CALGARY, ALBERTA--(Marketwire - July 27, 2011) -
Delphi Energy Corp. ("
Delphi" or the "Company") (
News -
Market indicators) is pleased to announce its results for the quarter ended June 30, 2011.
Second Quarter 2011 Highlights
- achieved record production in the second quarter with average daily volumes of 8,906 barrels of oil equivalent per day (boe/d), an increase of eleven percent compared to the second quarter of 2010;
- increased oil and natural gas liquids production by 65 percent to 2,663 bbls/d compared to 1,612 bbls/d in the second quarter of 2010, changing the production mix to approximately 30 percent crude oil and natural gas liquids in the second quarter of 2011;
- generated funds from operations (cash flow) of $17.5 million, an increase of 40 percent from the comparative quarter of 2010;
- reduced operating costs by 17 percent to $6.63 per boe in the second quarter of 2011 from $7.95 per boe in the second quarter of 2010;
- achieved an operating netback of $26.03 per boe and a cash netback of $21.60 per boe in the second quarter of 2011 compared to $22.05 per boe and $17.10 per boe, respectively, in the second quarter of 2010;
- realized $1.5 million ($1.85 per boe) in hedging gains on commodity contracts in the second quarter of 2011 compared to $4.2 million ($5.72 per boe) in the second quarter of 2010, providing stability to cash flow and balance sheet strength;
- increased cash netbacks (excluding hedging gains) by 73 percent compared to second quarter of 2010 as a result of increased oil and NGL production and lower costs, with higher oil prices offsetting lower realized NGL and natural gas prices;
- renewed the Company's credit facilities at $145.0 million, an increase of $5.0 million;
- reduced bank debt plus working capital (net debt) from $116.9 million at the end of the first quarter 2011 to $108.3 million at the end of the second quarter of 2011 resulting in a net debt to annualized quarterly cash flow ratio of approximately 1.5:1; and.
- commenced the second half 2011 capital program with two horizontal wells in Hythe and one multi-zone vertical well in Wapiti drilled and rig released during the quarter, despite wet weather conditions.
Operational Highlights
Three Months Ended Six Months Ended
June 30 June 30
Production 2011 2010 % Change 2011 2010 % Change
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Natural gas (mcf/d) 37,460 38,540 (3) 36,987 38,445 (4)
Crude oil (bbls/d) 1,346 1,074 25 1,225 910 35
Natural gas liquids
(bbls/d) 1,317 538 145 1,195 523 128
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Total (boe/d) 8,906 8,035 11 8,585 7,841 9
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Financial Highlights ($ thousands except per unit amounts)
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Petroleum and natural
gas sales 32,678 27,970 17 61,578 57,426 7
Per boe 41.35 39.83 4 40.34 41.32 (2)
Funds from operations 17,517 12,507 40 32,578 27,556 18
Per boe 21.60 17.10 26 20.96 19.42 8
Per share - Basic 0.15 0.12 25 0.28 0.27 4
Per share - Diluted 0.15 0.12 25 0.28 0.27 4
Net earnings 5,757 131 4,295 6,719 1,744 285
Per boe 7.09 0.17 4,129 4.32 1.23 251
Per share - Basic 0.05 - 100 0.06 0.02 200
Per share - Diluted 0.05 - 100 0.06 0.02 200
Capital invested 9,542 7,622 25 43,839 42,720 3
Disposition of
properties (63) (251) (75) (336) (251) 34
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Net capital invested 9,479 7,371 29 43,503 42,469 2
Acquisition of
properties - (307) (100) 87 385 (77)
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Total capital
invested 9,479 7,064 34 43,590 42,854 2
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Jun. 30 Dec. 31
2011 2010 % Change
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Debt plus working
capital deficiency(1) 108,338 108,054 -
Total assets 408,895 387,687 5
Shares outstanding
(000's)
Basic 117,513 112,825 4
Diluted 126,865 119,500 6
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(1) excludes risk management asset and the related current future income
taxes.
MESSAGE TO SHAREHOLDERS
Production during the second quarter of 2011 averaged 8,906 boe/d, an increase of eleven percent compared to 8,035 boe/d in the second quarter of 2010. The increased light oil production at Hythe and Bigstone and growing liquids production at Wapiti changed the production mix in the quarter to 30 percent liquids (70 percent natural gas) from 20 percent liquids (80 percent natural gas) in the second quarter of 2010. The change in production mix to higher netback oil and natural gas liquids was a significant contributor to second quarter cash flow.
Cash flow in the second quarter of 2011 was $17.5 million or $0.15 per basic share, compared to $12.5 million or $0.12 per basic share in the comparative quarter of 2010. The growth in cash flow in 2011 over 2010 was primarily a result of the continued reduction in operating costs, change in production mix towards higher netback crude oil and natural gas liquids production and the increase in realized oil prices offset by the decrease in realized natural gas prices.
Operating costs before processing income were $0.4 million lower than the comparative quarter despite average production growth of eleven percent over the same time. The fixed costs associated with owned natural gas plant infrastructure, field compression facilities and pipelines continue to be allocated over more production volumes resulting in lower marginal costs of new production. The Company continues to focus production growth in its core areas where operating costs were less than $6.00 per boe on a weighted average basis. The Company's operating costs were reduced by $1.32 per boe to $6.63 per boe in the second quarter of 2011, 17 percent lower than the comparative period.
For the quarter ended June 30, 2011, the Company recognized approximately $1.5 million in realized gains on financial and physical hedging contracts providing significant stability to the Company's cash flow.
The combination of the above highlighted items resulted in Delphi's financial position continuing to remain strong at the end of the second quarter of 2011, providing the financial flexibility to execute the second half of the 2011 capital program. At June 30, 2011, the Company had net debt of $108.3 million on total credit facilities of $145.0 million, providing excess financial capacity of approximately $36.7 million. On an annualized, second quarter funds from operations basis, Delphi's net debt to cash flow ratio was 1.5:1. Net debt includes bank debt plus working capital deficiency excluding the fair value of financial instruments.
Operations
Delphi has moved three drilling rigs into its operating areas in the Deep Basin of North West Alberta to kick off its second half 2011 capital program, drilling approximately 12 gross (9.2 net) wells.
During the second quarter, the Company drilled three wells (2.5 net) within its core areas of Wapiti and Hythe. One horizontal well (1.0 net) targeted light oil in the Doe Creek formation at Hythe. The second horizontal well drilled targeted natural gas in the Falher formation where the Company has identified approximately 60 to 70 follow-up locations. At Wapiti, one vertical well (0.5 net) was drilled and cased during the second quarter. Completion operations have commenced on all three wells, despite ongoing wet weather conditions which continues to cause timing delays.
At Wapiti, a total of approximately 8 gross (6.2 net) vertical wells targeting liquids-rich natural gas in the Nikanassin and uphole Cretaceous intervals will be drilled during the second half capital program.
At Hythe, the Company continues to advance its plan to improve the efficiency of the existing natural gas liquids ("NGL") recovery system at its processing facility. It is anticipated that the liquids recovery will increase NGL production in the Hythe area from five barrels per million cubic feet to 20 to 25 barrels per million cubic feet. It is anticipated the liquids recovery upgrade will be operational sometime in the first quarter of 2012.
At Bigstone, industry activity and positive results offsetting the Company's Montney acreage (27 net sections) support acceleration of the Company's Montney drilling plans in the area. It is anticipated the first horizontal well targeting liquids-rich natural gas will spud in October.
Outlook
The Company expects to spend an estimated $80.0 - $85.0 million in 2011, with field capital directed towards drilling opportunities in the Bigstone, Hythe and Wapiti core areas. Guidance for 2011 production volumes remains at 8,800 to 9,200 boe/d.
Delphi expects 2011 AECO natural gas prices to average approximately Cdn. $3.70 per mcf for forecast purposes and towards that end has mitigated downside commodity price risk with an active natural gas hedging program. For the remainder of 2011, the Company is hedged with approximately 61 percent of its natural gas production protected at an average floor price of $4.83 per mcf. This represents a 31 percent premium to the 2011 strip price of $3.69 per mcf. The growth in production of liquids volume, increased hedging and lower operating costs offset by lower natural gas prices are expected to result in cash flow for 2011 of $65.0 to $69.0 million.
Bank debt including working capital is estimated to be between $115.0 million and $120.0 million at December 31, 2011 resulting in a debt to cash flow ratio of approximately 1.8:1.
The Company has grown on the strength of its superior cash generating capabilities, solid reserve base with a comfortable 26 percent annual decline profile and large inventory of robust deep basin liquids-rich natural gas projects. Given the significant drill-ready project inventory, the Company remains focused on the acceleration of its growth profile. An expanded second half drilling program, including a second Montney location, is being evaluated and would be funded by the disposition of certain non-core assets.
On behalf of the Board of Directors and all the employees of Delphi, we would like to thank our shareholders for their continued support as we remain focussed on sustainable, capital efficient growth of the Company's production and reserve base while maintaining the financial strength and flexibility to take advantage of strategic opportunities.
CONFERENCE CALL
A conference call is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Thursday, July 28, 2011. The conference call number is 1-800-355-4959 or 416-695-6616. A brief presentation by David Reid, President and CEO and Brian Kohlhammer, VP Finance & CFO will be followed by a question and answer period.
If you are unable to participate in the conference call, a taped broadcast will be available until August 4, 2011. To access the replay, dial 1-800-408-3053 or 905-694-9451. The passcode is 2823086. Delphi's second quarter 2011 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'S DISCUSSION AND ANALYSIS
(All tabular amounts are stated in thousands of dollars, except per unit amounts)
Management's discussion and analysis ("MD&A") 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 position and results of operations of the Company. Its focus is primarily a comparison of the financial performance for the three and six months ended June 30, 2011 and 2010 and should be read in conjunction with Note 7 of the unaudited interim consolidated financial statements and accompanying notes for the three and six months ended June 30, 2011 and the audited consolidated financial statements and accompanying notes for the years ended December 31, 2010 and 2009. The unaudited interim consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") including International Accounting Standard 34 "Interim Financial Reporting". The reporting currency is the Canadian dollar. The discussion and analysis has been prepared as of July 26, 2011.
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 to the Canadian Securities Administrators' National Instrument 51-101 when boes are disclosed. Boes may be misleading, particularly if used in isolation.
The MD&A contains the terms "funds from operations", "funds from operations per share", "net debt", "cash operating costs" and "netbacks" which are not recognized measures under IFRS. 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-IFRS measure and has been defined by the Company as net earnings plus the add back of non-cash items (depletion and depletion, accretion, stock-based compensation, exploration and evaluation expenses, deferred income taxes, gain on dispositions and unrealized gain/(loss) on financial instruments) and excludes the change in non-cash working capital related to operating activities and expenditures on decommissioning obligations. 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 IFRS. The Company has defined net debt as the sum of long term debt plus/minus working capital excluding the current portion of deferred income taxes and fair value of financial instruments. 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 expense, general and administrative expenses and cash finance costs.
DELPHI'S OPERATIONS
What is the nature of Delphi's business and where are its operations?
Delphi Energy Corp. ("Delphi" or "the Company") is a publicly-traded company with its corporate office in Calgary, Alberta, Canada. Delphi is engaged in the exploration for, development and production of crude oil and natural gas from properties and assets located in Western Canada in which it holds an interest. The Company's operations are primarily concentrated in the Deep Basin of North West Alberta, representing in excess of 90 percent of the Company's production. The Company has three primary core areas in the Deep Basin located at Bigstone, Hythe and Wapiti/Gold Creek.
SECOND QUARTER 2011 ACCOMPLISHMENTS
What were the highlights of Delphi's operations in the second quarter of 2011?
In the second quarter of 2011, the Company achieved the following:
- achieved average production of 8,906 barrels of oil equivalent per day ("boe/d"), an increase of eleven percent compared to the second quarter of 2010;
- increased the liquids percentage of production to approximately 30 percent crude oil and natural gas liquids in the second quarter of 2011, up from 20 percent in the second quarter of 2010;
- generated funds from operations ("cash flow") of $17.5 million, an increase of 40 percent from the comparative quarter of 2010;
- achieved a cash netback of $21.60 per boe, achieving the Company's objective of maintaining a cash netback of at least $20.00 per boe in this low natural gas price environment;
- reduced operating costs by 17 percent to $6.63 per boe in the second quarter of 2011 from $7.95 per boe in the comparative quarter of 2010;
- realized $2.1 million in hedging gains on natural gas contracts while incurring $0.6 million of hedging losses on a crude oil call option;
- rig released 3 (2.5 net) wells late in the quarter as part of a start to the summer capital program; and
- increased the Company's credit facilities from $140.0 million to $145.0 million based upon the Company's reserves growth in the December 31, 2010 year end engineering report and the successful first quarter of 2011 capital program.
Cash flow in the second quarter of 2011 was $17.5 million or $0.15 per basic share, compared to $12.5 million or $0.12 per basic share in the comparative quarter of 2010. The growth in cash flow in 2011 over 2010 was primarily a result of the continued reduction in operating costs, higher production, change in production mix towards higher netback crude oil and natural gas liquids and the increase in realized oil prices offset by the decrease in realized natural gas prices.
In the second quarter of 2011, operating costs before processing income were $0.4 million lower than the comparative quarter despite average production growth of eleven percent over the same time. The fixed costs associated with owned natural gas plant infrastructure, field compression facilities and pipelines continue to be allocated over more production volumes resulting in lower marginal costs of new production. The Company continues to focus production growth in its core areas where operating costs were less than $6.00 per boe on a weighted average basis. The Company's operating costs were reduced by $1.32 per boe to $6.63 per boe in the second quarter of 2011, 17 percent lower than the comparative period. For the six months ended June 30, 2011, operating costs were $6.70 per boe compared to $8.31 per boe for the comparative period of 2010.
For the three and six months ended June 30, 2011, the Company recognized approximately $1.5 million and $3.3 million in realized gains on financial and physical hedging contracts providing significant stability to the Company's cash flow.
The combination of the above highlighted items resulted in Delphi's financial position continuing to remain strong at the end of the second quarter of 2011, providing the financial flexibility to execute the second half of the 2011 capital program. At June 30, 2011, the Company had net debt of $108.3 million on total credit facilities of $145.0 million, providing excess financial capacity of approximately $36.7 million. On an annualized, second quarter funds from operations basis, Delphi's net debt to cash flow ratio was 1.5:1. Net debt includes bank debt plus working capital deficiency excluding the fair value of financial instruments.
FINANCIAL STRATEGIES
Are there financial strategies the Company employs to achieve results and forecast expectations?
The Company maintains an active risk management program as an integral part of its overall financial strategy to mitigate volatility in cash flow 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 and light crude oil market. The transactions are generally undertaken for contract terms 12 to 24 months in advance with financially strong counterparties and are predominantly executed on a physical basis with the Company's natural gas purchaser. Delphi's risk management program consists of fixed price contracts, costless collars, participating swaps and puts and calls which provide downside protection. Costless collars, participating swaps and puts also provide the opportunity to share in the upside if market prices increase above the floor price. 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 production as long as demand/supply fundamentals indicate volatile markets in the future.
Delphi continues to direct efforts at maintaining or reducing its controllable costs. Increasing production at its operating fields which are processed through Company owned infrastructure reduces facility 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 major repairs. The Company strives to achieve improvement in its costs of production and at a minimum maintain current production costs while growing production.
Maintaining or improving strong operating netbacks per boe through the risk management program and the control of costs associated with production operations and corporate overhead, 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.
As a result of the significant difference in netbacks between crude oil and natural gas, the Company's capital expenditures have been allocated more towards light oil and liquids-rich natural gas opportunities. By altering the Company's production mix, there is greater certainty of achieving the Company's cash flow expectations due to the higher netback crude oil and natural gas liquids production.
The annual net capital expenditure program in the field will continue to approximate forecast cash flow. 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.
2011 OUTLOOK AND FORWARD-LOOKING INFORMATION
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 MD&A are made as of July 26, 2011 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.
Delphi's operational and financial expectations for 2011 are based upon the Company's projection of drilling plans, drilling success and production results and the estimated related revenues and associated costs of royalties, transportation expenses, operating costs, general and administrative expenses and interest costs. Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply and demand forecasts and publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of material variances from previously communicated expectations.
OPERATIONS
How many wells does Delphi expect to drill in 2011?
Delphi expects to drill 25 gross wells (19.4 net) in 2011 focused in its core areas of Bigstone, Hythe and Wapiti/Gold Creek. In Bigstone and Hythe, drilling will primarily be horizontal wells directed at light oil opportunities in the Cardium formation and Doe Creek formation, respectively. At Wapiti/Gold Creek, the drilling will primarily be directed at vertical multi-zone opportunities with the liquids-rich Nikanassin formation being the primary target. The factors that may hinder Delphi from achieving its drilling plans include the availability of drilling rigs and equipment needed at the drill site, timely receipt of well licenses and permits and approval by the landowners for surface access to the location.
What are the Company's production expectations?
Delphi expects production from crude oil, natural gas and natural gas liquids to average between 8,800 to 9,200 boe/d in 2011, up eleven percent from an average of 8,086 boe/d in 2010. The production mix is expected to be approximately 27 percent light oil and liquids-rich natural gas in 2011, compared to 20 percent in 2010, as the capital program focuses on light oil and liquids-rich natural gas drilling opportunities. These production and sales mix expectations may not be achieved if decline rates are greater than expected, the new wells do not perform as expected, drilling plans are delayed for the reasons outlined above, completion and tie-in of new wells is delayed due to weather or the unavailability of the required service equipment in the field, mechanical failure of field equipment, delays in accessing production facilities or additional waiting time for any approvals.
REVENUES
What does the Company project for crude oil and natural gas prices in 2011?
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 primarily influenced by North American, rather than global, supplies of natural gas versus domestic demand for winter heating and cooling demand for the summer. 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, primarily in periods of a shortfall in supply. In addition, multi-stage fracturing technology has unlocked the significant natural gas resource potential of numerous shale basins in North America capable of initially producing at very high rates of natural gas.
For forecasting purposes, Delphi continues to expect a challenging natural gas market for 2011 as a result of strong natural gas production in the United States through horizontal drilling using multi-stage fracturing technology into the shale gas plays. Delphi is expecting AECO to average $3.70 per mcf in 2011.
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 Canadian/United States ("Cdn/US") dollar exchange rate. The fundamental supply/demand equation for crude oil is more balanced on a daily basis than natural gas due to consistent demand for crude oil of approximately 88 million barrels per day to meet the global requirement for energy. The price of crude oil can also be influenced significantly by geopolitical events in the major oil exporting countries of the world and the strength or weakness of the global economies.
Delphi continues to believe that oil prices will remain at current levels for the remainder of the year. For forecasting purposes, the Company believes WTI will average U.S. $96.50 per barrel in 2011.
Canadian/United States Exchange Rate
Both crude oil and natural gas prices in Canada are premised on the U.S. dollar price for each product adjusted for the Cdn/US dollar exchange rate and quality and transportation differentials. The strength or weakness of the Canadian dollar versus the U.S. dollar will largely reflect the global demand for raw materials, particularly metals, minerals and crude oil. The global financial markets tolerance for risk and its need for financial security in the form of holding U.S dollars will also have an effect on the value of the Canadian dollar against the U.S. dollar. Delphi believes the Canadian dollar will remain quite strong relative to the U.S. dollar in 2011 as global economies continue to recover from the slowdown since 2008.
The Canadian dollar is now expected to trade slightly better than parity with the U.S. dollar in 2011. The exchange rate is influenced by many variables which will continue to result in significant volatility. Delphi has assumed an average exchange rate of $0.96 Cdn. to U.S. dollar.
Has Delphi undertaken any hedges for 2011 and 2012 to mitigate the risk of volatility in its product pricing?
In light of the low natural gas prices over the past two years and a future outlook which has resulted in the forward price curve for natural gas to decrease based on the view that there is ample supply of natural gas with the development of the shale gas plays, particularly in the United States, Delphi has become more focused on protecting the downside of prices as opposed to locking in gains to be made on unusually high prices. Currently, Delphi has hedged approximately 61 percent of its before-royalty natural gas production at a predominantly AECO based average floor price of $4.83 per mcf for the remainder of 2011. This compares to the forward strip commodity price for AECO of $3.69 per mcf for the remainder of 2011 as of July 18, 2011. Delphi continually monitors the variables affecting the price of natural gas and crude oil in order to ensure its capital program is in line with expected funds from operations. The following natural gas hedges are in place to support the Company's cash flow.
Jul-Sep Oct-Dec
2011 2011 2012
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Production hedged (mmcf/d) 25.4 19.8 2.3
Percentage of natural gas production(1) 69% 53% 6%
Price floor (Cdn $/mcf) $4.76 $4.88 $ 4.70
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(1) based on 37 mmcf/d
The Company has also executed a call option at U.S. $90.00 on 600 bbls/d for January 1, 2011 to December 31, 2012. The fair value of outstanding natural gas contracts is estimated to be a gain of approximately $2.6 million with a loss of approximately $5.0 million on outstanding crude oil contracts as of July 18, 2011.
ROYALTIES
What average royalty rate does Delphi expect to pay in 2011?
The Company pays royalties to provincial governments, individuals and companies that own surface and/or mineral rights. These payments take the form of Crown, freehold and overriding royalties. Crown royalty rates for crude oil and natural gas are generally calculated on a sliding scale based on commodity prices and production rates whereas freehold and overriding royalty rates are generally a fixed percentage of revenue. Crown royalty rates can change due to price fluctuations or changes in production volumes on a well by well basis subject to minimum and maximum rates. For natural gas liquids, Crown royalty rates are a fixed percentage of revenue with the rate varying according to the nature of the product. Crown royalty credits are received from the Crown and represent the fee earned by the owners of natural gas processing infrastructure to process the Crown's royalty share of natural gas. Freehold royalties are paid on freehold lands and overriding royalties are generally payable on lands where the Company has earned an interest in the lands through a farm-in, whether the lands are Crown or freehold. Royalties are not affected by gains or losses realized through the Company's risk management program.
For 2011, Delphi expects its royalty rate, after the deduction for royalty credits, will average between 14 to 17 percent of gross revenue, excluding realized and unrealized gains or losses on financial instruments.
TRANSPORTATION EXPENSES AND OPERATING COSTS
Will Delphi be able to further reduce its costs of production in 2011?
Transportation expenses are costs incurred by the Company to transport its production volumes from the wellhead to the point of sales. 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.
Delphi expects its transportation expenses to be approximately $2.50 - $2.75 per boe in 2011. Transportation expenses are subject to the availability of pipeline capacity on an interruptible basis in areas of significant production growth by industry.
Operating costs have been trending downward over the past several years as Delphi focuses its capital program and achieves growth in its core areas of Bigstone, Hythe and Wapiti/Gold Creek, all areas with an operating cost structure of less than $6.00 per boe. As production grows and fixed area costs are allocated over increased production volumes, the marginal cost of incremental production is expected to be less than field average operating cost. In 2011, Delphi will also realize the full year benefit of the 2010 disposition of very high operating cost production in East Central Alberta.
The costs of production may be more than expected in periods of very high industry activity causing considerable competition and rising prices for general oilfield services and equipment, however, further reductions in operating costs are anticipated resulting in expected operating costs averaging between $6.50 and $6.75 per boe in 2011.
GENERAL & ADMINISTRATIVE AND FINANCE COSTS
What are the Company's overhead costs for personnel and financing?
In 2011, Delphi anticipates its general and administrative costs, net of capitalized amounts, to be approximately $2.00 per boe. A high level of industry activity may cause an increase in general and administrative expenses due to higher than expected employee retention costs and to hire new employees and general cost inflation.
Interest costs will be dependent on market rates and credit spreads for the oil and gas sector and will be a function of the general economic conditions in Canada. If the economy is viewed as growing too fast, which may result in inflation, interest rates may be increased to slow down the pace of growth in the economy. Interest costs may also increase if cash flow from operations is less than expected and bank debt is used to fund a larger portion of the capital program than originally anticipated. Interest expense is expected to be approximately $1.75 per boe in 2011.
CAPITAL PROGRAM AND NET DEBT LEVELS
What are the Company's forecast capital expenditures and net debt levels for 2011?
In 2011, Delphi anticipates a field capital program of approximately $80.0 - 85.0 million resulting in net debt levels between $115.0 and $120.0 million by the end of 2011. Growth in cash flow to approximately $65.0 to $69.0 million is expected to result in a net debt to cash flow ratio of approximately 1.8:1 at the end of 2011.
Capital expenditures for the second half of the year will be planned according to the cash flow generated and achieving net debt targets.
BUSINESS ENVIRONMENT
What external factors of the business environment did the Company have to contend with in the second quarter of 2011?
The price the Company receives for its production volumes is a significant determinant of the Company's cash flow. The table below outlines the changes in the various benchmark commodity prices and economic parameters which affect the prices received for the Company's production.
Benchmark Prices and Economic Parameters
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Natural Gas
NYMEX (US $/mmbtu) 4.37 4.32 1 4.28 4.73 (10)
AECO (CDN $/mcf) 3.87 3.89 - 3.83 4.42 (13)
Crude Oil
West Texas Intermediate
(US $/bbl) 102.55 77.99 31 98.39 78.39 26
Edmonton Light (CDN $/bbl) 103.05 75.13 37 95.62 77.59 23
Foreign Exchange
Canadian to U.S. dollar 0.97 1.03 (6) 0.98 1.03 (5)
U.S. to Canadian dollar 1.03 0.97 6 1.02 0.97 5
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Natural Gas
AECO averaged $3.87 per mcf in the second quarter of 2011, virtually unchanged from the comparative period. For the six months ended June 30, 2011, AECO was 13 percent lower than the same period of 2010.
Crude Oil
WTI averaged U.S. $102.55 per barrel in the second quarter of 2011, an increase of 31 percent over the second quarter of 2010. As a result of a narrowing basis differential, Canadian prices were 37 percent higher in the second quarter of 2011 over the comparative period of 2010. Edmonton light averaged $103.05 per barrel in the second quarter of 2011 versus $75.13 per barrel in 2010.
Canadian/United States Exchange Rate
The value of the Canadian dollar against its U.S. counterpart continued to strengthen in the second quarter of 2011 as crude oil prices breached U.S. $100.00 per barrel and the concerns over the U.S. government's total debt were raised. As a producer of crude oil, a stronger Canadian dollar has had a negative effect on the price received for production. The Cdn/US exchange rate varied from a high of $0.95 to a low near $0.99 late in the second quarter. This negative effect to the price of oil for Canadian producers was offset by a narrowing basis differential between U.S. and Canadian markets.
Industry Cost of Services
The increase in crude oil prices and the demand to drill horizontal oil and natural gas wells using multi-stage fracturing technology has resulted in drilling contractors and oilfield service companies becoming very busy. Natural gas drilling has become more focused on liquids-rich natural gas opportunities with continued strong demand for high deliverability natural gas wells in the Canadian shale gas plays, predominantly the Montney formation. Consequently, there has been pricing pressure on drilling equipment capable of completing these types of operations. Completion services have also tightened up as more and more horizontal drilling is undertaken with the intention of completing the wells using multi-stage fracturing technology.
OPERATIONAL AND FINANCIAL RESULTS
DRILLING OPERATIONS
How active was Delphi in its drilling program in the second quarter of 2011?
Capital activity in the second quarter primarily included the completion of several projects from the first quarter capital program and the commencement of the second half of 2011 capital program. Start up of the program was delayed due to weather, however, the Company did complete drilling operations on three wells before the end of the quarter. In light of continued low natural gas prices, the Company focused its efforts on drilling light oil and liquids-rich natural gas opportunities in the quarter.
Three Months Ended Six Months Ended
June 30, 2011 June 30, 2011
Gross Net Gross Net
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Liquids-rich natural gas wells 2.0 1.5 10.0 8.7
Oil wells 1.0 1.0 6.0 4.2
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Total wells 3.0 2.5 16.0 12.9
Success rate (%) 100 100 100 100
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CAPITAL INVESTED
How much did the Company spend in the second quarter and first six months of 2011 and where were the capital expenditures incurred?
The Company continued to direct its capital program at its core areas in North West Alberta to take advantage of the multi-zone nature of these assets, low production operating costs and quick on-stream capability associated with owned gathering and processing infrastructure. Total capital invested in the field during the second quarter was $9.5 million as equipping and facility costs were incurred to complete the winter program and the summer drilling program commenced. For the six months ended June 30, 2011, Delphi incurred capital expenditures of $43.8 million, with approximately 69 percent directed at drilling and completion operations and 26 percent incurred on equipping and facility projects.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Land 188 1,329 (86) 420 3,833 (89)
Seismic 151 8 1,788 151 131 15
Drilling and
completions 5,197 706 636 30,068 27,688 9
Equipping and
facilities 3,093 4,712 (34) 11,352 8,862 28
Capitalized expenses 552 636 (13) 1,263 1,436 (12)
Other 361 231 56 585 770 (24)
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Capital invested 9,542 7,622 25 43,839 42,720 3
Disposition of
properties (63) (251) (75) (336) (251) 34
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Net capital invested 9,479 7,371 29 43,503 42,469 2
Acquisition of
properties - (307) (100) 87 385 (77)
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Total capital invested 9,479 7,064 34 43,590 42,854 2
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PRODUCTION
What factors contributed to the growth in production volumes and the success in growing oil and natural gas liquids volumes?
Production for the three months ended June 30, 2011 averaged 8,906 boe/d, representing an increase of eleven percent over the comparative period due to the successful drilling and optimization programs at Bigstone, Hythe and Wapiti/Gold Creek. With the continued low natural gas pricing, Delphi's 2010/2011 drilling program primarily targeted opportunities in its crude oil and liquids-rich natural gas inventory to maximize netbacks. For the three months ended June 30, 2011, production growth is highlighted by a 65 percent increase in crude oil and natural gas liquids compared to the second quarter of 2010. 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 second quarter was weighted 70 percent to natural gas, 15 percent to crude oil and 15 percent to natural gas liquids. For the six months ended June 30, 2011, production was weighted 72 percent to natural gas, 14 percent to crude oil and 14 percent to natural gas liquids.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Natural gas (mcf/d) 37,460 38,540 (3) 36,987 38,445 (4)
Crude oil (bbls/d) 1,346 1,074 25 1,225 910 35
Natural gas liquids
(bbls/d) 1,317 538 145 1,195 523 128
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Total (boe/d) 8,906 8,035 11 8,585 7,841 9
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Crude oil production in the second quarter was 25 percent higher than the comparative period. The increase in oil production is due to the successful horizontal drilling targeting Cardium light oil at Bigstone and the Doe Creek light oil at Hythe.
Natural gas liquids were 145 percent higher for the quarter primarily due to the increased natural gas liquids production in the Wapiti/Gold Creek area where the Company has been successfully drilling multi-zone vertical wells with the Nikanassin formation as the primary target.
Natural gas production was three percent lower compared to the second quarter of 2010 due to a reduction in capital directed at natural gas opportunities.
REALIZED SALES PRICES
What were the sales prices realized by the Company for each of its products?
For the three months ended June 30, 2011, Delphi's risk management program realized a gain of $1.5 million. For the quarter, the realized gain on natural gas contracts was $0.63 per mcf with physical contracts contributing a gain of $0.18 per mcf and financial contracts contributing a gain of $0.45 per mcf. The gains were lower than the comparative periods due to the change in the forward curve for natural gas prices at the time the contracts were executed. Overall natural gas prices were ten percent lower in the second quarter of 2011 than the comparative period in 2010, primarily due to the reduced gains realized on natural gas contracts. For crude oil, the Company lost $5.55 per barrel on a call option as part of a cross commodity swap. The value of the call, at the time it was undertaken, was used to purchase a higher price on a natural gas contract. Realized crude oil prices were 21 percent higher in the second quarter of 2011, principally due to a 37 percent increase in the price of Canadian benchmark crude prices and an upgrade of the Company's crude quality.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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AECO ($/mcf) 3.87 3.89 (1) 3.83 4.42 (13)
Heating content and
marketing ($/mcf) 0.26 0.21 24 0.23 0.33 (30)
Gain on physical
contracts ($/mcf) 0.18 0.90 (80) 0.33 0.86 (62)
Gain on financial
contracts ($/mcf) 0.45 0.30 50 0.30 0.16 88
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Realized natural gas
price ($/mcf) 4.76 5.30 (10) 4.69 5.77 (19)
Edmonton Light ($/bbl) 103.05 75.13 37 95.62 77.59 23
Gain (loss) on financial
contracts ($/bbl) (5.55) 1.11 - (4.15) 0.66 -
Quality differential
($/bbl) (2.89) 1.90 - (0.58) (0.83) (30)
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Realized oil price
($/bbl) 94.61 78.14 21 90.89 77.42 17
Realized natural gas
liquids price ($/bbl) 44.02 54.56 (19) 48.56 57.88 (16)
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Total realized sales
price ($/boe) 41.35 39.83 4 40.34 41.32 (2)
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Delphi's oil production has changed from a mix of light and medium oil to predominantly light oil therefore the Company's average price for crude oil, since mid 2010, will generally fluctuate with the change in the benchmark crude oil prices. With the disposition of the East Central Alberta properties in the second quarter of 2010, 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.
Natural gas liquids prices in the second quarter of 2011 were 19 percent lower than the second quarter of 2010.
How do the realized natural gas prices compare to the benchmark AECO pricing?
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 5.5 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 Delphi realized on its natural gas price 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 been a premium to AECO.
Jun. Mar. Dec. Sept. Jun. Mar. Dec. Sept.
30 31 31 30 30 31 31 30
2011 2011 2010 2010 2010 2009 2009 2009
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Natural Gas Price
Delphi realized
($/mcf) 4.76 4.62 5.00 5.28 5.30 6.26 6.15 5.77
AECO average ($/mcf) 3.87 3.80 3.64 3.54 3.89 4.96 4.49 2.94
Premium to AECO 23% 22% 37% 49% 36% 26% 37% 96%
Hedging gain
($000's) 2,142 2,126 4,045 4,676 4,186 2,941 4,498 7,973
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RISK MANAGEMENT ACTIVITIES
What is Delphi's risk management strategy and what contracts are in place to mitigate the risk of volatility?
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. For natural gas production, Delphi has hedged approximately 61 percent of its before-royalty natural gas production at a predominately AECO based average floor price of $4.83 per mcf for the remainder of 2011.
With respect to financial contracts, which are derivative financial instruments, management has elected not to use hedge accounting and consequently records the fair value of its natural gas and crude oil financial contracts on the balance sheet at each reporting period with the change in the fair value being classified as unrealized gains and losses in the statement of operations. Physical commodity sale contracts based in U.S. dollars include an embedded derivative associated with the foreign exchange rate. Due to this derivative, the changes in the fair value of these contracts are included in the statement of earnings.
As of July 26, 2011, the Company has fixed the price applicable to future production through the following contracts.
Type of Quantity Contract Price
Time Period Commodity Contract Contracted ($/unit)
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January 2011 -
December 2011 Natural Gas Physical 2,500 GJ/d $3.79 fixed
January 2011 -
December 2011(1) Natural Gas Financial 2,500 GJ/d $7.14 call
January 2011 -
December 2011(3) Natural Gas Financial 3,000 GJ/d $4.00 put
January 2011 -
December 2011(4) Natural Gas Physical 2,500 GJ/d $4.12 fixed
January 2011 -
December 2012(2) Crude Oil Financial 600 bbls/d U.S. $90.00 call
April 2011 -
October 2011 Natural Gas Physical 2,000 GJ/d $5.66 fixed
April 2011 -
October 2011 Natural Gas Physical 4,000 GJ/d $3.80 fixed
April 2011 -
October 2011 Natural Gas Financial 2,000 GJ/d $3.82 fixed
April 2011 -
October 2011 Natural Gas Financial 2,000 GJ/d $3.79 fixed
April 2011 -
December 2011(2) Natural Gas Financial 6,810 GJ/d $5.69 fixed
April 2011 -
December 2011 Natural Gas Physical 2,000 GJ/d U.S. $4.52 fixed
November 2011 -
March 2012 Natural Gas Physical 1,000 mmbtu/d U.S. $5.14 fixed
January 2012 -
December 2012(3) Natural Gas Financial 3,000 GJ/d $4.50 call
January 2012 -
December 2012(4) Natural Gas Physical 2,500 GJ/d $4.50 call
April 2012 -
October 2012 Natural Gas Physical 1,000 mmbtu/d U.S. $4.96 fixed
April 2012 -
October 2012 Natural Gas Physical 2,000 GJ/d $4.06 fixed
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(1) The Company had 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.
(2) The Company has acquired a natural gas contract at $5.69 per gigajoule
on 6,810 gigajoules per day for the period April 1, 2011 through
December 31, 2011. This contract was paid for with the sale of a crude
oil call on 600 barrels per day at a price of U.S. $90.00 WTI per barrel
for the period January 1, 2011 through December 31, 2012.
(3) The Company has acquired a natural gas put contract at $4.00 per
gigajoule on 3,000 gigajoules per day for the period January 1, 2011
through December 31, 2011. This put was paid for with the sale of a
natural gas call on 3,000 gigajoules per day at a price of $4.50 per
gigajoule for the period January 1, 2012 through December 31, 2012.
(4) The Company has acquired a natural gas contract at $4.12 per gigajoule
on 2,500 gigajoules per day for the period January 1, 2011 through
December 31, 2011. This contract was paid for with the sale of a
natural gas call on 2,500 gigajoules per day at a price of $4.50 per
gigajoule for the period January 1, 2012 through December 31, 2012.
The Company recognized an unrealized gain on its financial contracts of $2.3 million in the second quarter of 2011, primarily due to the crude oil call option. 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 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
How do revenues in the second quarter of 2011 compare to 2010 and what factors contributed to the change?
For the three months ended June 30, 2011, Delphi generated revenue of $32.7 million representing a 17 percent increase over the comparative quarter of 2010. The composition of revenue by product for the six months ended June 30, 2011 changed significantly versus the comparative period. For the six months ended June 30, 2011, natural gas revenues accounted for 48 percent of total revenue versus 68 percent in the comparative period in 2010. Crude oil and natural gas liquids represented 51percent of revenue in 2011 versus 32 percent in the same period in 2010. The change in mix is a combination of prices received for the products whereby realized natural gas prices decreased while crude oil prices increased and the growth in production volume of the products.
The risk management program associated with natural gas and crude oil pricing generated revenue of $3.3 million in the first six months of 2011. For twelve consecutive quarters, Delphi has received a significant premium to AECO pricing primarily due to the success of the risk management program.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Natural gas 14,077 14,361 (2) 27,119 33,011 (18)
Natural gas physical
contract gains 619 3,140 (80) 2,241 6,018 (63)
Crude oil 12,277 7,575 62 21,079 12,643 67
Natural gas liquids 5,277 2,666 98 10,504 5,479 92
Sulphur 428 228 88 634 275 131
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Total 32,678 27,970 17 61,578 57,426 7
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ROYALTIES
What were royalty costs in the second quarter of 2011?
In the second quarter of 2011, the Company paid Crown, freehold and gross overriding royalties. Crown royalties of $4.6 million were partially offset by $1.4 million of royalty credits for processing the Crown's share of natural gas with the net amount of $3.2 million representing 66 percent of the total royalties paid in the quarter compared to 76 percent in the same quarter of 2010. The net Crown royalties increased in 2011 compared to 2010 primarily as a result of higher crude oil commodity prices in 2011, the Company's significant increase in crude oil and natural gas liquids production.
Gross overriding royalties represented 33 percent of total royalties in the second quarter of 2011 compared to 22 percent in 2010. The increase in gross overriding royalties is primarily a result of higher crude oil prices and higher production volumes encumbered by gross overriding royalties.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Crown royalties 4,558 4,296 6 9,142 9,028 1
Royalty credits (1,396) (693) 101 (2,789) (2,817) (1)
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Crown royalties - net 3,162 3,603 (12) 6,353 6,211 2
Freehold royalties 54 95 (43) 54 166 (67)
Gross overriding
royalties 1,555 1,021 52 2,633 2,156 22
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Total 4,771 4,719 1 9,040 8,533 6
Per boe 5.89 6.45 (9) 5.82 6.01 (3)
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What were the average royalty rates paid on production in the second quarter of 2011?
The average royalty rates were slightly lower than the comparative period. Crown royalty rates were 32 percent lower primarily as a result of increased royalty credits in 2011 compared to 2010. Overriding royalties increased primarily as a result of growth in production from wells encumbered by an overriding royalty.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Crown rate - net of
royalty credits 9.9% 14.5% (32) 10.7% 12.1% (12)
Gross overriding rate 4.9% 4.1% 20 4.4% 4.2% 5
Average rate 14.9% 19.0% (22) 15.2% 16.6% (8)
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The royalty rate calculations above exclude gains or losses on risk management activities from revenue as the denominator.
OPERATING EXPENSES
How has the Company been able to reduce its operating expenses in 2011 as compared to 2010?
Operating costs for the three months ended June 30, 2011, decreased seven percent over the comparative period and were ten percent lower for the six months ended June 30, 2011. The Company accumulated new and additional infrastructure in its core areas during 2009 which allows for lower per boe operating costs as production volumes continue to increase. Additionally, the disposition of the East Central Alberta properties in the second quarter of 2010 provided a decrease in absolute costs. Operating costs in the second quarter of 2011 were $6.63 per boe which represents a 17 percent decrease over the $7.95 per boe experienced in 2010. For the six months ended June 30, 2011, operating costs per boe were 19 percent lower than the comparative period of 2010. The decrease is attributed to lower field operating costs, the disposition of the East Central Alberta properties as well as increased volumes from the cost efficient core areas of Hythe, Wapiti/Gold Creek and Bigstone.
The Company earns processing income on third party production volumes going through facilities owned by Delphi. The processing income represents a reduction of the Company's costs to operate these facilities and hence is deducted in determining operating expenses. Processing income indicates the Company has excess capacity at its facilities which it can access to handle growth in its production volumes. Processing income was slightly higher in the three and six months ended June 30, 2011 than the comparative period of 2010 by two and four percent, respectively.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Production costs 6,036 6,464 (7) 11,684 13,027 (10)
Processing income (665) (654) 2 (1,280) (1,232) 4
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Total 5,371 5,810 (8) 10,404 11,795 (12)
Per boe 6.63 7.95 (17) 6.70 8.31 (19)
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TRANSPORTATION EXPENSES
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Total 2,269 2,474 (8) 4,481 4,670 (4)
Per boe 2.80 3.38 (17) 2.88 3.29 (12)
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What factors contributed to the change in transportation costs in 2011?
On a per boe basis, transportation costs for the three months ended June 30, 2011, decreased by 17 percent over the comparative period and were twelve percent lower for the six months ended June 30, 2011. The decrease in transportation costs per boe is primarily due to the growth in production volumes resulting in the allocation of fixed transportation costs over more volumes.
GENERAL AND ADMINISTRATIVE
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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General and
administrative costs 4,194 3,468 21 6,895 5,901 17
Overhead recoveries (373) (395) (6) (825) (950) (13)
Salary allocations (1,532) (787) 95 (2,573) (1,532) 68
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Net 2,289 2,286 - 3,497 3,419 2
Per boe 2.82 3.13 (10) 2.25 2.41 (7)
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How do general and administrative costs in 2011 compare to 2010?
An increase in personnel costs due to an expansion of the technical teams were offset by increased salary allocations and growth in production volumes resulting in costs per boe decreasing over the comparative periods. On a per boe basis, general and administrative (G&A) costs were down by ten percent in the second quarter of 2011 compared to the second quarter of 2010. On the same comparative basis for the six months ended June 30, G&A costs per boe were down seven percent. Delphi is committed to delivering strong growth and believes a strong team is paramount to achieve this goal.
SHARE-BASED COMPENSATION
What is share-based compensation expense?
Share-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.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Share-based compensation 356 430 (17) 536 646 (17)
Capitalized costs (25) (79) (68) (39) (202) (81)
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Net 331 351 (6) 497 444 12
Per boe 0.41 0.48 (15) 0.32 0.31 3
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The share-based non-cash compensation expense for the three months ended June 30, 2011, decreased 17 percent over the comparative period. The decrease is attributed to the vesting of options in the first quarter and a longer vesting period for options granted to employees in the second quarter. During the three months ended June 30, 2011, Delphi capitalized $25,000 of share-based compensation associated with exploration and development activities.
FINANCE COSTS
How do the costs of borrowing compare against the prior period?
For the three months ended June 30, 2011, interest costs were two percent lower than the comparative period.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Interest 1,303 1,329 (2) 2,683 2,671 -
Accretion 138 129 7 279 267 4
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Total 1,441 1,458 (1) 2,962 2,938 1
Interest per boe 1.61 1.82 (12) 1.73 1.88 (8)
Accretion per boe 0.17 0.18 (6) 0.18 0.19 (5)
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During 2009, the Company converted $80.0 million of its outstanding long term debt from prime-based loans to bankers' acceptances. At June 30, 2011, the bankers' acceptances have terms ranging from 60 to 92 days and a weighted average effective interest rate of 3.97 percent over the term.
What is accretion expense and how did this expense for 2011 compare to 2010?
The accretion of decommissioning obligations is an expense that 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 used a risk-free interest rate of three percent for the purpose of calculating the fair value of its decommissioning obligations and hence the accretion expense. The accretion expense for the three months ended June 30, 2011 increased seven percent over the comparative period.
DEPLETION AND DEPRECIATION
Has the Company's depletion and depreciation rate and expense changed in the second quarter of 2011 compared to the comparative period?
Depletion and depreciation per boe for the three months ended June 30, 2011 decreased one percent over the comparative period. With continued drilling success at Bigstone, Hythe and Wapiti/Gold Creek, Delphi has been able to add proved plus probable reserves at a cost very similar to the Company's current depletion rate. The increase in total depletion and depreciation was a result of increased production volumes.
In the first six months ended June 30, 2010, the Company recorded an impairment loss of $5.0 million on a non-core cash generating unit as a result of declining natural gas prices.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
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Depletion and depreciation 11,522 10,541 9 22,123 20,509 8
Impairment loss - - - - 5,000 (100)
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Total 11,522 10,541 9 22,123 25,509 (13)
Per boe 14.22 14.42 (1) 14.24 17.98 (21)
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INCOME TAXES
What was the affect on deferred income taxes as a result of the earnings for the period?
The provision for deferred income taxes in the financial statements for the three months ended June 30, 2011 was an expense of $2.2 million. Delphi does not anticipate it will be cash taxable before 2014.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
----------------------------------------------------------------------------
Current - - - - - -
Future 2,150 198 986 2,361 1,574 50
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Total 2,150 198 986 2,361 1,574 50
Per boe 2.65 0.27 881 1.52 1.11 37
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FUNDS FROM OPERATIONS
What are funds from operations and why is it a key performance measure?
Funds from operations is a non-IFRS measure that has been defined by the Company as net earnings (loss) plus the add back of non-cash items (depletion and depreciation, accretion, stock-based compensation, gain on disposition, deferred income taxes and unrealized gain (loss) on the fair value of financial instruments) and excludes the accretion of long term debt, change in non-cash working capital related to operating activities and expenditures on decommissioning obligations. Delphi uses funds from operations ("cash flow") 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 to grow the Company's value for the shareholders and to repay debt.
How do funds from operations in the second quarter of 2011 compare to 2010?
For the three months ended June 30, 2011, funds from operations were $17.5 million ($0.15 per basic share) compared to $12.5 million ($0.12 per basic share) in the comparative period. The increase in funds from operations is primarily a result of an increase in production volumes, a reduction in operating costs and higher realized sales price per boe.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
----------------------------------------------------------------------------
Net earnings 5,757 131 4,295 6,719 1,744 285
Non-cash items:
Depletion and
depreciation 11,522 10,541 9 22,123 25,509 (13)
Accretion of
decommissioning
obligations 138 129 7 279 267 4
Gain on disposition (63) - 100 (336) - 100
Unrealized loss on
risk management
activities (2,318) 1,199 - 935 (2,238) -
Stock-based
compensation expense 331 351 (6) 497 444 12
Exploration and
evaluation - (42) 100 - 256 100
Deferred income taxes 2,150 198 986 2,361 1,574 50
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Funds from operations 17,517 12,507 40 32,578 27,556 18
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----------------------------------------------------------------------------
How do funds from operations compare to cash flow from operating activities in the financial statements?
Funds from operations reflect two primary differences from the IFRS term cash flow from operating activities shown on the financial statements. These differences are expenditures incurred for decommissioning obligations, changes in non-cash operating working capital and accretion of long term debt. The following table is a reconciliation of funds from operations to cash flow from operating activities for the three and six months ended June 30, 2011 and 2010.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
----------------------------------------------------------------------------
Funds from operations:
Non-IFRS 17,517 12,507 40 32,578 27,556 18
Accretion of long term
debt (626) - 100 (405) - 100
Change in non-cash
working capital 1,858 5,796 (68) (1,648) 1,768 (193)
----------------------------------------------------------------------------
Cash flow from
operating activities:
IFRS 18,749 18,303 2 30,525 29,324 4
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----------------------------------------------------------------------------
NET EARNINGS
What factors contributed to the earnings in 2011?
For the three and six months ended June 30, 2011, Delphi recorded net earnings of $5.8 million ($0.05 per basic share) and $6.7 million ($0.06 per basic share), respectively. Net earnings were achieved primarily due to cash netbacks of $21.60 per boe on production being greater than an average depletion rate of $14.22 per boe. Net earnings were further reduced by the negative impact of unrealized losses on risk management activities, stock-based compensation, accretion on decommissioning liabilities and future income taxes. These non-cash items represent the majority of the significant difference between funds from operations and net earnings.
NETBACK ANALYSIS
How do Delphi's netbacks achieved in the second quarter of 2011 compare to the same period in the prior year?
For 2011, the Company's cash netbacks were higher by 26 percent principally due to lower operating and transportation expenses. The Company strives for an operating netback in the $22.00 to $25.00 per boe range and a cash netback of $20.00 per boe in the current commodity price environment.
Delphi's production is predominantly natural gas and therefore Delphi's operating and cash netbacks are primarily driven by the price received for natural gas. The Company is focused on increasing its light oil and natural gas liquids percentage of total production volumes to further strengthen its cash flow netback per boe.
Three Months Ended Six Months Ended
June 30 June 30
2011 2010 % Change 2011 2010 % Change
----------------------------------------------------------------------------
Barrels of oil
equivalent ($/boe)
Realized sales price 41.35 39.83 4 40.34 41.32 (2)
Royalties 5.89 6.45 (9) 5.82 6.01 (3)
Operating expenses 6.63 7.95 (17) 6.70 8.31 (19)
Transportation 2.80 3.38 (17) 2.88 3.29 (12)
----------------------------------------------------------------------------
Operating netback 26.03 22.05 18 24.94 23.71 5
General and
administrative expenses 2.82 3.13 (10) 2.25 2.41 (7)
Interest 1.61 1.82 (12) 1.73 1.88 (8)
----------------------------------------------------------------------------
Cash netback 21.60 17.10 26 20.96 19.42 8
Unrealized (gain)loss on
financial contracts (2.86) 1.64 - 0.60 (1.58) -
Stock-based compensation
expense 0.41 0.48 (15) 0.32 0.31 3
Depletion and
depreciation 14.22 14.42 (1) 14.24 17.98 (21)
Accretion 0.17 0.18 (6) 0.18 0.19 (5)
Gain on disposition (0.08) - 100 (0.22) - 100
Exploration and
evaluation - (0.06) 100 - 0.18 100
Deferred income taxes 2.65 0.27 881 1.52 1.11 37
----------------------------------------------------------------------------
Net earnings 7.09 0.17 4,129 4.32 1.23 251
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SELECTED INFORMATION
Over the past two years, how has Delphi performed and what significant factors contributed to the results?
Over the last eight quarters production has grown from 6,773 boe/d to 8,906 boe/d. Production for the last eight quarters reflects the following events. With crude oil and natural gas prices going in opposite directions through 2009, the capital program in the second half of 2009 was geared toward drilling for crude oil while acquiring strategic natural gas properties and infrastructure. The Company completed four natural gas property and infrastructure acquisitions in the Deep Basin of North West Alberta in the latter half of 2009. Continued drilling success in 2010 focused on light oil and liquids-rich natural gas opportunities resulted in record fourth quarter and annual production of 8,539 boe/day and 8,086 boe/day, respectively. The 2010 average production represents growth of 19 percent over 2009. In the first quarter of 2011, production was 8,259 boe/d as a result of natural declines in production and an outage at a non-operated processing facility resulting in the shut-in of 550 boe/d for 22 days in the quarter. In the second quarter of 2011, production was 8,906 boe/d as a result of a successful winter drilling program focused on crude oil and liquids rich natural gas opportunities.
Over the past two years, the changes in revenue and cash flow from quarter to quarter primarily reflect the increased production volumes achieved and the volatility of commodity prices.
Natural gas prices over the past two years have generally reflected the cyclical nature of demand. Higher prices have been realized in the winter months, reflecting demand for heating with lower prices through the summer months as production is placed in storage for the upcoming heating season demand. In 2009, reduced heating and industrial demand due to the global economic crisis caused natural gas prices to decrease further as a result of concerns over excess supply relative to demand. The average spot price for AECO in 2009 was $3.96 per mcf, the lowest average price in ten years. The average spot price for AECO in 2010 increased only one percent to $4.00 per mcf. In 2011, the average spot price for AECO has been $3.83 per mcf. Crude oil prices had recovered to over U.S. $80.00 per barrel by the end of 2009 from a low earlier in the year of U.S. $33.98 per barrel. In 2010, crude oil averaged U.S. $79.55, which was a 28 percent increase over the comparative period in 2009. In 2011, crude oil prices have continued to increase, averaging over U.S. $100.00 in the second quarter and just under U.S. $100.00 for the first six months of 2011.
Net earnings of the Company are primarily driven by the difference between the cash flow netback realized per boe of production versus the Company's depletion, depreciation and amortization ("DD&A") rate. The Company continues to reduce its DD&A rate by finding and developing reserves at a cost less than the average DD&A rate. Overall finding and development ("F&D") costs were $9.21 per proved plus probable boe in 2009 and $14.91 per proved plus probable boe in 2010.
The following table sets forth certain information of the Company for the past eight consecutive quarters outlining this performance.
IFRS IFRS GAAP GAAP IFRS IFRS GAAP GAAP
Jun. Mar. Dec. Sep. Jun. Mar. Dec. Sept.
30 31 31 30 30 31 31 30
2011 2011 2010 2010 2010 2010 2009 2009
----------------------------------------------------------------------------
Production
Natural gas
(mcf/d) 37,460 36,509 38,918 39,439 38,540 38,349 34,626 33,628
Oil
(bbls/d) 1,346 1,102 1,147 831 1,074 745 630 624
Natural gas
liquids
(bbls/d) 1,317 1,072 906 710 538 508 487 544
----------------------------------------------------------------------------
Barrels of
oil
equivalent
(boe/d) 8,906 8,259 8,539 8,114 8,035 7,645 6,888 6,773
Financial
($ thousands
except per
unit
amounts)
Petroleum
and natural
gas revenue 32,678 28,900 30,475 28,080 27,970 29,519 26,297 24,433
Funds from
operations
(cash flow) 17,517 15,061 17,987 15,120 12,507 15,049 14,218 12,635
Per share -
basic 0.15 0.13 0.16 0.13 0.12 0.15 0.14 0.16
Per share -
diluted 0.15 0.13 0.16 0.13 0.12 0.15 0.14 0.16
Net
earnings
(loss) 5,757 962 204 (1,566) (131) 1,613 1,386 (3,278)
Per share -
basic 0.05 0.01 - (0.01) - 0.02 0.02 (0.04)
Per share -
diluted 0.05 0.01 - (0.01) - 0.02 0.02 (0.04)
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----------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
Share Capital
What has been the market activity in the Company's common shares?
At June 30, 2011, the Company had 117.5 million common shares outstanding (December 31, 2010 - 112.8 million). The common shares of Delphi trade on the TSX under the symbol DEE. The following table summarizes outstanding share data for the three and six months ended June 30, 2011.
Three Months Ended Six Months Ended
June 30, 2011 June 30, 2011
----------------------------------------------------------------------------
Weighted Average Common Shares
Basic 117,442 115,465
Diluted 119,660 117,682
Trading Statistics (1)
High 2.89 2.89
Low 2.01 2.01
Average daily volume 399,962 610,888
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Trading statistics based on closing price
How many common shares and stock options are currently outstanding?
As at July 21, 2011, the Company had 117.6 million common shares outstanding and 9.3 milllion stock options outstanding. The stock options have an average exercise price of $1.97 per share.
Sources and Uses of Funds
Three Months Ended Six Months Ended
June 30, 2011 June 30, 2011
----------------------------------------------------------------------------
Sources:
Funds from operations 17,517 32,578
Disposition of petroleum and
natural gas properties 63 336
Issue of flow-through common
shares, net of issue costs (18) 8,928
Exercise of stock options 521 1,800
Cash and cash equivalents 1,671 -
----------------------------------------------------------------------------
19,754 43,642
Uses:
Cash and cash equivalents - (1,851)
Capital expenditures (9,542) (43,839)
Accretion of long term debt (626) (405)
Acquisition of petroleum and
natural gas properties - (87)
Change in non-cash working capital (22,222) (10,338)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
32,390 56,520
----------------------------------------------------------------------------
Change in long term debt 12,636 12,878
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Bank Debt plus Working Capital Deficiency (Net Debt)
How much bank debt was outstanding on June 30, 2011?
At June 30, 2011, the Company had $79.5 million outstanding in the form of bankers' acceptances, $27.0 million drawn under Canadian-based prime loans and a working capital surplus of $8.2 million for total net debt of $108.3 million excluding the fair value of financial instruments.
What are the Company's credit facilities and when is the next scheduled review of the borrowing base?
The Company has a $145.0 million extendible revolving term credit facility with a syndicate of Canadian chartered banks, subject to the banks' semi-annual valuation of the Company's crude oil and natural gas properties. The facility is a 364 day committed facility available on a revolving basis until May 28, 2012 at which time it may be extended at the lenders' option. If the revolving period is not extended, the undrawn portion of the facility will be cancelled and the amount outstanding will convert to a 365 day non-revolving term facility. The amounts outstanding under the non-revolving facility are required to be repaid at the end of the non-revolving term being May 28, 2013. The non-extension provisions are applicable to the lenders on an individual basis.
Interest payable on amounts drawn under the facility is at the prevailing bankers' acceptance rates plus stamping fees, lenders' prime rate, US base rate or LIBOR plus the applicable margins, depending on the form of borrowing by the Company. The applicable margins and stamping fees are based on a sliding scale pricing grid tied to the Company's trailing debt to annualized quarterly cash flow ratio: from a minimum of the bank's prime rate or US base rate plus 1.25 percent to a maximum of the bank's prime rate or US base rate plus 4.25 percent or from a minimum of bankers' acceptances rate plus a stamping fee of 2.25 percent to a maximum of bankers' acceptances rate plus a stamping fee of 4.25 percent.
Contractual Obligations
Does the Company have any contractual obligations as of June 30, 2011 that will require funding in future years?
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 over the next five years are as follows:
2011 2012 2013 2014 2015
----------------------------------------------------------------------------
Gathering, processing and transmission 2,298 4,262 3,451 2,990 2,958
Office and equipment lease 1,098 775 390 - -
----------------------------------------------------------------------------
Total 3,396 5,037 3,841 2,990 2,958
----------------------------------------------------------------------------
----------------------------------------------------------------------------
GUARANTEES AND OFF-BALANCE SHEET ARRANGEMENTS
Does Delphi have any outstanding guarantees on behalf of third parties or any off-balance sheet arrangements which could lead to liabilities in the future?
Delphi has not entered into any guarantees or off-balance sheet arrangements. Certain lease agreements entered into in the normal course of operations could be considered off-balance sheet arrangements, however, all leases are operating leases with lease payments charged to operating expenses or general and administrative expenses on a monthly basis according to the lease.
CRITICAL ACCOUNTING ESTIMATES
In preparing the Company's financial statements, is Delphi required to make estimates or assumptions about future events?
The interim consolidated financial statements have been prepared in conformity with IFRS which requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, shareholders' equity, revenue and expenses. Actual results may differ from these estimates.
Estimates and their underlying assumptions are reviewed on an ongoing basis. 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. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.
In preparing these interim consolidated financial statements, the significant judgments made by management in applying the Company's accounting policies and the key sources of estimation uncertainty are expected to be the same as those to be applied in the first annual IFRS financial statements. These judgments, estimates and assumptions that have the most significant effect on the amounts recognized in the consolidated financial statements is included in the following:
i) valuation of financial instruments;
ii) valuation of exploration and evaluation assets;
iii) valuation of property, plant and equipment;
iv) measurement of decommissioning obligations; and
v) measurement of share-based compensation.
Estimates of proved plus probable reserves have an effect on a number of the areas referred to above, in particular, the valuation of property, plant and equipment and the calculation of depletion and depreciation.
NEW ACCOUNTING STANDARDS
Are there any new accounting standards which the Company has had to adopt and comply with?
International Financial Reporting Standards (IFRS)
The Company adopted IFRS effective January 1, 2011. As a result, the Company's financial results for the first quarter ended March 31, 2011 and comparative periods are reported under IFRS while selected historical data prior to 2010 continues to be reported under previous Canadian GAAP. Refer to note 7 of the consolidated interim financial statements of the Company for the affects of the transition to IFRS.
In November 2009, the International Accounting Standards Board ("IASB") published IFRS 9, "Financial Instruments, which covers the classification and measurement of financial assets as part of its project to replace IAS 39, "Financial Instruments: Recognition and Measurement." In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through earnings. If this option is elected, entities would be required to reverse the portion of the fair value change due to a company's own credit risk out of earnings and recognize the change in other comprehensive income. IFRS 9 is effective for the Company on January 1, 2013. Early adoption is permitted and the standard is required to be applied retrospectively. The Company is currently evaluating the impact of adopting IFRS 9.
In May 2011, the International Accounting Standards Board published IFRS 11, "Joint Arrangements" which carves out certain jointly controlled entities, now called joint ventures, from IAS 31 "Interests in Joint Ventures" and removes the choice of using the equity method or proportionate consolidation when accounting for these joint ventures. The equity method must now always be used. IFRS 11 is effective for the Company on January 1, 2013. The Company is currently evaluating the impact of adopting IFRS 11.
In May 2011, the International Accounting Standards Board published IFRS 13, "Fair Value Measurement" which defines fair value, establishes a framework for measuring fair value and sets out disclosure requirements for fair value measurements. IFRS 13 is effective for the Company on January 1, 2013. The Company is currently evaluating the impact of adopting IFRS 13.
CORPORATE GOVERNANCE
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
Disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the issuer's management, including its President and Chief Executive Officer and Vice President, Finance and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Company's President and Chief Executive Officer and Vice President, Finance and Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective and provide a reasonable level of assurance that information required to be disclosed by the Company is recorded, processed, summarized and reported within the time periods specified.
The Company notes that while it believes the disclosure controls and procedures and internal controls over financial reporting provide a reasonable level of assurance that they are effective, it does not expect that the disclosure controls and procedures and internal controls will prevent all errors and fraud. A control system is designed to provide reasonable, not absolute, assurance that the objectives of the control system are met. There were no changes made to the disclosure controls and procedures or internal controls over financial reporting as a result of the transition to IFRS.
ADDITIONAL INFORMATION
Where is additional information about Delphi available?
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.
DELPHI ENERGY CORP.
Consolidated Statements of Financial Position
June 30 December 31
(thousands of dollars) 2011 2010
----------------------------------------------------------------------------
(unaudited)
Assets
Current assets
Cash 5,890 4,039
Accounts receivable 17,516 17,897
Prepaid expenses and deposits 2,731 3,426
Fair value of financial instruments 161 2,080
----------------------------------------------------------------------------
26,298 27,442
Exploration and evaluation assets (Note 4) 3,756 2,787
Property, plant and equipment (Note 5) 378,841 357,458
----------------------------------------------------------------------------
Total assets 408,895 387,687
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities 17,952 28,416
Fair value of financial instruments 373 -
----------------------------------------------------------------------------
18,325 28,416
Other liability 800 -
Long term debt 116,523 105,000
Decommissioning obligations 17,996 17,232
Fair value of financial instruments 2,170 3,527
Deferred income taxes 18,938 16,552
----------------------------------------------------------------------------
174,752 170,727
Shareholders' equity
Share capital (Note 6) 247,256 236,382
Contributed surplus 11,577 11,987
Deficit (24,690) (31,409)
----------------------------------------------------------------------------
Total shareholders' equity 234,143 216,960
----------------------------------------------------------------------------
Total liabilities and shareholders' equity 408,895 387,687
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the interim consolidated financial statements.
DELPHI ENERGY CORP.
Consolidated Statements of Earnings and Comprehensive Earnings
For the three and six months ended June 30
Three Months Ended Six Months Ended
(thousands of dollars, except June 30 June 30
per share amounts) 2011 2010 2011 2010
----------------------------------------------------------------------------
(unaudited) (Note 7) (Note 7)
Revenue
Crude oil and natural gas
sales 32,678 27,970 61,578 57,426
Royalties (4,771) (4,719) (9,040) (8,533)
----------------------------------------------------------------------------
27,907 23,251 52,538 48,893
Realized gain on financial
instruments 842 1,155 1,105 1,218
Unrealized gain (loss) on
financial instruments 2,318 (1,199) (935) 2,238
----------------------------------------------------------------------------
31,067 23,207 52,708 52,349
Expenses
Operating 5,371 5,810 10,404 11,795
Transportation 2,269 2,474 4,481 4,670
Exploration and evaluation - (42) - 256
General and administrative 2,289 2,286 3,497 3,419
Share-based compensation (Note 6) 331 351 497 444
Gain on disposition (63) - (336) -
Depletion and depreciation (Note 5) 11,522 10,541 22,123 25,509
----------------------------------------------------------------------------
21,719 21,420 40,666 46,093
Finance costs (1,441) (1,458) (2,962) (2,938)
----------------------------------------------------------------------------
Earnings before taxes 7,907 329 9,080 3,318
Taxes
Deferred income taxes 2,150 198 2,361 1,574
----------------------------------------------------------------------------
Net earnings and comprehensive
earnings 5,757 131 6,719 1,744
----------------------------------------------------------------------------
Net earnings per share (Note 6)
Basic 0.05 - 0.06 0.02
Diluted 0.05 - 0.06 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the interim consolidated financial statements.
DELPHI ENERGY CORP.
Consolidated Statements of Changes in Shareholders' Equity
For the six months ended June 30, 2011 and 2010
Total
Share Contributed Shareholders'
(thousands of dollars) Capital Surplus Deficit Equity
----------------------------------------------------------------------------
(unaudited)
Balance as at January 1, 2010 206,382 11,027 (14,425) 202,984
Net earnings - - 1,744 1,744
Issue of common shares 30,250 - - 30,250
Share issue costs (1,982) - - (1,982)
Tax effect of share issue
costs 523 - - 523
Issued on exercise of options 607 - - 607
Share-based compensation on
exercise of options 324 (324) - -
Share-based compensation
expense - 444 - 444
Share-based compensation
capitalized - 183 - 183
----------------------------------------------------------------------------
Balance as at June 30, 2010 236,104 11,330 (12,681) 234,753
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total
Share Contributed Shareholders'
(thousands of dollars) Capital Surplus Deficit Equity
----------------------------------------------------------------------------
Balance as at December 31,
2010 236,382 11,987 (31,409) 216,960
Net earnings - - 6,719 6,719
Issue of flow-through common
shares 8,160 - - 8,160
Share issue costs (32) - - (32)
Issued on exercise of options 1,800 - - 1,800
Share-based compensation on
exercise of options 946 (946) - -
Share-based compensation
expense - 497 - 497
Share-based compensation
capitalized - 39 - 39
----------------------------------------------------------------------------
Balance as at June 30, 2011 247,256 11,577 (24,690) 234,143
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the interim consolidated financial statements.
DELPHI ENERGY CORP.
Consolidated Statements of Cash Flows
For the three and six months ended June 30
Three Months Ended Six Months Ended
June 30 June 30
(thousands of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
(unaudited)
Cash flow from (used in) operating
activities
Net earnings 5,757 131 6,719 1,744
Add non-cash items:
Depletion and depreciation 11,522 10,541 22,123 25,509
Accretion of decommissioning
obligations 138 129 279 267
Accretion of long term debt (626) - (405) -
Share-based compensation 331 351 497 444
Gain on disposition (63) - (336) -
Expensing of exploration and
evaluation costs - (42) - 256
Unrealized loss (gain) on
financial instruments (2,318) 1,199 935 (2,238)
Deferred income taxes 2,150 198 2,361 1,574
Change in non-cash working capital 1,858 5,796 (1,648) 1,768
----------------------------------------------------------------------------
18,749 18,303 30,525 29,324
Cash flow from (used in) financing
activities
Issue of common shares, net of
issue costs - 28,268 - 28,268
Issue of flow-through common
shares, net of issue costs (18) - 8,928 -
Exercise of stock options 521 269 1,800 607
Increase (decrease) in long term
debt 12,636 - 12,878 (1,100)
----------------------------------------------------------------------------
13,139 28,537 23,606 27,775
----------------------------------------------------------------------------
Cash flow available for investing
activities 31,888 46,840 54,131 57,099
Cash flow from (used in) investing
activities
Additions to exploration and
evaluation assets (713) 200 (969) (2,069)
Additions to property, plant and
equipment (8,829) (7,822) (42,870) (40,651)
Disposition of petroleum and
natural gas properties 63 251 336 251
Expensing of exploration and
evaluation costs - 42 - (256)
Acquisition of petroleum and
natural gas properties - 307 (87) (385)
Change in non-cash working capital (24,080) (28,932) (8,690) (8,234)
----------------------------------------------------------------------------
(33,559) (35,954) (52,280) (51,344)
----------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents (1,671) 10,886 1,851 5,755
Cash and cash equivalents,
beginning of period 7,561 (5,270) 4,039 (139)
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period 5,890 5,616 5,890 5,616
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash interest paid 1,973 1,309 3,169 2,705
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the interim consolidated financial statements.
DELPHI ENERGY CORP.
Notes to the Interim Consolidated Financial Statements
For the three and six months ended June 30, 2011
(thousands of dollars, except per share amounts) (unaudited)
1) STRUCTURE OF DELPHI
Delphi Energy Corp. ("Delphi" or "the Company") is a publicly-traded company with its corporate office in Calgary, Alberta, Canada. Delphi is engaged in the exploration for, development and production of crude oil and natural gas from properties and assets located in Western Canada in which it holds an interest. The Company's operations are primarily concentrated in the Deep Basin of North West Alberta, representing in excess of 90 percent of the Company's production.
The interim consolidated financial statements as at and for the three and six months ended June 30, 2011 comprise the accounts of the Company, its wholly-owned subsidiary and a partnership.
The audited consolidated financial statements of the Company as at and for the year ended December 31, 2010, which were prepared under previous Canadian GAAP are available through the Company's filings on SEDAR at
www.sedar.com or can be obtained from Delphi's website at
www.delphienergy.ca.
2) BASIS OF PRESENTATION
(a) Statement of compliance
These interim consolidated financial statements have been prepared in accordance with International Accounting Standards (IAS) 34 Interim Financial Reporting. These are the Company's second International Financial Reporting Standards (IFRS) interim consolidated financial statements for part of the period covered by the first IFRS annual financial statements and IFRS 1 First-time Adoption of International Financial Reporting Standards has been applied. The interim consolidated financial statements do not include all of the information required for full annual financial statements.
An explanation of how the transition to IFRS has affected the reported consolidated financial performance of the Company for the three and six months ended June 30, 2010 is provided in note 7. This note includes reconciliations of total comprehensive earnings for the comparative periods reported under previous Canadian GAAP to those reported for those periods under IFRS.
These interim consolidated financial statements were approved by the Board of Directors on July 26, 2011.
(b) Basis of measurement
The interim consolidated financial statements have been prepared on the historical cost basis except for derivative financial instruments which are measured at fair value.
(c) Functional and presentation currency
These interim consolidated financial statements are presented in Canadian dollars, which is the Company's functional currency.
(d) Use of estimates and judgments
The preparation of the interim consolidated financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, shareholders' equity, revenue and expenses. Actual results may differ from these estimates.
Estimates and their underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.
In preparing these interim consolidated financial statements, the significant judgments made by management in applying the Company's accounting policies and the key sources of estimation uncertainty are expected to be the same as those to be applied in the first annual IFRS financial statements. These judgments, estimates and assumptions that have the most significant effect on the amounts recognized in the consolidated financial statements include the following:
vi) valuation of financial instruments;
vii) valuation of exploration and evaluation assets;
viii) valuation of property, plant and equipment;
ix) measurement of decommissioning obligations; and
x) measurement of share-based compensation.
Estimates of proved plus probable reserves have an effect on a number of the areas referred to above, in particular, the valuation of property, plant and equipment and the calculation of depletion and depreciation expense.
3) SIGNIFICANT ACCOUNTING POLICIES
The unaudited interim consolidated financial statements of Delphi have been prepared by management in accordance with International Financial Reporting Standards and following the same accounting policies and methods of computation as the unaudited interim consolidated financial statements for the three months ended March 31, 2011. The unaudited interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto in the Company's Annual Report for the year ended December 31, 2010 and the unaudited interim consolidated financial statements and notes thereto in the Company's First Quarter Report for the three months ended March 31, 2011.
The Company's accounting policies have been applied consistently to all periods presented in these interim consolidated financial statements and have been applied consistently by the Company and its subsidiaries. Certain comparative amounts have been reclassified to conform to the current year's presentation.
(a) Restricted Share Unit Plan
The Company has a restricted share unit ("RSU") plan whereby the fair value of the RSU's is expensed into the statement of earnings over the same period that the units vest and at each reporting date between the grant date and settlement, the fair value of the liability is re-measured with any changes in fair value recognized in the statement of earnings for the period.
4) EXPLORATION AND EVALUATION ASSETS
Total
----------------------------------------------------------------------------
Balance as at January 1, 2010 315
Additions 2,472
----------------------------------------------------------------------------
Balance as at December 31, 2010 2,787
Additions 969
----------------------------------------------------------------------------
Balance as at June 30, 2011 3,756
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5) PROPERTY, PLANT AND EQUIPMENT
Crude oil
and natural
gas Production Other
Cost properties equipment assets Total
----------------------------------------------------------------------------
Balance as at January 1, 2010 223,100 109,266 572 332,938
Additions 81,991 20,928 49 102,968
Acquisitions 18 - - 18
Dispositions (247) - - (247)
Change in decommissioning
obligations 1,559 - - 1,559
----------------------------------------------------------------------------
Balance as at December 31, 2010 306,421 130,194 621 437,236
Additions 27,005 15,697 232 42,934
Acquisitions 87 - - 87
Change in decommissioning
obligations 485 - - 485
----------------------------------------------------------------------------
Balance as at June 30, 2011 333,998 145,891 853 480,742
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crude oil
and natural
Accumulated depletion and gas Production Other
depreciation properties equipment assets Total
----------------------------------------------------------------------------
Balance as at January 1, 2010 - - - -
Depletion and depreciation (36,994) (7,155) (129) (44,278)
Impairment losses (30,500) (5,000) - (35,500)
----------------------------------------------------------------------------
Balance as at December 31, 2010 (67,494) (12,155) (129) (79,778)
Depletion and depreciation (18,617) (3,255) (251) (22,123)
----------------------------------------------------------------------------
Balance as at June 30, 2011 (86,111) (15,410) (380) (101,901)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value as at June 30,
2011 247,887 130,481 473 378,841
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value as at December
31, 2010 238,927 118,039 492 357,458
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 30, 2011, costs in the amount of $4.7 million (June 30, 2010 - $4.3 million) representing work in progress were excluded from the depletion calculation and estimated future development costs of $129.6 million (June 30, 2010 - $82.3 million) have been included in costs subject to depletion.
During 2010, as a result of decreasing natural gas prices, the Company recognized an impairment of $35.5 million relating to several cash generating units ("CGU's") outside of the Company's focus area in the Deep Basin which predominantly produce natural gas only. The impairments were based on the difference between the period end net book value of the CGU's and the recoverable amount. The recoverable amount was determined using fair value less cost to sell based on discounted cash flows of proved plus probable reserves using discount rates of 12 to 15 percent.
6) SHARE CAPITAL
At June 30, 2011 and 2010, the Company was authorized to issue an unlimited number of common shares. The holders of common shares are entitled to receive dividends as declared by the Company and are also entitled to one vote per share.
(a) Issued and outstanding June 30, 2011 December 31, 2010
----------------------------------------------------------------------------
Outstanding Outstanding
shares shares
(000's) Amount (000's) Amount
----------------------------------------------------------------------------
Balance, beginning of period 112,825 236,382 101,166 206,382
Issue of common shares - - 11,000 30,250
Issue of flow-through common
shares 3,200 8,160 - -
Exercise of stock options 1,488 1,800 659 775
Allocated from contributed
surplus - 946 - 418
Share issue costs - (32) - (1,966)
Tax effect of share issue
costs - - - 523
----------------------------------------------------------------------------
Balance, end of period 117,513 247,256 112,825 236,382
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On March 24, 2011, the Company issued 3.2 million flow-through common shares at a price of $2.80 per share for gross proceeds of $8.96 million. A flow-through premium of $0.8 million related to the issuance of the shares has been recorded as a long term liability on the consolidated statement of financial position. The liability will be reversed as qualified expenditures are incurred. The Company has an obligation to incur qualifying exploration expenditures by December 31, 2012 to satisfy the terms of the flow-through common shares issued.
(b) Share-based compensation
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. Options granted prior to September 1, 2009 vest over a two-year period starting on the date of grant. Options granted between September 1, 2009 and May 31, 2011 vest over a two-year period with one-third vesting six months after the date of grant and one-third on each of the first and second anniversary of the grant date. Options granted on May 31, 2011 or later vest over a four-year period with one-fourth vesting on each of the first, second, third and fourth anniversary of the grant date. The exercise price of each option equals the five day weighted average of the market price of the Company's common shares, immediately preceding the date of the grant. As at June 30, 2011 there were 9.4 million options to purchase shares outstanding.
The following table summarizes the changes in the number of options outstanding and the weighted average exercise prices.
June 30, 2011 December 31, 2010
----------------------------------------------------------------------------
Weighted Weighted
Outstanding average Outstanding average
options exercise options exercise
(000's) price (000's) price
----------------------------------------------------------------------------
Balance, beginning of period 6,675 1.66 7,428 1.40
Granted 3,390 2.56 1,074 2.64
Forfeited (321) 2.46 (67) 1.50
Exercised (392) 1.33 (659) 1.18
----------------------------------------------------------------------------
Balance, end of period 9,352 1.97 7,776 1.59
----------------------------------------------------------------------------
Exercisable, end of period 5,679 1.61 6,116 1.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table summarizes information about the stock options
outstanding and exercisable at June 30, 2011.
Options outstanding Options exercisable
----------------------------------------------------------------------------
Weighted
Weighted average Weighted
Outstanding average remaining average
Range of options exercise term Exercisable exercise
exercise price (000's) price (years) (000's) price
----------------------------------------------------------------------------
$0.65 - $0.97 1,166 0.65 2.67 1,166 0.65
$0.98 - $1.54 350 1.21 2.90 295 1.18
$1.55 - $1.72 3,060 1.68 1.45 3,035 1.68
$1.73 - $2.15 605 1.90 2.35 435 1.81
$2.16 - $3.34 4,171 2.62 4.55 748 2.85
----------------------------------------------------------------------------
Total 9,352 1.97 3.10 5,679 1.61
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The weighted average share price at the date of exercise for stock options exercised in 2011 was $2.40 (2010 - $2.70).
The Company accounts for its share-based compensation using the fair value method for all stock options. For the six months ended June 30, 2011, Delphi recorded non-cash compensation expense of $0.5 million (June 30, 2010 - $0.4 million).
During the six months ended June 30, 2011, the Company granted 3.4 million options. The fair values of all options granted during the period are estimated at the date of grant using the Black-Scholes option pricing model. The weighted average fair value of options granted during the period was $2.56 per option (June 30, 2010 - $1.55 per option). The assumptions used in the Black-Scholes model to determine fair value were as follows.
For the six months ended June 30 2011 2010
----------------------------------------------------------------------------
Risk-free interest rate (%) 2.4 2.9
Expected life (years) 5.0 5.0
Forfeiture rate (%) 5.6 3.6
Expected volatility (%) 64.5 65.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the six months ended June 30, 2011, the Company instituted a restricted share unit ("RSU") plan. Employees are eligible to receive RSU awards or convert up to 50 percent of their performance bonus into RSU awards. RSU awards received by an employee as a result of conversion, receive a 30 percent increase in the number of RSU's received through the conversion. The RSU awards vest on each of the first, second and third anniversary of the award date at which time the employee will receive a cash payment equivalent to the number of RSU's vested multiplied by the Company's closing share price on the business day immediately preceding the vesting date.
June 30, 2011
----------------------------------------------------------------------------
Outstanding RSU's Amount
----------------------------------------------------------------------------
Restricted share unit obligation 58,012 124
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(c) Net earnings per share
Net earnings per share has been calculated based on the following weighted
average common shares.
Three Month Ended June 30 Six Months Ended June 30
2011 2010 2011 2010
----------------------------------------------------------------------------
Weighted average common
shares - basic 117,442 104,808 115,465 103,037
Stock options 2,218 3,158 2,218 3,158
----------------------------------------------------------------------------
Weighted average common
shares - diluted 119,660 107,966 117,682 106,195
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7) FIRST TIME ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS
These are the Company's second interim consolidated financial statements for the period covered by the first annual consolidated financial statements to be prepared in accordance with IFRS.
The accounting policies outlined in Note 3 have been applied in preparing the interim consolidated financial statements for the three and six months ended June 30, 2011 and the comparative information for the three and six months ended June 30, 2010.
An explanation of how the transition from previous Canadian GAAP to IFRS has affected the Company's financial performance for the three and six months ended June 30, 2010 is set out in the following tables.
Key First Time Adoption Exemptions Applied
IFRS 1 First Time Adoption of International Financial Reporting Standards allows first time adopters certain exemptions from retrospective application of certain IFRS.
The Company has applied the following exemptions:
-- Previously, crude oil and natural gas assets in property, plant and
equipment on the statement of financial position were recognized and
measured on a full cost basis in accordance with previous Canadian GAAP.
The Company has elected to measure its properties at the amount
determined under previous Canadian GAAP as at January 1, 2010. Costs
included in the full cost pool on January 1, 2010 were allocated on a
pro-rata basis to the underlying assets on the basis of total proved
plus probable reserve values as at January 1, 2010. Decommissioning
liabilities were measured using a risk free rate, with a corresponding
adjustment recorded to opening retained earnings.
-- IFRS 3 Business Combinations has not been applied to acquisitions of
subsidiaries or interests in joint ventures that occurred before January
1, 2010.
IFRS Consolidated Statement of Earnings and Comprehensive Earnings
For the three months ended June 30, 2010
Effect of
Previous Transition
(thousands of dollars) Notes GAAP to IFRS IFRS
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales 27,970 - 27,970
Royalties (4,719) - (4,719)
----------------------------------------------------------------------------
23,251 - 23,251
Realized gain on financial
instruments 1,155 - 1,155
Unrealized loss on financial
instruments (1,199) - (1,199)
----------------------------------------------------------------------------
23,207 - 23,207
Expenses
Operating d) 5,845 (35) 5,810
Transportation 2,474 - 2,474
Exploration and evaluation a) - (42) (42)
General and administrative d) 1,770 516 2,286
Share-based compensation c) 320 31 351
Depletion and depreciation b) 15,089 (4,548) 10,541
----------------------------------------------------------------------------
25,498 (4,077) 21,420
Finance costs e) (1,329) (129) (1,458)
----------------------------------------------------------------------------
Earnings (loss)before taxes (3,620) 3,949 329
Taxes
Deferred income taxes
(reduction) f) (878) 1,076 198
----------------------------------------------------------------------------
Net earnings (loss) and
comprehensive earnings (loss) (2,742) 2,873 131
----------------------------------------------------------------------------
----------------------------------------------------------------------------
IFRS Consolidated Statement of Earnings and Comprehensive Earnings
For the six months ended June 30, 2010
Effect of
Previous Transition
(thousands of dollars) Notes GAAP to IFRS IFRS
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales 57,426 - 57,426
Royalties (8,533) - (8,533)
----------------------------------------------------------------------------
48,893 - 48,893
Realized gain on financial
instruments 1,218 - 1,218
Unrealized gain on financial
instruments 2,238 - 2,238
----------------------------------------------------------------------------
52,349 - 52,349
Expenses
Operating d) 11,836 (41) 11,795
Transportation 4,670 - 4,670
Exploration and evaluation a) - 256 256
General and administrative d) 2,789 630 3,419
Share-based compensation c) 425 19 444
Depletion and depreciation b) 28,991 (3,482) 25,509
----------------------------------------------------------------------------
48,711 (2,617) 46,093
Finance costs e) (2,671) (267) (2,938)
----------------------------------------------------------------------------
Earnings before taxes 967 2,351 3,318
Taxes
Deferred income taxes f) 449 1,125 1,574
----------------------------------------------------------------------------
Net earnings and comprehensive
earnings 518 1,226 1,744
----------------------------------------------------------------------------
----------------------------------------------------------------------------
IFRS Consolidated Statement of Changes in Shareholders' Equity
For the six months ended June 30, 2010
Effect of
Previous Transition
(thousands of dollars) Notes GAAP to IFRS IFRS
----------------------------------------------------------------------------
Shareholders' equity
Share capital g) 228,162 7,942 236,104
Contributed surplus h) 11,371 (41) 11,330
Deficit i) 825 (13,506) (12,681)
----------------------------------------------------------------------------
Total shareholders' equity 240,358 (5,605) 234,753
----------------------------------------------------------------------------
Notes to reconciliations:
(a) Property, plant and equipment - Delphi's PP&E assets were allocated to CGU's whereas under previous Canadian GAAP all crude oil and natural gas assets were accumulated into one cost centre. The deemed cost of Delphi's crude oil and natural gas assets were allocated to its defined CGU's based on Delphi's total proved plus probable reserve values as at January 1, 2010, in accordance with IFRS 1. These CGU's were aligned within the major geographic regions in which Delphi operates and could change in the future as a result of acquisition and disposition activity. The following tables highlight the changes in property, plant and equipment and the effect on the consolidated statement of earnings as a result of the transition from previous GAAP to IFRS.
Three Months Ended Six Months Ended
Consolidated statement of earnings June 30, 2010 June 30, 2010
----------------------------------------------------------------------------
Expensing of dry hole costs (42) 256
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(b) Depletion and depreciation expense - Delphi has chosen to calculate its depletion using a reserve base of total proved plus probable reserves, as compared to using only proved reserves under previous Canadian GAAP. As a result, the depletion and depreciation expense decreased as compared to its calculation under previous Canadian GAAP.
Three Months Ended Six Months Ended
Consolidated statement of earnings June 30, 2010 June 30, 2010
----------------------------------------------------------------------------
Decrease in depletion and depreciation (4,419) (8,107)
Reclassification of accretion expense (129) (375)
Impairment losses - 5,000
----------------------------------------------------------------------------
Increase in depletion and depreciation (4,548) (3,482)
----------------------------------------------------------------------------
Impairment of PP&E assets - Under IFRS, an impairment test of PP&E is performed at the CGU level as opposed to the entire PP&E balance, which was required under previous GAAP through the full cost ceiling test. Delphi is required to recognize an impairment loss if the carrying amount of a CGU exceeds the higher of its fair value less cost to sell and value in use. Under previous GAAP, estimated future cash flows used to assess whether an impairment has occurred were not discounted.
During the first six months of 2010, as a result of decreasing natural gas prices, the Company recognized a $5.0 million impairment relating to a CGU outside the Company's focus area in the Deep Basin which predominantly produced natural gas.
(c) Share-based compensation - Delphi is required to utilize a forfeiture rate in its calculation of share-based compensation, unlike under previous Canadian GAAP where this was an option but not required.
Three Months Ended Six Months Ended
Consolidated statement of earnings June 30, 2010 June 30, 2010
----------------------------------------------------------------------------
Change to share-based compensation (1) (20)
Share-based compensation capitalized
to PP&E 54 89
Share-based compensation capitalized
to E&E (22) (49)
----------------------------------------------------------------------------
31 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(d) Capitalized directly related overhead
Three Months Ended Six Months Ended
Consolidated statement of earnings June 30, 2010 June 30, 2010
----------------------------------------------------------------------------
Decrease in capitalized directly
related overhead 481 589
Transfer from operating expense to
general and administration 35 41
----------------------------------------------------------------------------
516 630
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(e) Finance costs - Accretion expense is classified as a finance cost rather
than depletion and depreciation and includes the impact of using a risk-
free rate.
Three Months Ended Six Months Ended
Consolidated statement of earnings June 30, 2010 June 30, 2010
----------------------------------------------------------------------------
Accretion expense (129) (267)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(f) Deferred income tax - Delphi recorded a decrease of $2.7 million to its deferred tax liability upon transition to IFRS with the offset to opening retained earnings. The change in deferred tax liability is primarily due to the adjustments to the balances of property, plant and equipment and decommissioning liabilities on transition to IFRS.
Three Months Ended Six Months Ended
Consolidated statement of earnings June 30, 2010 June 30, 2010
----------------------------------------------------------------------------
Deferred income tax related to
transition to IFRS 1,076 1,125
----------------------------------------------------------------------------
----------------------------------------------------------------------------
g) Share Capital - Delphi recorded an increase of $7.4 million to its share capital upon transition to IFRS, with the offset to opening retained earnings, relating to the recording of flow-through shares under IFRS. Under previous GAAP, the tax renouncement related to flow-through shares was recorded against share capital whereas under IFRS only the portion related to the flow-through premium is recorded against share capital. This change is retrospective for all flow-through share issuances. For the flow-through share issuance in 2009, where the qualifying expenditures were incurred in 2010, the flow-through premium of $1.0 million is recorded in other liabilities instead of share capital until the qualifying expenditures are incurred, at which point the flow-through premium is recorded in share capital.
Delphi recorded a decrease of $0.1 million to its share capital upon transition to IFRS, with the offset to opening retained earnings, relating to changes in the treatment of share issue costs under IFRS.
Consolidated statement of financial position June 30, 2010
----------------------------------------------------------------------------
Flow-through adjustment 7,409
Flow-through issuance in 2009 655
Share issue cost adjustment (122)
----------------------------------------------------------------------------
7,942
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(h) Contributed Surplus - Delphi is required to utilize a forfeiture rate in
its calculation of share-based compensation, unlike under previous GAAP
where this was an option but not required.
Consolidated statement of financial position June 30, 2010
----------------------------------------------------------------------------
Change due to forfeiture rate (41)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) Deficit - Under IFRS, Delphi remeasured its liability for asset retirement obligations using the risk-free rate of interest. IFRS requires that decommissioning obligations be remeasured each reporting period for changes in the discount rate with a corresponding adjustment to the cost of property, plant and equipment. At January 1, 2010 Delphi's total decommissioning liabilities increased by $6.2 million to $18.1 million as the liability was revalued to reflect the estimated risk-free rate of interest of 3.6% as compared to the credit adjusted risk-free rate of 8 - 10% used under previous GAAP.
Upon transition to IFRS, Delphi recorded an impairment on its East Central Alberta cash generating unit to a net realizable value of $0.3 million, with the impairment of $3.9 million recognized in opening retained earnings as required by IFRS 5. The remaining assets and liabilities were reclassified to assets and liabilities held for sale. The net assets were sold in the second quarter of 2010 for $0.3 million.
Consolidated statement of financial position June 30, 2010
----------------------------------------------------------------------------
Decommissioning obligations (6,056)
Share-based compensation c) 2
Flow-through adjustment g) (8,064)
Flow-through premium g) (266)
Impairment of assets held for sale (3,895)
Share issue cost adjustment g) 122
Deferred income tax f) 2,458
Capitalized directly related overhead d) (589)
Depletion and depreciation b) 7,981
Rate change in decommissioning obligations 57
Expensing of dry hole costs a) (256)
Impairment loss b) (5,000)
----------------------------------------------------------------------------
(13,506)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
DIRECTORS OFFICERS
David J. Reid David J. Reid
President and Chief Executive Officer President and Chief
Delphi Energy Corp. Executive Officer
Tony Angelidis Tony Angelidis
Senior Vice President Exploration Senior Vice President Exploration
Delphi Energy Corp.
Hugo H. Batteke
Harry S. Campbell, Q.C. (3) Vice President Operations
Partner
Burnet, Duckworth & Palmer LLP Michael K. Galvin
Vice President Land
Robert A. Lehodey, Q.C. (2) (3)
Partner Rod A. Hume
Osler, Hoskin & Harcourt LLP Vice President Engineering
Stephen Mulherin (1) Brian P. Kohlhammer
Partner Vice President Finance and Chief
Polar Capital Corporation Financial Officer
Andrew E. Osis (1) CORPORATE OFFICE
Chief Executive Officer and Director
Poynt Corporation 300, 500 - 4th Avenue S.W.
Calgary, Alberta T2P 2V6
David Sandmeyer (2) Telephone: (403) 265-6171
Director Facsimile: (403) 265-6207
Freehold Royalty Trust Email: info@delphienergy.ca
Website: www.delphienergy.ca
Lamont C. Tolley (1) (2) BANKERS
Independent Businessman
National Bank of Canada
(1) Member of the Audit Committee The Bank of Nova Scotia
(2) Member of the Reserves Committee Alberta Treasury Branches
(3) Member of the Corporate Governance
and Compensation Committee INDEPENDENT ENGINEERS
AUDITORS GLJ Petroleum Consultants Ltd.
KPMG LLP Toronto Stock Exchange - DEE
LEGAL COUNSEL TRANSFER AGENT
Osler, Hoskin & Harcourt LLP Olympia Trust Company
ABBREVIATIONS
bbls.....................barrels mmcf/d.....million cubic feet per day
bbls/d...........barrels per day NGL...............natural gas liquids
mbbls...........thousand barrels bcf................billion cubic feet
mcf..........thousand cubic feet boe.........barrels of oil equivalent
(6 mcf: 1 bbl)
mcf/d........thousand cubic feet boe/d.......barrels of oil equivalent
per day per day
mmcf..........million cubic feet mmboe..........million barrels of oil
equivalent
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)
or
Delphi Energy Corp.
300, 500 - 4 Avenue S.W.
Calgary, Alberta
T2P 2V6
info@delphienergy.ca
www.delphienergy.ca 
