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CALGARY, ALBERTA--(Marketwire - Nov. 4, 2009) - Delphi Energy Corp. ("Delphi" or "the Company") (TSX: DEE) is pleased to announce its financial and operational results for the third quarter ended September 30, 2009.
Third Quarter 2009 Highlights
- Achieved average production of 6,773 barrels of oil equivalent per day (boe/d) with an average of 200 boe/d shut-in during the quarter for facility turnarounds and low commodity prices.
- Generated funds from operations of $12.6 million ($0.16 per basic share) in the quarter, up from $12.4 million ($0.16 per basic share) in the second quarter of 2009.
- Attained a ten percent reduction in operating costs to $9.46 per boe in the third quarter, down from $10.49 per boe in the third quarter of 2008.
- Realized a 60 day average production rate of 430 boe/d from a successful Doe Creek horizontal oil well at Hythe. Initiated horizontal drilling operations on the first of seven follow-up drilling locations.
- Reduced net debt to $93.7 million from $104.1 million at the end of the second quarter, resulting in a net debt to annualized cash flow ratio of 1.9:1.
- Acquired strategic natural gas infrastructure and production of approximately 400 boe/d in the Wapiti/Gold Creek area of North West Alberta for $11.8 million.
- Extended the Company's natural gas hedge positions through March 31, 2011 with April to October 2010 now hedged 45 percent at $6.08 per mcf and November 2010 to March 2011 hedged 22 percent at $6.31 per mcf.
Financial Highlights ($ thousands except per unit amounts)
Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 % Change 2009 2008 % Change
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Petroleum and natural
gas sales 24,433 34,461 (29) 71,867 105,242 (32)
Per boe 39.21 59.09 (34) 38.82 61.72 (37)
Funds from operations 12,635 18,160 (30) 35,023 55,184 (37)
Per boe 20.28 31.45 (36) 18.92 32.36 (42)
Per share - Basic 0.16 0.24 (33) 0.44 0.77 (43)
Per share - Diluted 0.16 0.23 (30) 0.44 0.76 (42)
Net earnings (loss) (3,278) 6,744 - (9,415) 6,053 -
Per boe (5.26) 12.09 - (5.09) 3.55 -
Per share - Basic (0.04) 0.09 - (0.12) 0.08 -
Per share - Diluted (0.04) 0.09 - (0.12) 0.08 -
Capital invested 7,810 27,132 (71) 25,504 61,119 (58)
Disposition of
properties (9,728) (5,500) 77 (9,953) (8,450) 18
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Net capital invested (1,918) 21,632 - 15,551 52,669 (70)
Acquisition of
properties 19,669 34,096 (42) 19,451 37,946 (49)
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Total capital 17,751 55,728 (68) 35,002 90,615 (61)
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Sep. 30 Dec. 31
2009 2008 % Change
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Debt plus working capital
deficiency (1) 93,711 109,237 (14)
Total assets 358,028 364,538 (2)
Shares outstanding (000's)
Basic 92,314 79,067 17
Diluted 99,706 83,798 19
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(1) excludes risk management asset/liability and the related current future
income tax liability/asset.
Operational Highlights
Three Months Ended Nine Months Ended
September 30 September 30
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Production 2009 2008 % Change 2009 2008 % Change
Natural gas (mcf/d) 33,628 33,691 - 34,690 32,460 7
Crude oil (bbls/d) 624 372 68 490 376 30
Natural gas liquids (bbls/d) 544 421 29 509 436 17
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Total (boe/d) 6,773 6,409 6 6,781 6,223 9
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MESSAGE TO SHAREHOLDERS
Although natural gas prices continued their downward trend in the third quarter, Delphi generated strong financial and operational results remaining well positioned for sustainable, long-term organic growth. The Company achieved third quarter cash flow stronger than in the second quarter, maintained quarterly production volumes on a limited field capital program and had the financial resources to complete a strategic acquisition at Gold Creek/Wapiti in North West Alberta. At the end of the third quarter, the Company had increased its financial flexibility to $31.3 million available on its production credit facility.
Production during the third quarter of 2009 averaged 6,773 boe/d, an increase of six percent compared to 6,409 boe/d in the third quarter of 2008. The increased light oil production at Hythe changed the production mix in the quarter to 17 percent liquids (83 percent natural gas) from 13 percent liquids (87 percent natural gas) in the second quarter. The change in production mix to higher netback liquids contributed to the strong third quarter cash flow.
Delphi's natural gas production continues to receive a premium to AECO pricing due to marketing arrangements, heating content and natural gas hedges. Approximately 53 percent of the Company's natural gas production was hedged at an average price of $7.38 per mcf in the third quarter, resulting in a gain on natural gas contracts of $8.0 million. The hedging gains resulted in a realized natural gas price of $5.77 per mcf representing a premium of 96 percent to average AECO pricing.
To view Production Growth (boe/d) graph, please click the following link: http://media3.marketwire.com/docs/1104dee_growth.pdf
Funds from operations in the third quarter of 2009 were $12.6 million ($0.16 per basic share) compared to $18.2 million ($0.24 per basic share) in the third quarter of 2008. Significantly lower average oil and natural gas prices were partially offset by increased production volumes and reduced royalty rates. A ten percent reduction in operating costs per boe was offset by slightly higher transportation, general and administrative and interest costs per boe resulting in an overall two percent reduction in cash costs per boe compared to the same quarter in 2008.
During the quarter, the Company completed a common share offering for gross proceeds of $16.5 million by issuing 13.2 million shares at an average price of $1.25 per share.
At September 30, 2009, the Company had reduced net debt to $93.7 million from $109.2 million at December 31, 2008. Delphi's field capital program for the first nine months of 2009 was $25.5 million or 73 percent of the cash flow generated. The remaining cash flow was used to partially fund the Company's strategic acquisition in the Gold Creek/Wapiti area of North West Alberta. The Company's net debt to cash flow ratio on an annualized cash flow basis was reduced to 1.9:1 at the end of the third quarter. Net debt includes bank debt plus working capital deficiency excluding the risk management asset/liability and the related current future income taxes liability/asset.
The scheduled semi-annual credit review by the Company's lenders is underway. The Company's lenders are currently National Bank of Canada and Bank of Nova Scotia. Delphi has syndicated its credit facilities to an expanded group of lenders as part of its strategic long-term growth plan. The semi-annual review and syndication will be completed by late-November. The Company expects to renew its revolving $125.0 million production credit facility upon completion of syndication with all other terms of the credit facilities remaining largely unchanged from the current arrangements.
OPERATIONAL UPDATE
During the third quarter, the Company executed a limited field capital program by drilling and completing one horizontal oil well (1.0 net) and completing one vertical gas well (1.0 net). Delphi was also active in the merger and acquisition market closing one asset acquisition and announcing two additional acquisitions that will close in the fourth quarter. In aggregate, the three transactions will result in initial production gains of 1,100 boe/d, an increase in proven plus probable reserves of 4.0 million boe's, ownership in over 500 kilometres of gas gathering infrastructure and six gas processing plants with a combined processing capacity in excess of one billion cubic feet per day of raw gas.
Hythe
At Hythe, the Company drilled and completed one horizontal oil well (1.0 net) as a follow up to two previous successful oil recompletions in vertical wells. The horizontal section was approximately 1,000 metres in length and completion operations consisted of six intervals being fracture stimulated using a combination of multi stage fracture technology and gelled liquid petroleum gas as the frac fluid. The 60 day average production rate was 390 barrels of light oil per day and 300 mcf/d of associated gas for a total of 430 boe/d. Based on a cost of $2.5 million this project resulted in finding and development costs of approximately $14.00 per boe, a recycle ratio in excess of 4.0 and a payout period of approximately 8 months. The oil pool has been mapped over 5,000 acres, of which Delphi controls 88 percent, with internal estimates of original oil in place in excess of 18 million barrels. A mature analog pool on trend is projected to ultimately recover 29 percent of the original oil in place. Delphi has commissioned a detailed reservoir simulation of the pool with preliminary results indicating a recovery factor of approximately 33 percent or an expected ultimate recovery of 5.2 million barrels of oil net to Delphi's working interest. Preliminary modeling indicates up to seventeen horizontal producers and seven water injectors would be required for full field development. Delphi is currently drilling the first of two horizontal wells (1.4 net) scheduled for the fourth quarter of 2009 and is planning up to five additional wells (4.4 net) in 2010.
The Company also completed one vertical gas well (1.0 net), that was drilled in the second quarter which had a seven day average production rate of 960 mcf/d (160 boe/d).
In the fourth quarter, the Company is continuing to advance the resource-type plays at Hythe with the drilling of a horizontal gas well targeting the Bluesky formation and a recompletion program targeting up to thirteen intervals in six wells that are currently either standing or low rate producers.
Bigstone
At Bigstone, the Company will drill one vertical gas well (0.5 net) prior to year end. The proposed well offsets a Company operated well completed in the first quarter that had a 90 day average production rate of 4,500 mcf/d (750 boed). The Company continues to monitor industry activity targeting oil in the Cardium formation on lands directly offsetting and on trend with the Bigstone field. In preparation for the upcoming winter program the Company is licensing three vertical gas wells and three horizontal oil wells targeting the Cardium formation.
LAND ACQUISITIONS
During the third quarter, the Company successfully participated in several Crown land sales acquiring 2,400 gross acres, in the Hythe and Gold Creek areas, at an average working interest of 71 percent. In combination with previous 2009 Crown land sales and the three asset acquisitions, Delphi has increased its undeveloped land position by 47,000 net acres to 172,000 net acres, an increase of 38 percent from December 31, 2008.
ASSET ACQUISITIONS
During the second half of 2009, the Company will complete three independent transactions comprised of an asset acquisition, an asset exchange/acquisition and a corporate acquisition. These transactions will result in a net gain of approximately 1,100 boed, 4.0 million boe's of proven plus probable reserves, ownership in significant gas processing and gathering systems and an increase in undeveloped land of 34,000 net acres.
Composite reserve and production acquisition costs are as follows (excludes undeveloped land costs and includes Future Development Costs):
Proved reserves $14.49 per boe Proved plus Probable Reserves $10.05 per boe Production Addition Costs $29,100 per boe/d
The acquired assets are located in the Deep Basin and will expand the Company's core asset base in North West Alberta. The primary producing intervals are the Cretaceous sands that the Company has been successfully developing in the Hythe and Bigstone areas through the use of existing and emerging technologies such as horizontal drilling, multi-stage fracture stimulations and gelled liquid petroleum gas fracturing. At Hythe and in the Gold Creek/Wapiti area, the acquired lands provide an increased working interest and expanded land base in the developing light oil play, the conventional Cretaceous gas development and the resource-type Nikanassin play. In 2010, the Company will recomplete two wells (0.8 net) and drill up to six wells (2.9 net); primary targets will be the Nikanassin and Gething with secondary potential in the Bluesky and Dunvegan intervals.
Delphi continues to build on a strategy of capital efficient growth and inventory expansion by acquiring underdeveloped, multi-zone natural gas assets in the Deep Basin of North West Alberta with significant low risk conventional and resource-type development potential. Development of the large original gas in place identified on these assets through the use of conventional and emerging technologies provide scale and repeatability for visible long-term capital efficient growth. Operational control of production, land and capital programs coupled with ownership in natural gas processing and gathering infrastructure are essential to controlling operating and capital cost efficiencies.
OUTLOOK
The Company will continue to be disciplined in its capital spending focusing on its core areas of Bigstone, Hythe and the recently acquired Gold Creek/Wapiti asset. Operational risk, capital efficiencies and continued inventory generation were the driving factors in selecting projects for the winter and 2010 field capital program.
The field capital program for the fourth quarter is estimated to be $12.0 to $14.0 million with two rigs drilling through the end of the year in conjunction with the on-going recompletion program. Cash flow for 2009 is now forecast to be between $45.0 million and $47.0 million compared to the original guidance of $38.0 million to $43.0 million. Increased cash flow for 2009 has been generated by reduced cash costs, higher crude oil prices and a change in the production mix. The Company has approximately 49 percent of its natural gas production hedged at $7.29 per mcf for the remainder of 2009.
The Company's planned 2010 capital program of approximately $65.0 million is expected to result in production volumes of 7,500 boe/d to 8,000 boe/d. A drill ready inventory in excess of $120.0 million was utilized to generate the 2010 capital program. The program consists of a broad range of projects including up to 24 drill wells (17.6 net), well and infrastructure optimization projects, recompletions, pipeline and facility projects.
The Company's 2010 cash flow forecast of $60.0 million to $65.0 million is based on an average AECO price of $5.70 per mcf and a WTI price of U.S. $75.00 per barrel. Net debt at December 31, 2010 is expected to be approximately $95.0 million to $100.0 million with a resultant net debt to cash flow ratio of 1.6:1. As in prior years, the Company's risk management program provides stability to the Company's cash flow, ensuring a defined level of capital spending. The Company has the following hedges in place:
Jan - Mar 2010 Apr - Oct 2010 Nov 2010 - Mar 2011
Volume Hedged (mcf/d) 10,436 16,129 7,875
Price (Cdn $/mcf) 7.81 6.08 6.31
Percentage Hedged (i) 29% 45% 22%
(i) based on 36,000 mcf/d.
Effective October 16, 2009, Henry Lawrie resigned from the Board of Directors for personal health reasons. Mr Lawrie has been the Chairman of the Audit & Reserves Committee and was a valuable advisor to fellow members of the Board and the Delphi Team on accounting, financial and governance matters. We are very appreciative of his efforts and wish him and his family well.
In addition, on behalf of the Board of Directors and all the employees of Delphi, I would like to thank our shareholders for their continued support. The Delphi Team continues to expand and remains focused on sustainable, capital efficient growth while maintaining the financial strength and flexibility to take advantage of strategic opportunities in this transaction-oriented environment.
CONFERENCE CALL
A conference call is scheduled for 11:00 a.m. Mountain Time (1:00 a.m. Eastern Time) on Thursday, November 5, 2009. The conference call number is 800-355-4959 or 416-340-8427. 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 November 12, 2009. To access the replay, dial 800-408-3053 or 416-695-5800. The passcode is 8458868. Delphi's third quarter 2009 financial statements and management's discussion and analysis are available on Delphi's website at www.delphienergy.ca and will be available on SEDAR at www.sedar.com within 24 hours.
Delphi Energy is a Calgary-based company that explores, develops and produces oil and natural gas in Western Canada. The Company is managed by a proven technical team. Delphi trades on the Toronto Stock Exchange under the symbol DEE.
Forward-Looking Statements. This release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", may", "will", "should", believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.
More particularly and without limitation, this release contains forward looking statements and information relating to the Company's risk management program, petroleum and natural gas production, future funds from operations, capital programs, commodity prices, costs and debt levels. The forward-looking statements and information are based on certain key expectations and assumptions made by Delphi, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the capital availability to undertake planned activities and the availability and cost of labour and services.
Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect the Company's operations or financial results are included in reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). The forward-looking statements and information contained in this press release are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Basis of Presentation. For the purpose of reporting production information, reserves and calculating unit prices and costs, natural gas volumes have been converted to a barrel of oil equivalent (boe) using six thousand cubic feet equal to one barrel. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with the Canadian Securities Administrators' National Instrument 51-101 when boes are disclosed. Boes may be misleading, particularly if used in isolation.
Non-GAAP Measures. The release contains the terms "funds from operations", "funds from operations per share", "net debt", "cash operating costs" and "netbacks" which are not recognized measures under Canadian generally accepted accounting principles. The Company uses these measures to help evaluate its performance. Management considers netbacks an important measure as it demonstrates its profitability relative to current commodity prices. Management uses funds from operations to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and to repay debt. Funds from operations is a non-GAAP measure and has been defined by the Company as net earnings plus the addback of non-cash items (depletion, depreciation and accretion, stock-based compensation, future income taxes and unrealized gain/(loss) on risk management activities) and excludes the change in non-cash working capital related to operating activities and expenditures on asset retirement obligations and reclamation. The Company also presents funds from operations per share whereby amounts per share are calculated using weighted average shares outstanding consistent with the calculation of earnings per share. Delphi's determination of funds from operations may not be comparable to that reported by other companies nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. The Company has defined net debt as the sum of long term debt plus working capital excluding the current portion of future income taxes and risk management asset/liability. Net debt is used by management to monitor remaining availability under its credit facilities. Cash operating costs have been defined as the sum of operating expenses, transportation expenses, general and administrative expenses and interest costs.
MANAGEMENT DISCUSSION AND ANALYSIS
(All tabular amounts are stated in thousands of dollars, except per unit amounts)
The management discussion and analysis has been prepared by management and reviewed and approved by the Board of Directors of Delphi Energy Corp. ("Delphi" or "the Company"). The discussion and analysis is a review of the financial results of the Company based upon accounting principles generally accepted in Canada. Its focus is primarily a comparison of the financial performance for the nine months ended September 30, 2009 and 2008 and should be read in conjunction with the audited financial statements and accompanying notes for the years ended December 31, 2008 and 2007. The discussion and analysis has been prepared as of November 3, 2009.
OPERATIONAL AND FINANCIAL HIGHLIGHTS
Delphi's third quarter production averaged 6,773 barrels of oil equivalent per day (boe/d), representing a six percent increase over the comparative period in 2008. Year to date, the Company increased production volumes nine percent over 2008. Natural gas production represented 83 percent of the Company's average production in the third quarter compared to 87 percent in the second quarter of 2009. The change in production mix was a result of the increased light oil production at Hythe, Alberta. Third quarter production volumes were also affected by scheduled facility maintenance which resulted in an average 200 boe/d shut in for the quarter. Despite the scheduled downtime, Delphi is pleased with its ability to show year over year organic growth in an unstable commodity price environment. The Company has undertaken a minimal field capital program in 2009, opting to maintain production at approximately 6,800 boe/d for the first three quarters of the year as a result of the significant drop in natural gas prices over that time. The Company has used its financial strength and cash flow in excess of capital invested to acquire strategic production and infrastructure in North West Alberta and expand its inventory of growth opportunities.
Funds flow from operations in the third quarter of 2009 was $12.6 million or $0.16 per basic share, compared to $18.2 million or $0.24 per basic share in 2008, primarily as a result of lower average oil and natural gas prices for the quarter offset by the growth in production volumes, reduced royalty rates and a two percent reduction in cash operating costs per boe as compared to the same quarter in 2008. Delphi's risk management program continued to contribute to funds from operations providing the Company with $8.0 million in realized hedging gains in the quarter.
Delphi's financial position continued to remain strong in the third quarter of 2009, providing financial flexibility to execute the remainder of its 2009 capital program. At September 30, 2009, the Company had net debt of $93.7 million on a production credit facility of $125.0 million, providing excess financial capacity of approximately $31.3 million. On an annualized cash flow basis, the Company's net debt to cash flow ratio was 1.9:1 as of September 30, 2009.
Delphi has been actively pursuing property and corporate acquisitions in its core area of North West Alberta. On August 31, 2009, Delphi closed the property and infrastructure acquisition in the Gold Creek/Wapiti areas of North West Alberta. In addition, on August 21, 2009, Delphi announced the acquisition of Fairmount Energy Inc. which is expected to close in the fourth quarter of 2009. On September 30, 2009, Delphi announced a property and infrastructure acquisition at Hythe, Alberta which closed on November 3, 2009. These strategic acquisitions provide production, land and infrastructure within the Company's core area of focus.
BUSINESS ENVIRONMENT
Benchmark Prices
Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 % Change 2009 2008 % Change
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Natural Gas
NYMEX (US $/mmbtu) 3.16 9.91 (68) 3.81 9.62 (60)
AECO (CDN $/mcf) 2.94 7.73 (62) 3.78 8.64 (56)
Crude Oil
West Texas Intermediate
(US $/bbl) 68.29 117.97 (42) 57.13 113.29 (50)
Edmonton Light (CDN $/bbl) 71.49 121.85 (41) 62.47 115.14 (46)
Foreign Exchange
Canadian to US dollar 1.10 0.96 15 1.17 0.98 19
US to Canadian dollar 0.91 1.04 (13) 0.86 1.02 (16)
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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 is subject to disruption from time to time. The increase in capacity of natural gas liquefaction and regasification facilities has resulted in natural gas in North America becoming a global commodity, more so through the winter heating season than the summer cooling season, with influences from world weather conditions and global supply in the form of liquefied natural gas (LNG) delivered to the United States.
In the third quarter of 2009, the U.S. Northeast and Midwest and Central Canada experienced below average seasonal temperatures resulting in reduced average demand for natural gas for electrical generation with industrial demand remaining significantly reduced due to the continuing economic slowdown. Downward pressure on natural gas prices began early in 2009 and continued through most of the third quarter as natural gas storage numbers continued to grow over the five year average levels. AECO gas prices hit a low of $2.02 per mcf early in September but have since recovered to over $4.25 per mcf at the end of October, 2009. AECO averaged $2.94 per mcf in the third quarter. The drop in natural gas prices has had a significant effect on the active drilling rig count in both Canada and the United States.
For internal forecasting purposes, Delphi continues to expect a challenging natural gas market for the remainder of 2009 and anticipates AECO to average between $3.75 and $4.25 per mcf for the year. Delphi continues to monitor the variables affecting the price of natural gas in order to ensure its capital program is in line with expected funds flow from operations.
Crude Oil
West Texas Intermediate at Cushing, Oklahoma (WTI) is the benchmark reference for North American crude oil prices. Canadian crude oil prices are based upon postings, primarily at Edmonton, Alberta and represent the WTI price adjusted for quality and transportation differentials as well as the US/CDN dollar exchange rate.
Through the third quarter of 2009, the price for crude oil was reasonably stable between U.S. $65.00 and $75.00 per barrel. Crude oil supplies continued to grow in the quarter as demand remained reduced due to the slowdown in global economies and use of energy. WTI averaged U.S. $68.29 per barrel for the quarter compared to U.S. $117.97 per barrel for the same quarter in the prior year, a decrease of 42 percent. The average price of U.S. $68.29 per barrel was, however, 15 percent higher than the second quarter average of U.S. $59.62 per barrel.
In the third quarter of 2009, the value of the Canadian dollar increased against its U.S. counterpart as the demand for the United States dollar as a safe haven in these uncertain economic times decreased. This negative effect to the price of oil for Canadian producers was compounded by a widening basis differential between U.S. and Canadian markets. In the third quarter of 2009, Canadian crude oil prices averaged $71.49 per barrel compared to $121.85 per barrel for the same quarter in the prior year, a decrease of 41 percent.
Prices for heavy oil and other lesser quality crude oils trade at a discount or differential to light crude oil due to the additional costs involved in the refining process. The average differential in the third quarter of 2009 was $6.21 per barrel compared to $16.43 per barrel in 2008. The decrease in the average differential, offset by lower light oil prices, resulted in Bow River crude prices averaging $65.29 per barrel compared to $105.42 per barrel in the third quarter of 2008.
For internal forecasting purposes, Delphi anticipates WTI to average between U.S. $65.00 and $75.00 per barrel for the remainder of 2009 with the Canadian dollar to remain between $1.00 and $1.05 per U.S. dollar.
Industry Cost of Services
The drop in commodity prices in the latter half of 2008 and through 2009 so far have had a significant negative effect on cash flow available for capital programs and hence drilling and field activity. Drilling contractors and oilfield service companies have had to reduce the rates charged for equipment and labour in order to remain competitive and as active as possible, but at a much slower pace than in previous years. The overall uncertainty in the economy has also led to reduced demand for oilfield services and equipment as many companies have been unable to raise external sources of funding to pursue capital programs.
FINANCIAL STRATEGY
The Company maintains an active risk management program as an integral part of its overall financial strategy to mitigate volatility in funds from operations resulting from fluctuating commodity prices. Delphi's program involves executing numerous contracts over a period of time to take advantage of the volatility in the natural gas market. The strategy takes advantage of the upward swings in natural gas prices as a result of a) the changes in demand/supply fundamentals and/or b) the movement of significant financial assets invested in the natural gas market as a pure commodity play. The transactions are generally undertaken for contract terms 12 to 24 months in advance with financially strong counterparties and predominantly executed on a physical basis with the Company's natural gas marketer. Delphi's risk management program consists of fixed price contracts, costless collars, participating swaps and puts and calls which provide downside protection along with the opportunity to share in the upside if market prices increase above the floor price for the costless collar, participating swaps and puts. If market prices are above fixed price contracts or the ceiling price of costless collars and calls, the Company would continue to achieve its downside protection while realizing losses on these hedging contracts.
Delphi has a strategy of hedging approximately 40 to 50 percent of its natural gas production as long as demand/supply fundamentals indicate volatile markets in the future. Currently, Delphi has hedged approximately 49 percent of its before-royalty natural gas production at a predominantly AECO based average floor price of $7.29 per mcf for the remainder of 2009. This compares to the forward strip commodity price for AECO of $5.74 per mcf as of September 30, 2009. The following natural gas hedges are in place to support the Company's cash flow.
Oct Nov-Mar Apr-Dec Oct-Dec Jan-Dec
2009 2009/2010 2010 2009 2010
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Production hedged
(mmcf/d) 19.0 13.1 15.2 17.7 14.0
Percentage of natural gas
production (i) 53% 36% 42% 49% 39%
Price floor (Cdn $/mcf) $ 7.38 $ 7.51 $ 6.13 $ 7.29 $ 6.44
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(i) based on 36 mmcf/d
The fair value of the outstanding contracts is estimated to be approximately $6.9 million as of September 30, 2009.
As the Company's financial condition improves and/or natural gas demand/supply fundamentals move toward equilibrium or reduced supply, Delphi will manage its hedging program accordingly to take advantage of exposure to higher natural gas commodity prices.
Delphi continues to direct efforts at maintaining or reducing its controllable costs. Increasing production at its various operating fields through Company owned infrastructure reduces fixed costs on a per boe basis and improves netbacks. Field operators are encouraged to undertake preventative maintenance on field infrastructure and wellsite equipment to minimize production downtime and prevent significant operating costs associated with repairs. The Company strives to achieve improvement in its costs of production and at a minimum maintain current production costs.
Maintaining or improving strong operating netbacks per boe through the risk management program and the control of costs associated with production operations, allows the Company to pursue its planned capital program with greater confidence that financial flexibility will be maintained while incurring capital expenditures to grow production volumes. The risk management program has been and will continue to be an integral part of maximizing operating netbacks during periods of price volatility and excess natural gas supply.
The annual net capital expenditure program in the field will continue to be slightly less than forecast funds from operations. Additional capital may be approved as a result of opportunistic acquisitions, incremental cash flow from greater than expected production growth, higher than forecast cash netbacks or other sources of financing.
Delphi continues to be focused on reducing its leverage and improving its financial flexibility through net debt reduction or increasing funds flow growth resulting in a lower net debt to annualized quarterly funds from operations ratio. The Company continues to be focused on achieving its internal target range for this ratio of 1.3 to 1.5 times. In a low price environment, the Company's objective would be to reduce or at least not increase the net debt balance by undertaking a capital program within cash flow.
SELECTED INFORMATION
The following table sets forth certain information of the Company for the
past eight consecutive quarters.
Sept. 30 Jun. 30 Mar. 31 Dec. 31
2009 2009 2009 2008
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Production
Natural gas (mcf/d) 33,628 35,641 34,813 35,545
Oil (bbl/d) 624 371 475 431
Natural gas liquids (bbl/d) 544 498 485 353
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Barrels of oil equivalent (boe/d) 6,773 6,809 6,762 6,708
Financial
($ thousands except per unit amounts)
Petroleum and natural gas revenue 24,433 23,229 24,205 30,160
Funds from operations 12,635 12,371 10,017 13,473
Per share - basic 0.16 0.16 0.13 0.18
Per share - diluted 0.16 0.16 0.13 0.18
Net earnings (loss) (3,278) (2,817) (3,320) (959)
Per share - basic (0.04) (0.04) (0.04) (0.01)
Per share - diluted (0.04) (0.04) (0.04) (0.01)
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Sept. 30 Jun. 30 Mar. 31 Dec. 31
2008 2008 2008 2007
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Production
Natural gas (mcf/d) 33,691 31,898 31,777 30,610
Oil (bbl/d) 372 368 387 346
Natural gas liquids (bbl/d) 421 517 372 420
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Barrels of oil equivalent (boe/d) 6,409 6,202 6,056 5,868
Financial
($ thousands except per unit amounts)
Petroleum and natural gas revenue 34,461 38,569 32,212 26,632
Funds from operations 18,160 19,965 17,059 13,747
Per share - basic 0.24 0.29 0.25 0.20
Per share - diluted 0.23 0.28 0.25 0.20
Net earnings (loss) 6,743 49 (739) 1,732
Per share - basic 0.09 - (0.01) 0.03
Per share - diluted 0.09 - (0.01) 0.03
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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 Peace River Arch acquisition resulted in continued production growth quarter over quarter. In the first nine months of 2009, production growth was achieved with drilling success at Bigstone and Hythe, Alberta. Revenue and funds from operations reflect the cycle of natural gas prices and production volumes.
Natural gas prices over the past two years have generally reflected the cyclical nature of demand. Higher prices in the winter months, reflecting demand for heating, weaken through the summer months as production is placed in storage for the upcoming heating season demand. Natural gas prices in the second quarter of 2008 did not follow the cyclical trend expected, as prices continued to increase coming out of the winter heating season due to concerns over natural gas supply in storage and the continued increase in crude oil prices. Subsequent to the second quarter, natural gas prices decreased significantly and then stabilized in the fourth quarter. In 2009, reduced heating demand and industrial demand due to the economic crisis caused natural gas prices to decrease further as a result of concerns over excess supply. The Company achieved record cash flow of approximately $20.0 million in the second quarter of 2008 at the peak of commodity prices. Delphi continues to mitigate the volatility of commodity prices on its cash flow and capital program by undertaking an active risk management program. For the nine months ended September 30, 2009, the Company has recorded cash flow of $35.0 million, during a period of weak commodity pricing. The strong 2009 cash flow is attributed to an increase in production volumes, reduced cost structure and a successful risk management program.
DRILLING RESULTS
Three Months Ended Nine Months Ended
September 30, 2009 September 30, 2009
Gross Net Gross Net
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Natural gas wells - - 6.0 4.8
Oil wells 1.0 1.0 1.0 1.0
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Total wells 1.0 1.0 7.0 5.8
Success rate (%) 100 100 100 100
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The Company had a successful quarter with the drill bit resulting in a drilling success rate of 100 percent. The Company has in excess of one hundred drilling locations identified within its core areas of operations.
CAPITAL INVESTED
Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 % Change 2009 2008 % Change
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Land 427 130 228 983 130 656
Seismic 84 719 (88) 380 722 (47)
Drilling and completions 4,442 21,329 (79) 15,524 44,390 (65)
Equipping and facilities 2,035 3,599 (43) 5,591 12,847 (56)
Capitalized expenses 810 767 6 2,623 2,434 8
Other 12 588 (98) 403 596 (32)
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Capital invested 7,810 27,132 (71) 25,504 61,119 (58)
Disposition of
properties (9,728) (5,500) 77 (9,953) (8,450) 18
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Net capital invested (1,918) 21,632 - 15,551 52,669 (70)
Acquisition of
properties 19,669 34,096 (42) 19,451 37,946 (49)
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Total capital 17,751 55,728 (68) 35,002 90,615 (61)
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The Company continues to focus its capital program towards its core areas of Bigstone and Hythe to take advantage of the multi-zone nature of these assets, low operating costs and quick on-stream capability associated with owned gathering and processing infrastructure. Year to date, the Company has directed capital towards drilling, completion and tie-in of five wells at Hythe, Alberta, one well at Bigstone, Alberta and one well at Noel, British Columbia. In the third quarter of 2009, the Company closed an acquisition of predominantly natural gas producing properties with significant infrastructure in North West Alberta for cash consideration of $19.7 million. Upon closing the acquisition, the Company immediately disposed of 40 percent of the acquired working interest in the properties for cash proceeds of $7.9 million. In addition, the Company disposed of two non-core minor working interest natural gas properties for cash proceeds of $1.8 million.
PRODUCTION
Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 % Change 2009 2008 % Change
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Natural gas (mcf/d) 33,628 33,691 - 34,690 32,460 7
Crude oil (bbls/d) 624 372 68 490 376 30
Natural gas liquids
(bbls/d) 544 421 29 509 436 17
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Total (boe/d) 6,773 6,409 6 6,781 6,223 9
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Production for the three months ended September 30, 2009 averaged 6,773 boe/d representing an increase of six percent over the comparative period primarily due to the successful drilling and optimization programs at Bigstone and Hythe. The success of the 2009 capital program has allowed the company to increase production volumes nine percent over the comparative period in 2008. This is a testament to the quality of the asset base and technical expertise of the staff and management. A significant undeveloped land base, multi-zone potential and the successful application of emerging technologies continue to provide material growth opportunities in existing and new play concepts. Third quarter production volumes were affected by scheduled facility maintenance which resulted in an average 200 boe/d shut in for the quarter. The Company's production portfolio for the quarter was weighted 83 percent to natural gas, nine percent to crude oil and eight percent to natural gas liquids. The change in production mix to 17 percent crude oil and natural gas liquids from 13 percent in the second quarter of 2009 was a contributing factor to the third quarter's strong cash flow.
Crude oil production was 68 percent higher for the three months ended September 30, 2009 over the comparative quarter. The increase in oil production is due to the successful drilling and optimization program targeting the Doe Creek light oil discovery at Hythe, Alberta.
Natural gas liquids were 29 percent higher for the three months ended September 30, 2009, as compared to the comparative period in 2008 due to the increased natural gas liquids production at Progress, Alberta.
REALIZED SALES PRICES
Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 % Change 2009 2008 % Change
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AECO ($/mcf) 2.94 7.73 (62) 3.78 8.64 (56)
Heating content and
marketing ($/mcf) 0.26 0.57 (54) 0.26 0.53 (51)
Gain (loss) on physical
contracts ($/mcf) 2.22 (0.05) - 1.66 (0.20) -
Gain (loss) on financial
contracts ($/mcf) 0.35 0.03 1,076 0.34 (0.01) -
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Realized natural gas price
($/mcf) 5.77 8.28 (30) 6.04 8.96 (33)
Realized oil price ($/bbl) 68.47 111.34 (39) 59.79 103.54 (42)
Realized natural gas liquids
price ($/bbl) 51.29 93.26 (45) 47.11 94.94 (50)
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Total realized sales price
($/boe) 39.21 59.09 (34) 38.82 61.72 (37)
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For the three and nine months ended September 30, 2009, Delphi's risk management program realized a gain of $8.0 million and $19.0 million, respectively. For the quarter, the realized gain was $2.57 per mcf with physical contracts contributing a gain of $2.22 per mcf and financial contracts contributing a gain of $0.35 per mcf. For the nine months ended September 30, 2009, the average realized natural gas price was 33 percent less than the comparative period due to a 56 percent decrease in the AECO spot price offset by significant realized hedging gains.
Excluding hedges, the Company continues to receive higher than the AECO spot price on natural gas sales due to the high heating content of its natural gas production and the sale of approximately 3,500 million British thermal units (mmbtu) per day on the Alliance pipeline which is priced at the Chicago Monthly Index.
The following table outlines the premium (discount) Delphi realized on natural gas prices compared to the average quarterly AECO price due to the risk management program, quality of production and gas marketing arrangements. In years of both high and low commodity price environments, Delphi's realized sales price has benefited from a premium to AECO.
Sept. 30 Jun. 30 Mar. 31 Dec. 31
2009 2009 2009 2008
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Natural Gas Price
Delphi realized ($/mcf) 5.77 5.81 6.55 8.14
AECO average ($/mcf) 2.94 3.47 4.95 6.70
Premium (discount) to AECO 96% 67% 32% 21%
Hedging gain (loss) ($000's) 7,973 6,997 3,991 1,985
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Sept. 30 Jun. 30 Mar. 31 Dec. 31
2008 2008 2008 2007
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Natural Gas Price
Delphi realized ($/mcf) 8.28 9.66 8.91 7.61
AECO average ($/mcf) 7.73 10.22 7.97 6.15
Premium (discount) to AECO 7% (5%) 12% 24%
Hedging gain (loss) ($000's) (67) (3,153) 1,371 2,996
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Delphi's oil production is a mix of light and medium oil; therefore the Company's average price fluctuates with the change in the benchmark crude oil prices and the quality differential. Increased production of light oil at Bigstone and Hythe continues to high grade the Company's quality of crude oil resulting in pricing more reflective of light oil. Year to date, the Company's realized crude oil and natural gas liquids prices were significantly lower than the comparative quarter in the previous year as a result of the significant drop in benchmark prices.
To view Natural gas Prices (Cdn$/mcf) graph, please click the following link: http://media3.marketwire.com/docs/1104dee_ngp.pdf
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 49 percent of its before-royalty natural gas production at a predominately AECO based average floor price of $7.29 per mcf for the remainder of 2009.
With respect to financial contracts, which are derivative financial instruments, management has elected not to use hedge accounting and consequently records the fair value of its natural gas financial contracts on the balance sheet at each reporting period with the change in the fair value being classified as unrealized gains and losses in the statement of operations. The changes in the fair value of the United States dollar denominated physical contracts are also classified as unrealized gains and losses in the statement of operations.
The Company recognized an unrealized non-cash loss on its financial contracts and United States dollar denominated physical contracts of $1.9 million for the first nine months of 2009. The fair values of these contracts are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the contracts outstanding at the end of the period having regard to forward prices and market values provided by independent sources. Due to the inherent volatility in commodity prices, actual amounts realized may differ from these estimates.
The Company has fixed the price applicable to future production through the
following contracts.
Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
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April 2009 - Natural Physical 1,000 GJ/d $7.08 fixed
October 2009 Gas
April 2009 - Natural Physical 2,000 GJ/d $8.25 floor/$10.00 ceiling
October 2009 Gas
April 2009 - Natural Physical 1,000 U.S. $8.18 fixed
October 2009 Gas mmbtu/d
April 2009 - Natural Physical 2,000 GJ/d $8.59 fixed
October 2009 Gas
April 2009 - Natural Physical 2,000 GJ/d $6.70 floor plus 50%
October 2009 Gas greater than $6.70
April 2009 - Natural Physical 3,000 GJ/d $7.52 fixed
March 2010 Gas
April 2009 - Natural Physical 2,000 GJ/d $6.80 floor plus 50%
March 2010 Gas greater than $6.80
November 2009 - Natural Physical 2,000 GJ/d $7.75 floor/$8.70 ceiling
March 2010 Gas
November 2009 - Natural Physical 2,000 GJ/d $7.26 floor plus 50%
March 2010 Gas greater than $7.26
November 2009 - Natural Physical 2,000 GJ/d $7.65 floor plus 50%
March 2010 Gas greater than $7.65
April 2010 - Natural Physical 3,000 GJ/d $6.25 floor/$7.47 ceiling
December 2010 Gas
April 2010 - Natural Physical $5.93 floor plus 50%
December 2010 Gas 4,000 GJ/d greater than $5.93
April 2010 - Natural Financial 2,000 GJ/d $5.53 fixed
October 2010 Gas
April 2010 - Natural Physical 3,000 GJ/d $6.12 fixed
March 2011
Gas
April 2010 - Natural Physical 2,500 GJ/d $5.73 fixed
March 2011
Gas
February 2009 - Natural Financial 3,500 GJ/d $6.00 Put
December 2009(i)
Gas
March 2009 - Natural Physical 3,500 GJ/d $6.00 Put
December 2009(i) Gas
January 2010 - Natural Financial 3,500 GJ/d $7.40 Call
December 2010(i) Gas
January 2010 - Natural Physical 3,500 GJ/d $7.15 Call
December 2010(i) Gas
April 2010 - Natural Financial 2,500 GJ/d $4.75 Put
October 2010(ii) Gas
January 2011 - Natural Financial 2,500 GJ/d $7.14 Call
December 2011(ii) Gas
100 bbls/d
January 2010 - Crude Oil Financial Cdn. $86.40 fixed
December 2010
January 2010 - Crude Oil Financial 100 bbls/d Cdn. $72.20 floor/$100.00
December 2010 ceiling
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(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.
(ii) The Company has acquired a natural gas put contract at $4.75 per
gigajoule on 2,500 gigajoules per day for the period April 1, 2010
through October 31, 2010. This put was paid for with the sale of a
natural gas call on 2,500 gigajoules per day at a price of $7.14 per
gigajoule for the period January 1, 2011 through December 31, 2011.
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 Nine Months Ended
September 30 September 30
2009 2008 % Change 2009 2008 % Change
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Natural gas 9,893 25,824 (62) 38,270 81,420 (53)
Natural gas physical
contract gains (losses) 6,882 (164) - 15,695 (1,759) -
Crude oil 3,931 3,769 4 7,999 10,667 (25)
Natural gas liquids 2,567 3,573 (28) 6,546 11,342 (42)
Sulphur 69 1,362 (95) 91 3,662 (98)
Realized gain on risk
management contracts 1,091 97 1,025 3,266 (90) -
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Total 24,433 34,461 (29) 71,867 105,242 (32)
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The decrease in revenue over the comparative periods is attributed to the decrease in realized sales price per boe offset by the realized gains from the risk management program and the increase in production volumes.
Additionally, during 2008, sulphur prices began their rise as demand for fertilizers increased around the world. Delphi received $3.7 million from the sale of sulphur during the first nine months of 2008, primarily associated with production at its Tower Creek well. As a result of the slowing economies around the world, sulphur prices have fallen significantly resulting in minimal sales year to date in 2009 despite ongoing production at Tower Creek.
ROYALTIES
Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 % Change 2009 2008 % Change
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Total 1,514 6,352 (76) 6,423 20,560 (69)
Per boe 2.43 10.77
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