipment (39,327) (35,287)
----------------------------------------------------------------------------
Net future income tax liability (34,156) (28,162)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The non-capital losses expire in the year 2026.

NOTE 9: FINANCIAL INSTRUMENTS

(a) Risk management overview

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

(b) Fair value of financial assets and liabilities

The Company's financial instruments as at December 31, 2008 include cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, long-term debt and risk management asset.

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

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

(c) Market risk

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

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

Foreign currency exchange rate risk

Foreign currency exchange rate risk is the risk that future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company's petroleum and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for petroleum and natural gas are affected by changes in the exchange rate between the Canadian and United States dollar. The exchange rate could affect the values of certain contracts, however, this indirect influence cannot be accurately quantified. The Company had no foreign exchange rate swap or related financial contracts in place as at December 31, 2008.

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in the market interest rates. The Company is exposed to interest rate risk to the extent that bank debt is at a floating rate of interest. The Company had no interest rate swap or related financial contracts in place as at December 31, 2008. If interest rates had been 100 basis points lower with all other variables held constant, net earnings for the year ended December 31, 2008 would have been $0.6 million (2007- $0.3 million) higher, due to lower interest expense.

Commodity price risk

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

As at December 31, 2008, the Company had the following financial derivative sales contracts which were recorded on the balance sheet at fair value of $1.7 million (2007 - $1.1 million) with changes in fair value included in unrealized gain of $0.6 million (2007 - $0.8 million) on risk management activities in the statement of earnings.



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


The Company has both United States and Canadian dollar physical sales contracts. The Canadian dollar physical sales contracts were entered into and continue to be held for the purpose of delivery of non-financial items as executory contracts and have not been recorded at fair value. The fair value of the United States dollar physical sales contracts are recorded on the balance sheet with changes in fair value included in unrealized gain or loss on risk management activities in the statement of earnings. As at December 31, 2008, the Company had the following physical sales contracts.



Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
April 2008 - Natural
March 2009 Gas Physical 2,000 GJ/d $7.30 fixed

November 2008 - Natural $7.46 fixed
March 2009 Gas Physical 4,000 GJ/d

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

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

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

April 2009 - Natural
October 2009 Gas Physical 1,000 mmbtu/d U.S. $8.18 fixed

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

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

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

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

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

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

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


For the year ended December 31, 2008, the Canadian dollar physical contracts resulted in a settlement loss of $0.1 million (2007 - gains of $7.1 million) that have been included in petroleum and natural gas sales. If natural gas prices had been +/- $0.10 per mcf, with all other variables held constant, the net change in the unrealized gain or loss on risk management activities in the statement of earnings for the year would have been +/- $0.1 million (2007 - $nil). The sensitivity is higher in 2008 as compared to 2007 because of an increase in financial and U.S. dollar based physical contracts outstanding.

The Company entered into the following contracts subsequent to December 31, 2008:



Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
----------------------------------------------------------------------------
April 2010 -
December 2010 Natural Gas Physical 3,000 GJ/d $6.25 floor/$7.47 ceiling

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

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

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

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

January 2010 - Natural
December 2010(1) Gas Physical 3,500 GJ/d $7.15 Call
----------------------------------------------------------------------------

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


d) Credit risk

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

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

The carrying amount of cash and accounts receivable represents the maximum credit exposure. The Company does not consider an allowance for doubtful accounts is required as at December 31, 2008, however, bad debt expense of $0.1 million was recorded during the year.



As at December 31, 2008 the Company's aged receivables are as follows.

December 31, 2008
----------------------------------------------------------------------------
Current (less than 30 days) 11,484
Past due (31-90 days) 1,617
Past due (more than 90 days) 1,421
----------------------------------------------------------------------------
Total 14,522
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(e) Liquidity risk

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

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

The following are the contractual maturities of financial liabilities as at December 31, 2008.



Financial liabilities less than 1 Year 1 - 2 Years 3 - 5 Years Thereafter
----------------------------------------------------------------------------
Outstanding cheques 105 - - -
Accounts payable and accrued
liabilities 36,211 - - -
Long term debt - principal - 91,400 - -
----------------------------------------------------------------------------
Total 36,316 91,400 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


NOTE 10: COMMITMENTS

The Company is committed to future minimum payments for natural gas transmission and processing, operating leases on compression equipment and office space. Payments required under these commitments for each of the next five years are: 2009-$4.5 million; 2010-$5.2 million; 2011-$4.9 million; 2012-$3.6 million; 2013-$2.2 million.

NOTE 11: CHANGES IN NON-CASH WORKING CAPITAL ITEMS



Years ended December 31 2008 2007
----------------------------------------------------------------------------
Change in working capital item:
Accounts receivable (1,918) 3,493
Prepaid expenses and deposits (176) (1,292)
Accounts payable and accrued liabilities 6,555 8,164
----------------------------------------------------------------------------
Total change in non-cash working capital 4,461 10,365
Relating to:
Operating activities (5,022) 6,777
Investing activities 9,483 3,588
----------------------------------------------------------------------------
4,461 10,365
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Contact Information

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