EnCana Corporation (TSX & NYSE: ECA) continued to deliver strong financial and operating performance in the second quarter of 2009 – a period of very low natural gas prices. Cash flow was $2.2 billion, or $2.87 per share, and operating earnings were $917 million, or $1.22 per share – down 25 and 38 percent respectively on a per share basis compared to the second quarter of 2008. EnCana’s financial performance was greatly enhanced by its commodity price hedges, which contributed a $900 million after-tax gain, or $1.20 per share, to cash flow in the second quarter. Second quarter natural gas and oil production remained flat at 4.6 billion cubic feet equivalent per day (Bcfe/d) compared to the second quarter of 2008.
“EnCana’s continued strong financial and operating performance during this period of weak natural gas prices provides clear evidence of how our risk management measures reduce volatility in our business and help us continue to enhance long-term value creation. In the past year, natural gas prices dropped close to 70 percent, yet we have continued to meet or exceed our 2009 financial and operating objectives. Our natural gas price hedges provide an increased level of certainty to our cash flows so that we can most effectively manage our capital programs. Operationally, our production is on track for the year and we have additional natural gas productive capacity that we are not bringing on due to the prevailing weak prices. In our oil activities, we’ve seen a promising price recovery from the first quarter of 2009 and our newly expanded oil projects at Foster Creek and Christina Lake are ramping up production, up about 65 percent in the past year,” said Randy Eresman, EnCana’s President & Chief Executive Officer.
“Through 2009, EnCana will remain focused on directing our capital investment to our lowest cost, highest return projects and on maintaining our financial strength and flexibility. We are taking advantage of cost deflation and reduced industry activity by renegotiating supply and services contracts and by improving efficiencies. EnCana’s cost reduction initiatives, announced in February, have already exceeded our savings target of $900 million for the year. Some of those savings, achieved primarily through capital reductions, have been redeployed to other parts of our portfolio, largely to shale gas plays,” Eresman said.
“Our financial position remains strong. In the past few months, we have secured additional support for our financial future by hedging more than 45 percent of our expected natural gas production during the 2010 gas year at a price averaging $6.09 per thousand cubic feet (Mcf). During all periods in the economic cycle, we strive to be the leading North American resource play company developing unconventional natural gas and enhanced oil,” Eresman said.
IMPORTANT NOTE: EnCana reports in U.S. dollars unless otherwise noted and follows U.S. protocols, which report gas and oil production, sales and reserves on an after-royalties basis. The company’s financial statements are prepared in accordance with Canadian generally accepted accounting principles (GAAP). Per share amounts for cash flow and earnings are on a diluted basis.
Second Quarter 2009 Highlights
(all year-over-year comparisons are to the second quarter of 2008)
Financial
- Cash flow decreased 25 percent per share to $2.87, or $2.2 billion
- Operating earnings were down 38 percent per share to $1.22, or $917 million
- Net earnings decreased 80 percent to 32 cents per share, or $239 million
- Capital investment, excluding acquisitions and divestitures, was down 37 percent to $1.1 billion, primarily due to lower drilling and completion costs as a result of fewer wells drilled, cost deflation, a weaker Canadian dollar and lower long-term incentive costs as a result of a decline in share price
- Free cash flow was $1.1 billion, down 8 percent (Free cash flow is defined in Note 1 on page 8)
- EnCana’s integrated oil business venture with ConocoPhillips generated $293 million in operating cash flow, comprised of $139 million from the company’s Foster Creek and Christina Lake upstream projects, and $154 million from the downstream business. Operating cash flow was down $174 million largely due to lower crack spreads and capacity utilization in the downstream business
- Realized natural gas prices were down 18 percent to $6.99 per Mcf and realized liquids prices decreased 44 percent to $50.23 per barrel (bbl). These prices include financial hedges
- At the end of the quarter, debt to capitalization was 27 percent and debt to adjusted EBITDA was 0.7 times
- Paid dividend of 40 cents per share
- Completed public offering in the United States of notes totalling $500 million at 6.5 percent
Operating – Upstream
- Key resource play production was up 1 percent, with a 27 percent increase in oil production and a 1 percent decrease in natural gas production
- Total natural gas production decreased 1 percent to 3.79 billion cubic feet per day (Bcf/d), down 1 percent per share
- Total oil and natural gas liquids (NGLs) production increased 6 percent to almost 136,000 barrels per day (bbls/d), up 6 percent per share
- Foster Creek and Christina Lake oil production grew 65 percent to approximately 40,700 bbls/d net to EnCana
- Operating and administrative costs of $1.15 per thousand cubic feet equivalent (Mcfe) decreased from $1.71 per Mcfe in the second quarter of 2008, primarily due to lower long-term incentive costs as a result of a decline in share price, a weaker Canadian dollar, and lower repairs, maintenance and workover costs
Operating – Downstream
- Refined products averaged 428,000 bbls/d (214,000 bbls/d net to EnCana), down 8 percent
- Refinery crude utilization of 89 percent or 404,000 bbls/d crude throughput (202,000 bbls/d net to EnCana), down 8 percent.
Net earnings positively impacted by hedging program
EnCana’s net earnings were impacted by mark-to-market accounting for hedging contracts. EnCana’s second quarter net earnings of $239 million were down $982 million from the second quarter of 2008. Net earnings in the second quarter of 2009 included a $900 million after-tax, realized gain on hedging, primarily offset by a $750 million after-tax, unrealized loss that was previously included in net earnings as unrealized gains due to mark-to-market accounting. It is because of these dramatic mark-to-market accounting swings in net earnings that EnCana focuses on operating earnings as a better measure of quarter-over-quarter earnings performance.
Realized after-tax hedging gains for the first eight months of the 2008-2009 natural gas year, which runs from November 1, 2008 to October 31, 2009, were $1.9 billion and, as of June 30, 2009, unrealized after-tax gains for the remainder of the gas year were about $1.1 billion, for a total of approximately $3.0 billion, after tax.
Financial Summary – Total Consolidated | ||||||||||||
(for the period ended June 30)
($ millions, except per share amounts) | Q2 2009 |
Q2
2008 | % ∆ | 6 months 2009 | 6 months 2008 | % ∆ | ||||||
Cash flow1 | 2,153 | 2,889 | -25 | 4,097 | 5,278 | -22 | ||||||
Per share diluted | 2.87 | 3.85 | -25 | 5.45 | 7.02 | -22 | ||||||
Operating earnings1 | 917 | 1,469 | -38 | 1,865 | 2,514 | -26 | ||||||
Per share diluted | 1.22 | 1.96 | -38 | 2.48 | 3.34 | -26 | ||||||
Net earnings | 239 | 1,221 | -80 | 1,201 | 1,314 | -9 | ||||||
Per share diluted | 0.32 | 1.63 | -80 | 1.60 | 1.75 | -9 | ||||||
Earnings Reconciliation Summary – Total Consolidated | ||||||||||||
Net earnings | 239 | 1,221 | 1,201 | 1,314 | ||||||||
Add back (losses) & deduct gains | ||||||||||||
Unrealized mark-to-market gain (loss), after tax | (750) | (235) | (661) | (972) | ||||||||
Non-operating foreign exchange gain (loss), after tax | 72 | (13) | (3) | (228) | ||||||||
Operating earnings1 | 917 | 1,469 | -38 | 1,865 | 2,514 | -26 | ||||||
Per share diluted | 1.22 | 1.96 | -38 | 2.48 | 3.34 | -26 | ||||||
1 Cash flow and operating earnings are non-GAAP measures as defined in Note 1 on Page 8.
Production & Drilling Summary | ||||||||||||
Total Consolidated | ||||||||||||
(for the period ended June 30) (After royalties) | Q2 2009 | Q2 2008 | % ∆ | 6 months 2009 | 6 months 2008 | % ∆ | ||||||
Natural Gas (MMcf/d) | 3,788 | 3,841 | -1 | 3,828 | 3,787 | +1 | ||||||
Natural gas production per 1,000 shares (Mcf/d) | 5.04 | 5.12 | -1 | 5.10 | 5.05 | +1 | ||||||
Oil and NGLs (Mbbls/d) | 136 | 128 | +6 | 135 | 132 | +2 | ||||||
Oil and NGLs production per 1,000 shares (Mcfe/d) | 1.09 | 1.02 | +6 | 1.08 | 1.06 | +2 | ||||||
Total Production (MMcfe/d) | 4,602 | 4,607 | - | 4,638 | 4,582 | +1 | ||||||
Total production per 1,000 shares (Mcfe/d) | 6.13 | 6.14 | - | 6.18 | 6.11 | +1 | ||||||
Net wells drilled | 216 | 409 | -47 | 1,099 | 1,552 | -29 | ||||||
Key resource play oil production grows 27 percent; key resource play natural gas production steady
Oil and natural gas production from key resource plays increased 1 percent to 3.56 Bcfe/d compared to 3.51 Bcfe/d in the second quarter of 2008. Oil production was up 27 percent from the second quarter of 2008 to about 75,000 bbls/d led by Foster Creek and Christina Lake. Natural gas resource play production was down slightly, by 1 percent, to 3.1 Bcf/d, with lower volumes offset by Cutbank Ridge, which saw strong performance from the company’s Montney developments in British Columbia. Production volumes benefited from lower royalties in Alberta, which were offset by a decision, due to lower prices and netbacks in certain areas, to shut in some wells, restrict some wells’ productive capacity and delay some well completions or tie-ins to sales pipelines. These company-wide initiatives resulted in between 300 million and 400 million cubic feet per day (MMcf/d) being kept off line.
Integrated oil business contributes solid second quarter performance
EnCana’s integrated oil business continued its strong performance with Foster Creek and Christina Lake production increasing 65 percent to about 40,700 bbls/d compared to the same quarter in 2008. Year-over-year oil prices fell dramatically from the record highs seen one year ago, but prices recovered significantly, up close to 40 percent, from the low levels experienced in the first quarter of 2009. Operating cash flow for Foster Creek and Christina Lake was up 11 percent to $139 million in 2009 compared to $125 million in 2008. The downstream operations reported a 55 percent decrease in operating cash flow to $154 million from $342 million mainly due to lower crack spreads and capacity utilization.
Expansion of enhanced oil production capacity at Foster Creek and Christina Lake remains on track
At Foster Creek, phases D and E were commissioned in the second quarter, each adding 30,000 bbls/d of productive capacity. Production continues to ramp up and is on target to exit 2009 exceeding 90,000 bbls/d (45,000 bbls/d net to EnCana). In the second quarter, a regulatory application was initiated for Foster Creek’s phases F, G, and H with each phase expected to add about 30,000 bbls/d of productive capacity. At Christina Lake, construction of phase C continues to proceed on schedule and on budget. Phase C is expected to add about 40,000 bbls/d of capacity, with first production forecast in late 2011. Phase D of the Christina Lake project is targeted to be sanctioned by EnCana and ConocoPhillips in the fourth quarter of 2009. Regulatory applications for phases E, F and G at Christina Lake are expected to be filed in the third quarter of 2009 with each of these new phases designed to add approximately 40,000 bbls/d of productive capacity. EnCana continues to proceed through the regulatory application process for future expansion phases at Foster Creek and Christina Lake although exact timing of construction and initial production from these phases is subject to receipt of regulatory approvals and partnership sanction.
Haynesville and Horn River shale plays continue to show very strong results
EnCana continues to see improved operational performance and strong initial production rates from its Haynesville shale gas play. To date, EnCana has drilled 25 gross horizontal wells in the play. EnCana has increased fracture stimulations in each horizontal well from eight to as many as 14. This efficiency initiative has helped increase initial production rates and reduce well costs by about 35 percent from prior wells to an estimated $9 million per well. The strongest well performance continues to be in the northern portion of the company’s Red River Parish leases where EnCana has a joint venture with Shell. EnCana exited the second quarter with gross production from North Louisiana of about 100 MMcf/d. EnCana is currently operating 10 rigs in the Haynesville Shale, up from five at the start of 2009, and is participating in another four rigs operated by Shell.
At Horn River, the joint drilling program by EnCana and Apache Corporation at Two Island Lake continues to meet or exceed expectations for both initial well production and expected size of the resource. As a result of the joint venture’s combined activities, to date 32 gross wells have been drilled to evaluate the basin and 10 gross horizontal wells placed on production. Similar to activity at the Haynesville, fracture stimulations at Horn River have increased to up to 14 stages per horizontal section. The first wells completed in 2009 were placed on production towards the end of the quarter. The wells have shown strong results with flow rates of 9.5 MMcf/d to 11 MMcf/d after 15 days of initial flow. EnCana also commissioned a new compression and dehydration facility as well as a gas gathering pipeline that connects the Two Island Lake area with the Spectra pipeline system near the proposed EnCana operated Cabin gas plant.
Large opportunity ahead for abundant, affordable, cleaner-burning natural gas
“Looking ahead, we strongly believe there are tremendous opportunities for expanding the use of clean-burning natural gas to help solve some of our continent’s most pressing energy, environmental and economic challenges. A number of respected geological authorities have recently confirmed the abundant nature of North American natural gas. This abundance will help ensure an affordable future for expanding natural gas in our economy, primarily by displacing foreign oil in transportation and by fuelling electricity generation. While the use of natural gas as a convenient and economic transportation fuel for trucks and cars is not common in North America, it is in wide use on other continents. As a step in that direction, EnCana has started to convert a portion of its vehicle fleet to run on natural gas in select Canadian and U.S. operating locations,” Eresman said.
Growth from key North American resource plays | ||||||||||||||||||
Resource Play (After royalties) | Daily Production | |||||||||||||||||
2009 | 2008 | 2007 | ||||||||||||||||
YTD | Q2 | Q1 | Full Year | Q4 | Q3 | Q2 | Q1 | Full Year | ||||||||||
Natural Gas | ||||||||||||||||||
(MMcf/d) | ||||||||||||||||||
Jonah | 600 | 576 | 623 | 603 | 573 | 615 | 630 | 595 | 557 | |||||||||
Piceance | 371 | 355 | 386 | 385 | 377 | 407 | 383 | 372 | 348 | |||||||||
East Texas | 356 | 304 | 409 | 334 | 408 | 339 | 316 | 273 | 143 | |||||||||
Fort Worth | 144 | 138 | 149 | 142 | 143 | 148 | 137 | 140 | 124 | |||||||||
Greater Sierra | 215 | 216 | 215 | 220 | 228 | 228 | 219 | 205 | 211 | |||||||||
Cutbank Ridge | 332 | 340 | 323 | 296 | 311 | 322 | 280 | 271 | 258 | |||||||||
Bighorn | 171 | 186 | 156 | 167 | 165 | 185 | 170 | 146 | 126 | |||||||||
CBM | 319 | 330 | 309 | 304 | 308 | 309 | 303 | 298 | 259 | |||||||||
Shallow Gas | 667 | 661 | 673 | 700 | 683 | 691 | 712 | 715 | 726 | |||||||||
Total natural gas | ||||||||||||||||||
(MMcf/d) | 3,175 | 3,106 | 3,243 | 3,151 | 3,196 | 3,244 | 3,150 | 3,015 | 2,752 | |||||||||
Oil (Mbbls/d) | ||||||||||||||||||
Foster Creek | 31 | 34 | 28 | 26 | 29 | 27 | 21 | 27 | 24 | |||||||||
Christina Lake | 6 | 6 | 7 | 4 | 6 | 5 | 4 | 2 | 3 | |||||||||
Pelican Lake | 20 | 19 | 21 | 22 | 20 | 22 | 21 | 24 | 23 | |||||||||
Weyburn | 16 | 15 | 16 | 14 | 15 | 14 | 13 | 14 | 15 | |||||||||
Total oil (Mbbls/d)1 | 74 | 75 | 72 | 66 | 71 | 67 | 59 | 67 | 65 | |||||||||
Total (MMcfe/d)1 | 3,617 | 3,557 | 3,676 | 3,548 | 3,621 | 3,648 | 3,506 | 3,417 | 3,141 | |||||||||
% change from prior period | +4.6 | -3.2 | +1.5 | +13.0 | -0.7 | +4.1 | +2.6 | +2.7 | +12.9 |
1 Totals may not add due to rounding.
Drilling activity in key North American resource plays | |||||||||||||||||||
Resource Play | Net Wells Drilled | ||||||||||||||||||
2009 | 2008 | 2007 | |||||||||||||||||
YTD | Q2 | Q1 | Full Year | Q4 | Q3 | Q2 | Q1 | Full Year | |||||||||||
Natural Gas | |||||||||||||||||||
Jonah | 65 | 30 | 35 | 175 | 40 | 43 | 49 | 43 | 135 | ||||||||||
Piceance | 88 | 35 | 53 | 328 | 70 | 94 | 81 | 83 | 286 | ||||||||||
East Texas | 26 | 11 | 15 | 78 | 23 | 22 | 22 | 11 | 35 | ||||||||||
Fort Worth | 22 | 6 | 16 | 83 | 21 | 21 | 20 | 21 | 75 | ||||||||||
Greater Sierra | 25 | 10 | 15 | 106 | 14 | 29 | 27 | 36 | 109 | ||||||||||
Cutbank Ridge | 38 | 18 | 20 | 82 | 17 | 17 | 24 | 24 | 93 | ||||||||||
Bighorn | 35 | 14 | 21 | 64 | 5 | 11 | 18 | 30 | 62 | ||||||||||
CBM | 279 | 1 | 278 | 698 | 359 | 78 | 10 | 251 | 1,079 | ||||||||||
Shallow Gas | 381 | 45 | 336 | 1,195 | 383 | 233 | 83 | 496 | 1,914 | ||||||||||
Total gas wells | 959 | 170 | 789 | 2,809 | 932 | 548 | 334 | 995 | 3,788 | ||||||||||
Oil | |||||||||||||||||||
Foster Creek | 16 | 10 | 6 | 20 | 1 | 6 | 1 | 12 | 23 | ||||||||||
Christina Lake | - | - | - | - | - | - | - | - | 3 | ||||||||||
Pelican Lake | 5 | 1 | 4 | - | - | - | - | - | - | ||||||||||
Weyburn | - | - | - | 21 | 3 | 4 | 5 | 9 | 37 | ||||||||||
Total oil wells | 21 | 11 | 10 | 41 | 4 | 10 | 6 | 21 | 63 | ||||||||||
Total | 980 | 181 | 799 | 2,850 | 936 | 558 | 340 | 1,016 | 3,851 | ||||||||||
Second quarter natural gas and oil prices | |||||||||||||
Q2 2009 |
Q2
2008 | % ∆ | 6 months 2009 | 6 months 2008 | % ∆ | ||||||||
Natural gas ($/MMBtu) | |||||||||||||
NYMEX | 3.50 | 10.93 | -68 | 4.19 | 9.48 | -56 | |||||||
EnCana realized gas price1 ($/Mcf) | 6.99 | 8.54 | -18 | 7.11 | 8.29 | -14 | |||||||
Oil and NGLs ($/bbl) | |||||||||||||
WTI | 59.79 | 123.80 | -52 | 51.68 | 111.12 | -53 | |||||||
Western Canadian Select (WCS) | 52.37 | 102.18 | -49 | 43.50 | 89.58 | -51 | |||||||
Differential WTI/WCS | 7.42 | 21.62 | -66 | 8.18 | 21.54 | -62 | |||||||
EnCana realized liquids price 1 | 50.23 | 90.47 | -44 | 42.45 | 79.77 | -47 | |||||||
Chicago 3-2-1 crack spread ($/bbl) | 10.95 | 13.60 | -19 | 10.35 | 10.65 | -3 | |||||||
1 Realized prices include the impact of financial hedging. | |||||||||||||
Price risk management
Risk management positions at June 30, 2009 are presented in Note 16 to the unaudited Interim Consolidated Financial Statements. In the second quarter of 2009, EnCana’s commodity price risk management measures resulted in realized gains of approximately $900 million after tax, composed of an $896 million after-tax gain on gas prices and basis hedges and a $4 million after-tax gain on other hedges.
EnCana has hedged two-thirds of expected 2009 natural gas production, about 2.6 Bcf/d, through October of this year at an average NYMEX equivalent price of $9.13 per Mcf. EnCana has also extended its risk management program through 2010. As of July 21, 2009, EnCana had established fixed price hedges on more than 45 percent of the company's expected 2010 natural gas production - or about 2 Bcf/d - at an average NYMEX equivalent price of $6.09 per Mcf for the gas year, which runs from November 1, 2009 to October 31, 2010. EnCana also has 20,000 bbls/d of expected 2010 oil production hedged at an average fixed price of WTI $76.45 per bbl. This price hedging strategy increases certainty in cash flow to help ensure that EnCana can meet its capital and dividend requirements without substantially adding to debt. EnCana continually assesses its hedging needs and the opportunities available prior to establishing its capital program for the upcoming year.
Corporate developments
Quarterly dividend of 40 cents per share declared
EnCana’s Board of Directors has declared a quarterly dividend of 40 cents per share payable on September 30, 2009 to common shareholders of record as of September 15, 2009. Based on the July 22, 2009 closing share price on the New York Stock Exchange of $52.57, this represents an annualized yield of about 3 percent.
“Plans for splitting EnCana into two independent companies, creating an integrated oil company and a pure-play natural gas company, continue to be evaluated, but are currently on hold as market conditions continue to be volatile,” Eresman said.
Guidance updated
EnCana has updated its 2009 guidance for total natural gas, oil and NGLs production to a range of 4.4 to 4.8 MMcfe/d from 4.5 to 4.7 MMcfe/d. EnCana has also updated its capital investment guidance from $6.1 billion to a range of $5.5 billion to $6 billion. Total operating cost guidance has been reduced to $1.00 from $1.10 per Mcfe. Updated guidance and key resource play information is posted on the company’s website at www.encana.com.
EnCana sells non-core properties for $632 million
On July 16, 2009, EnCana announced it had reached an agreement to sell approximately 409,000 net acres of non-core natural gas and oil producing properties for approximately $632 million to Bonavista Energy Trust. Current production on these lands is approximately 60 MMcfe/d, after royalties. The transaction includes properties known as the Hoadley trend which covers an expansive area in west-central Alberta. The sale has an effective date of April 1, 2009 and is subject to typical closing conditions and regulatory approvals. It is expected to close in the third quarter of 2009.
Financial strength
EnCana has a very strong balance sheet, with 88 percent of EnCana’s outstanding debt comprised of long-term, fixed-rate debt with an average remaining term of more than 13 years. Upcoming debt maturities in 2009 are $250 million and in 2010 are $200 million. At June 30, 2009, EnCana had $3.4 billion in unused committed credit facilities. EnCana manages its financial strategy to achieve a strong investment grade credit rating. EnCana targets a debt to capitalization ratio of less than 40 percent and a debt to adjusted EBITDA ratio of less than 2.0 times. At June 30, 2009, the company’s debt to capitalization ratio was 27 percent and debt to adjusted EBITDA, on a trailing 12-month basis, was 0.7 times.
On May 4, 2009, EnCana completed a public offering in the United States of $500 million notes with an interest rate of 6.50 percent due on May 15, 2019. The net proceeds of the offering were used to repay a portion of EnCana's existing bank and commercial paper indebtedness. The offering was made in the United States under EnCana's previously filed shelf prospectus dated March 11, 2008 and a prospectus supplement dated April 29, 2009.
In the quarter, EnCana invested $1.1 billion in capital on continued development of the company’s long-term production and refining assets – including the coker and refinery expansion (CORE) project at the Wood River refinery in Illinois, expansion of upstream oil projects in northeast Alberta, development of the Deep Panuke natural gas project offshore Nova Scotia, and other long-term upstream projects with substantial future growth potential.
CONFERENCE CALL TODAY |
11 a.m. Mountain Time (1 p.m. Eastern Time) |
EnCana will host a conference call today Thursday, July 23, 2009 starting at 11:00 a.m. MT (1:00 p.m. ET). To participate, please dial (800) 733-7560 (toll-free in North America) or (416) 644-3414 approximately 10 minutes prior to the conference call. An archived recording of the call will be available from approximately 1:00 p.m. MT on July 23 until midnight July 30, 2009 by dialing (877) 289-8525 or (416) 640-1917 and entering passcode 21307975 followed by the pound (#) sign. |
A live audio webcast of the conference call will also be available via EnCana’s website, www.encana.com, under Investor Relations. The webcast will be archived for approximately 90 days. |
NOTE 1: Non-GAAP measures
This news release contains references to non-GAAP measures as follows:
- Cash flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the Consolidated Statement of Cash Flows, in this news release and interim financial statements.
- Free cash flow is a non-GAAP measure that EnCana defines as cash flow in excess of capital investment, excluding net acquisitions and divestitures, and is used to determine the funds available for other investing and/or financing activities.
- Operating earnings is a non-GAAP measure that shows net earnings excluding non-operating items such as the after-tax impacts of a gain/loss on discontinuance, the after-tax gain/loss of unrealized mark-to-market accounting for derivative instruments, the after-tax gain/loss on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, the after-tax foreign exchange gain/loss on settlement of intercompany transactions, future income tax on foreign exchange related to U.S. dollar intercompany debt recognized for tax purposes only and the effect of changes in statutory income tax rates. Management believes that these excluded items reduce the comparability of the company’s underlying financial performance between periods. The majority of the U.S. dollar debt issued from Canada has maturity dates in excess of five years.
- Capitalization is a non-GAAP measure defined as debt plus shareholders’ equity. Debt to capitalization and debt to adjusted EBITDA are two ratios which management uses to steward the company’s overall debt position as measures of the company’s overall financial strength.
- Adjusted EBITDA is a non-GAAP measure defined as net earnings before gains or losses on divestitures, income taxes, foreign exchange gains or losses, interest net, accretion of asset retirement obligation, and depreciation, depletion and amortization.
These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding EnCana’s liquidity and its ability to generate funds to finance its operations.
EnCana Corporation
With an enterprise value of approximately $50 billion, EnCana is a leading North American unconventional natural gas and integrated oil company. By partnering with employees, community organizations and other businesses, EnCana contributes to the strength and sustainability of the communities where it operates. EnCana common shares trade on the Toronto and New York stock exchanges under the symbol ECA.
ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION – EnCana's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to EnCana by Canadian securities regulatory authorities which permits it to provide such disclosure in accordance with U.S. disclosure requirements. The information provided by EnCana may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). EnCana’s reserves quantities represent net proved reserves calculated using the standards contained in Regulation S-X of the U.S. Securities and Exchange Commission. Further information about the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading "Note Regarding Reserves Data and Other Oil and Gas Information" in EnCana's Annual Information Form.
In this news release, certain crude oil and NGLs volumes have been converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). Also, certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the same basis. BOE and cfe may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS – In the interests of providing EnCana shareholders and potential investors with information regarding EnCana, including management’s assessment of EnCana’s and its subsidiaries’ future plans and operations, certain statements contained in this news release are forward-looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as “forward-looking statements.” Forward-looking statements in this news release include, but are not limited to: future economic and operating performance (including per share growth, debt to capitalization ratio, debt to adjusted EBITDA ratio, sustainable growth and returns, free cash flow, cash flow, cash flow per share, operating earnings and increases in net asset value); projections contained in the company’s guidance forecasts and the anticipated ability to meet the company’s guidance forecasts; anticipated life of proved reserves; anticipated growth and success of resource plays and the expected characteristics of resource plays; anticipated production and drilling in the Horn River and Haynesville areas; anticipated cost reductions and production efficiencies from fracture stimulations; anticipated capacity and timing for the proposed Cabin Gas Plant; planned expansion of in-situ oil production; anticipated crude oil and natural gas prices, including basis differentials for various regions; anticipated expansion and production at Foster Creek and Christina Lake; anticipated divestitures; potential dividends; anticipated success of EnCana’s price risk management strategy; anticipated hedging gains; potential demand for natural gas; anticipated drilling; potential capital expenditures and investment; potential oil, natural gas and NGLs production in 2009 and beyond; anticipated plans to ramp up production in the event of the recovery of natural gas prices; anticipated conversion of natural gas powered vehicles; anticipated costs and cost reductions; the company’s plans for splitting into two independent companies and the conditions which may be required therefore; the expected closing date for the Bonavista Energy Trust transaction; and references to potential exploration. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the company’s actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These assumptions, risks and uncertainties include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions based upon the company’s current guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the company’s marketing operations, including credit risks; imprecision of reserves estimates and estimates of recoverable quantities of oil, natural gas and liquids from resource plays and other sources not currently classified as proved reserves; the ability of the company and ConocoPhillips to successfully manage and operate the integrated North American oil business and the ability of the parties to obtain necessary regulatory approvals; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining crude oil; risks associated with technology; the company’s ability to replace and expand oil and gas reserves; its ability to generate sufficient cash flow from operations to meet its current and future obligations; its ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; the company’s ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations or the interpretations of such laws or regulations; political and economic conditions in the countries in which the company operates; the risk of war, hostilities, civil insurrection and instability affecting countries in which the company operates and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the company; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by EnCana. Although EnCana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive.
Forward-looking information respecting anticipated 2009 cash flow for EnCana is based upon achieving average production of oil and gas for 2009 of approximately 4.4 to 4.8 Bcfe/d, average commodity prices for 2009 based on year-to-date actuals, forward curve commodity prices and US/Canadian dollar foreign exchange rate estimates as of June 30, 2009, and an average number of outstanding shares for EnCana of approximately 750 million. Assumptions relating to forward-looking statements generally include EnCana’s current expectations and projections made by the company in light of, and generally consistent with, its historical experience and its perception of historical trends, as well as expectations regarding rates of advancement and innovation, generally consistent with and informed by its past experience, all of which are subject to the risk factors identified elsewhere in this news release.
Furthermore, the forward-looking statements contained in this news release are made as of the date of this news release, and, except as required by law, EnCana does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this news release are expressly qualified by this cautionary statement.
Further information on EnCana Corporation is available on the company’s website, www.encana.com, or by contacting:
FOR FURTHER INFORMATION: | |||||
Investor contact: | Media contact: | ||||
EnCana Corporate Communications | |||||
Paul Gagne | Alan Boras | ||||
Vice-President, Investor Relations | Manager, Media Relations | ||||
(403) 645-4737 | (403) 645-4747 | ||||
Ryder McRitchie | |||||
Manager, Investor Relations | |||||
(403) 645-2007 | |||||
Susan Grey | |||||
Manager, Investor Relations | |||||
(403) 645-4751 | |||||
EnCana Corporation |
Interim Consolidated Financial Statements |
(unaudited) |
For the period ended June 30, 2009 |
(U.S. Dollars) |
Consolidated Statement of Earnings (unaudited) | |||||||||||||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||||||||||||
($ millions, except per share amounts) | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||
Revenues, Net of Royalties | (Note 4) | $ | 3,762 | $ | 7,422 | $ | 8,370 | $ | 12,856 | ||||||||||||||||||||
Expenses | (Note 4) | ||||||||||||||||||||||||||||
Production and mineral taxes | 32 | 154 | 93 | 268 | |||||||||||||||||||||||||
Transportation and selling | 321 | 427 | 614 | 839 | |||||||||||||||||||||||||
Operating | 512 | 709 | 1,065 | 1,405 | |||||||||||||||||||||||||
Purchased product | 1,385 | 2,882 | 2,594 | 5,275 | |||||||||||||||||||||||||
Depreciation, depletion and amortization | 980 | 1,097 | 1,963 | 2,132 | |||||||||||||||||||||||||
Administrative | 120 | 225 | 205 | 381 | |||||||||||||||||||||||||
Interest, net | (Note 6) | 129 | 147 | 233 | 281 | ||||||||||||||||||||||||
Accretion of asset retirement obligation | (Note 11) | 19 | 20 | 36 | 41 | ||||||||||||||||||||||||
Foreign exchange (gain) loss, net | (Note 7) | (60 | ) | (35 | ) | (2 | ) | 60 | |||||||||||||||||||||
(Gain) loss on divestitures | (Note 5) | 3 | (17 | ) | 2 | (17 | ) | ||||||||||||||||||||||
3,441 | 5,609 | 6,803 | 10,665 | ||||||||||||||||||||||||||
Net Earnings Before Income Tax | 321 | 1,813 | 1,567 | 2,191 | |||||||||||||||||||||||||
Income tax expense | (Note 8) | 82 | 592 | 366 | 877 | ||||||||||||||||||||||||
Net Earnings | $ | 239 | $ | 1,221 | $ | 1,201 | $ | 1,314 | |||||||||||||||||||||
Net Earnings per Common Share | (Note 15) | ||||||||||||||||||||||||||||
Basic | $ | 0.32 | $ | 1.63 | $ | 1.60 | $ | 1.75 | |||||||||||||||||||||
Diluted | $ | 0.32 | $ | 1.63 | $ | 1.60 | $ | 1.75 | |||||||||||||||||||||
See accompanying Notes to Consolidated Financial Statements. |
Consolidated Statement of Retained Earnings (unaudited) | ||||||||||||||||||||||||
Six Months Ended | ||||||||||||||||||||||||
June 30, | ||||||||||||||||||||||||
($ millions) | 2009 | 2008 | ||||||||||||||||||||||
Retained Earnings, Beginning of Year | $ | 17,584 | $ | 13,082 | ||||||||||||||||||||
Net Earnings | 1,201 | 1,314 | ||||||||||||||||||||||
Dividends on Common Shares | (601 | ) | (600 | ) | ||||||||||||||||||||
Charges for Normal Course Issuer Bid | (Note 12) | - | (243 | ) | ||||||||||||||||||||
Retained Earnings, End of Period | $ | 18,184 | $ | 13,553 | ||||||||||||||||||||
Consolidated Statement of Comprehensive Income (unaudited) | ||||||||||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||||||
($ millions) | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||
Net Earnings | $ | 239 | $ | 1,221 | $ | 1,201 | $ | 1,314 | ||||||||||||||||
Other Comprehensive Income, Net of Tax | ||||||||||||||||||||||||
Foreign Currency Translation Adjustment | 916 | 48 | 645 | (352 | ) | |||||||||||||||||||
Comprehensive Income | $ | 1,155 | $ | 1,269 | $ | 1,846 | $ | 962 | ||||||||||||||||
Consolidated Statement of Accumulated Other Comprehensive Income (unaudited) | ||||||||||||||||||||||||
Six Months Ended | ||||||||||||||||||||||||
June 30, | ||||||||||||||||||||||||
($ millions) | 2009 | 2008 | ||||||||||||||||||||||
Accumulated Other Comprehensive Income, Beginning of Year | $ | 833 | $ | 3,063 | ||||||||||||||||||||
Foreign Currency Translation Adjustment | 645 | (352 | ) | |||||||||||||||||||||
Accumulated Other Comprehensive Income, End of Period | $ | 1,478 | $ | 2,711 | ||||||||||||||||||||
See accompanying Notes to Consolidated Financial Statements. |
Consolidated Balance Sheet (unaudited) | |||||||||||||||||
As at | As at | ||||||||||||||||
June 30, | December 31, | ||||||||||||||||
($ millions) | 2009 | 2008 | |||||||||||||||
Assets | |||||||||||||||||
Current Assets | |||||||||||||||||
Cash and cash equivalents | $ | 330 | $ | 383 | |||||||||||||
Accounts receivable and accrued revenues | 1,472 | 1,568 | |||||||||||||||
Current portion of partnership contribution receivable | 321 | 313 | |||||||||||||||
Risk management | (Note 16) | 1,927 | 2,818 | ||||||||||||||
Inventories | (Note 9) | 710 | 520 | ||||||||||||||
4,760 | 5,602 | ||||||||||||||||
Property, Plant and Equipment, net | (Note 4) | 37,377 | 35,424 | ||||||||||||||
Investments and Other Assets | 955 | 727 | |||||||||||||||
Partnership Contribution Receivable | 2,672 | 2,834 | |||||||||||||||
Risk Management | (Note 16) | 44 | 234 | ||||||||||||||
Goodwill | 2,530 | 2,426 | |||||||||||||||
(Note 4) | $ | 48,338 | $ | 47,247 | |||||||||||||
Liabilities and Shareholders' Equity | |||||||||||||||||
Current Liabilities | |||||||||||||||||
Accounts payable and accrued liabilities | $ | 2,401 | $ | 2,871 | |||||||||||||
Income tax payable | 527 | 424 | |||||||||||||||
Current portion of partnership contribution payable | 315 | 306 | |||||||||||||||
Risk management | (Note 16) | 14 | 43 | ||||||||||||||
Current portion of long-term debt | (Note 10) | 250 | 250 | ||||||||||||||
3,507 | 3,894 | ||||||||||||||||
Long-Term Debt | (Note 10) | 8,688 | 8,755 | ||||||||||||||
Other Liabilities | 903 | 576 | |||||||||||||||
Partnership Contribution Payable | 2,697 | 2,857 | |||||||||||||||
Risk Management | (Note 16) | 26 | 7 | ||||||||||||||
Asset Retirement Obligation | (Note 11) | 1,325 | 1,265 | ||||||||||||||
Future Income Taxes | 6,945 | 6,919 | |||||||||||||||
24,091 | 24,273 | ||||||||||||||||
Shareholders' Equity | |||||||||||||||||
Share capital | (Note 12) | 4,579 | 4,557 | ||||||||||||||
Paid in surplus | (Note 12) | 6 | - | ||||||||||||||
Retained earnings | 18,184 | 17,584 | |||||||||||||||
Accumulated other comprehensive income | 1,478 | 833 | |||||||||||||||
Total Shareholders' Equity | 24,247 | 22,974 | |||||||||||||||
$ | 48,338 | $ | 47,247 | ||||||||||||||
See accompanying Notes to Consolidated Financial Statements. |
Consolidated Statement of Cash Flows (unaudited) | |||||||||||||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||||||||||||
($ millions) | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||
Operating Activities | |||||||||||||||||||||||||||||
Net earnings | $ | 239 | $ | 1,221 | $ | 1,201 | $ | 1,314 | |||||||||||||||||||||
Depreciation, depletion and amortization | 980 | 1,097 | 1,963 | 2,132 | |||||||||||||||||||||||||
Future income taxes | (Note 8) | (231 | ) | 152 | (194 | ) | 73 | ||||||||||||||||||||||
Unrealized (gain) loss on risk management | (Note 16) | 1,118 | 318 | 1,007 | 1,411 | ||||||||||||||||||||||||
Unrealized foreign exchange (gain) loss | (69 | ) | (11 | ) | (49 | ) | 65 | ||||||||||||||||||||||
Accretion of asset retirement obligation | (Note 11) | 19 | 20 | 36 | 41 | ||||||||||||||||||||||||
(Gain) loss on divestitures | (Note 5) | 3 | (17 | ) | 2 | (17 | ) | ||||||||||||||||||||||
Other | 94 | 109 | 131 | 259 | |||||||||||||||||||||||||
Net change in other assets and liabilities | 9 | (171 | ) | 23 | (264 | ) | |||||||||||||||||||||||
Net change in non-cash working capital | (207 | ) | (722 | ) | (334 | ) | (1,260 | ) | |||||||||||||||||||||
Cash From Operating Activities | 1,955 | 1,996 | 3,786 | 3,754 | |||||||||||||||||||||||||
Investing Activities | |||||||||||||||||||||||||||||
Capital expenditures | (Note 4) | (1,088 | ) | (1,996 | ) | (2,675 | ) | (3,903 | ) | ||||||||||||||||||||
Proceeds from divestitures | (Note 5) | 20 | 79 | 53 | 151 | ||||||||||||||||||||||||
Corporate acquisition | (Note 5) | (24 | ) | - | (24 | ) | - | ||||||||||||||||||||||
Net change in investments and other | (28 | ) | (18 | ) | (170 | ) | (9 | ) | |||||||||||||||||||||
Net change in non-cash working capital | (187 | ) | (101 | ) | (279 | ) | 191 | ||||||||||||||||||||||
Cash (Used in) Investing Activities | (1,307 | ) | (2,036 | ) | (3,095 | ) | (3,570 | ) | |||||||||||||||||||||
Financing Activities | |||||||||||||||||||||||||||||
Net issuance (repayment) of revolving long-term debt | (1,170 | ) | 426 | (665 | ) | 367 | |||||||||||||||||||||||
Issuance of long-term debt | (Note 10) | 496 | - | 496 | 723 | ||||||||||||||||||||||||
Repayment of long-term debt | - | (196 | ) | - | (196 | ) | |||||||||||||||||||||||
Issuance of common shares | (Note 12) | 19 | 13 | 21 | 76 | ||||||||||||||||||||||||
Purchase of common shares | (Note 12) | - | (15 | ) | - | (326 | ) | ||||||||||||||||||||||
Dividends on common shares | (301 | ) | (300 | ) | (601 | ) | (600 | ) | |||||||||||||||||||||
Cash From (Used in) Financing Activities | (956 | ) | (72 | ) | (749 | ) | 44 | ||||||||||||||||||||||
Foreign Exchange Gain (Loss) on Cash and Cash | |||||||||||||||||||||||||||||
Equivalents Held in Foreign Currency | 9 | 1 | 5 | (3 | ) | ||||||||||||||||||||||||
Increase (Decrease) in Cash and Cash Equivalents | (299 | ) | (111 | ) | (53 | ) | 225 | ||||||||||||||||||||||
Cash and Cash Equivalents, Beginning of Period | 629 | 889 | 383 | 553 | |||||||||||||||||||||||||
Cash and Cash Equivalents, End of Period | $ | 330 | $ | 778 | $ | 330 | $ | 778 | |||||||||||||||||||||
See accompanying Notes to Consolidated Financial Statements. |
Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)
1. Basis of Presentation
The interim Consolidated Financial Statements include the accounts of EnCana Corporation and its subsidiaries ("EnCana" or the "Company"), and are presented in accordance with Canadian generally accepted accounting principles ("GAAP"). EnCana's operations are in the business of the exploration for, the development of, and the production and marketing of natural gas, crude oil and natural gas liquids ("NGLs"), refining operations and power generation operations.
The interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2008, except as noted below. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements. Certain information and disclosures normally required to be included in the notes to the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, the interim Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2008.
2. Changes in Accounting Policies and Practices
On January 1, 2009, the Company adopted the following Canadian Institute of Chartered Accountants ("CICA") Handbook Section:
- "Goodwill and Intangible Assets", Section 3064. The new standard replaces the previous goodwill and intangible asset standard and revises the requirement for recognition, measurement, presentation and disclosure of intangible assets. The adoption of this standard has had no material impact on EnCana's Consolidated Financial Statements.
3. Recent Accounting Pronouncements
In February 2008, the CICA's Accounting Standards Board confirmed that International Financial Reporting Standards ("IFRS") will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises. EnCana will be required to report its results in accordance with IFRS beginning in 2011. The Company has developed a changeover plan to complete the transition to IFRS by January 1, 2011, including the preparation of required comparative information. The impact of IFRS on the Company's Consolidated Financial Statements is not reasonably determinable at this time.
As of January 1, 2011, EnCana will be required to adopt the following CICA Handbook sections:
- "Business Combinations", Section 1582, which replaces the previous business combinations standard. The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the statement of earnings. The adoption of this standard will impact the accounting treatment of future business combinations.
- "Consolidated Financial Statements", Section 1601, which together with Section 1602 below, replace the former consolidated financial statements standard. Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard should not have a material impact on EnCana's Consolidated Financial Statements.
- "Non-controlling Interests", Section 1602, which establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard should not have a material impact on EnCana's Consolidated Financial Statements.
4. Segmented Information
The Company's operating and reportable segments are as follows:
- Canada includes the Company’s exploration for, and development and production of natural gas, crude oil and NGLs and other related activities within the Canadian cost centre.
- USA includes the Company’s exploration for, and development and production of natural gas, NGLs and other related activities within the United States cost centre.
- Downstream Refining is focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. The refineries are jointly owned with ConocoPhillips.
- Market Optimization is primarily responsible for the sale of the Company's proprietary production. These results are included in the Canada and USA segments. Market optimization activities include third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment.
- Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once amounts are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates.
Market Optimization sells substantially all of the Company's upstream production to third-party customers. Transactions between segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis.
On December 31, 2008, EnCana updated its segmented reporting to present the upstream Canadian and United States cost centres and Downstream Refining as separate reportable segments. This resulted in EnCana presenting the Canadian portion of the Integrated Oil Division as part of the Canada segment. Previously, this was aggregated and presented in the Integrated Oil segment. Prior periods have been restated to reflect the new presentation.
EnCana has a decentralized decision making and reporting structure. Accordingly, the Company is organized into Divisions as follows:
- Canadian Plains Division includes natural gas and crude oil exploration, development and production assets located in eastern Alberta and Saskatchewan.
- Canadian Foothills Division includes natural gas exploration, development and production assets located in western Alberta and British Columbia as well as the Company’s Canadian offshore assets.
- USA Division includes natural gas exploration, development and production assets located in the United States and comprises the USA segment described above.
- Integrated Oil Division is the combined total of Integrated Oil – Canada and Downstream Refining. Integrated Oil – Canada includes the Company’s exploration for, and development and production of bitumen using enhanced recovery methods. Integrated Oil – Canada is composed of EnCana’s interests in the FCCL Partnership jointly owned with ConocoPhillips, the Athabasca natural gas assets and other bitumen interests.
Results of Operations (For the three months ended June 30)
Segment and Geographic Information | |||||||||||||||||||||||||||||||||||||
Canada | USA | Downstream Refining | |||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 2,070 | $ | 2,810 | $ | 1,126 | $ | 1,525 | $ | 1,313 | $ | 2,769 | |||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 17 | 36 | 15 | 118 | - | - | |||||||||||||||||||||||||||||||
Transportation and selling | 196 | 307 | 125 | 120 | - | - | |||||||||||||||||||||||||||||||
Operating | 291 | 396 | 99 | 186 | 112 | 127 | |||||||||||||||||||||||||||||||
Purchased product | (18 | ) | (46 | ) | - | - | 1,047 | 2,300 | |||||||||||||||||||||||||||||
1,584 | 2,117 | 887 | 1,101 | 154 | 342 | ||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 523 | 570 | 379 | 421 | 46 | 44 | |||||||||||||||||||||||||||||||
Segment Income (Loss) | $ | 1,061 | $ | 1,547 | $ | 508 | $ | 680 | $ | 108 | $ | 298 | |||||||||||||||||||||||||
Market Optimization | Corporate & Other | Consolidated | |||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 366 | $ | 647 | $ | (1,113 | ) | $ | (329 | ) | $ | 3,762 | $ | 7,422 | |||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||
Production and mineral taxes | - | - | - | - | 32 | 154 | |||||||||||||||||||||||||||||||
Transportation and selling | - | - | - | - | 321 | 427 | |||||||||||||||||||||||||||||||
Operating | 7 | 8 | 3 | (8 | ) | 512 | 709 | ||||||||||||||||||||||||||||||
Purchased product | 356 | 628 | - | - | 1,385 | 2,882 | |||||||||||||||||||||||||||||||
3 | 11 | (1,116 | ) | (321 | ) | 1,512 | 3,250 | ||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 4 | 4 | 28 | 58 | 980 | 1,097 | |||||||||||||||||||||||||||||||
Segment Income (Loss) | $ | (1 | ) | $ | 7 | $ | (1,144 | ) | $ | (379 | ) | 532 | 2,153 | ||||||||||||||||||||||||
Administrative | 120 | 225 | |||||||||||||||||||||||||||||||||||
Interest, net | 129 | 147 | |||||||||||||||||||||||||||||||||||
Accretion of asset retirement obligation | 19 | 20 | |||||||||||||||||||||||||||||||||||
Foreign exchange (gain) loss, net | (60 | ) | (35 | ) | |||||||||||||||||||||||||||||||||
(Gain) loss on divestitures | 3 | (17 | ) | ||||||||||||||||||||||||||||||||||
211 | 340 | ||||||||||||||||||||||||||||||||||||
Net Earnings Before Income Tax | 321 | 1,813 | |||||||||||||||||||||||||||||||||||
Income tax expense | 82 | 592 | |||||||||||||||||||||||||||||||||||
Net Earnings | $ | 239 | $ | 1,221 |
Product and Divisional Information | |||||||||||||||||||||||||||||||||||||||||||||
Canada Segment | |||||||||||||||||||||||||||||||||||||||||||||
Canadian Plains | Canadian Foothills | Integrated Oil - Canada | Total | ||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 820 | $ | 1,275 | $ | 907 | $ | 1,189 | $ | 343 | $ | 346 | $ | 2,070 | $ | 2,810 | |||||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 11 | 24 | 6 | 12 | - | - | 17 | 36 | |||||||||||||||||||||||||||||||||||||
Transportation and selling | 53 | 115 | 38 | 54 | 105 | 138 | 196 | 307 | |||||||||||||||||||||||||||||||||||||
Operating | 108 | 147 | 133 | 180 | 50 | 69 | 291 | 396 | |||||||||||||||||||||||||||||||||||||
Purchased product | - | - | - | - | (18 | ) | (46 | ) | (18 | ) | (46 | ) | |||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 648 | $ | 989 | $ | 730 | $ | 943 | $ | 206 | $ | 185 | $ | 1,584 | $ | 2,117 | |||||||||||||||||||||||||||||
Canadian Plains Division | |||||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | ||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 475 | $ | 629 | $ | 341 | $ | 644 | $ | 4 | $ | 2 | $ | 820 | $ | 1,275 | |||||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 5 | 13 | 6 | 11 | - | - | 11 | 24 | |||||||||||||||||||||||||||||||||||||
Transportation and selling | 10 | 18 | 43 | 97 | - | - | 53 | 115 | |||||||||||||||||||||||||||||||||||||
Operating | 51 | 74 | 55 | 72 | 2 | 1 | 108 | 147 | |||||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 409 | $ | 524 | $ | 237 | $ | 464 | $ | 2 | $ | 1 | $ | 648 | $ | 989 | |||||||||||||||||||||||||||||
Canadian Foothills Division | |||||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | ||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 823 | $ | 1,000 | $ | 74 | $ | 174 | $ | 10 | $ | 15 | $ | 907 | $ | 1,189 | |||||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 5 | 11 | 1 | 1 | - | - | 6 | 12 | |||||||||||||||||||||||||||||||||||||
Transportation and selling | 37 | 51 | 1 | 3 | - | - | 38 | 54 | |||||||||||||||||||||||||||||||||||||
Operating | 124 | 163 | 6 | 12 | 3 | 5 | 133 | 180 | |||||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 657 | $ | 775 | $ | 66 | $ | 158 | $ | 7 | $ | 10 | $ | 730 | $ | 943 | |||||||||||||||||||||||||||||
USA Division | |||||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | ||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 1,044 | $ | 1,308 | $ | 50 | $ | 130 | $ | 32 | $ | 87 | $ | 1,126 | $ | 1,525 | |||||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 11 | 107 | 4 | 11 | - | - | 15 | 118 | |||||||||||||||||||||||||||||||||||||
Transportation and selling | 125 | 120 | - | - | - | - | 125 | 120 | |||||||||||||||||||||||||||||||||||||
Operating | 77 | 106 | - | - | 22 | 80 | 99 | 186 | |||||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 831 | $ | 975 | $ | 46 | $ | 119 | $ | 10 | $ | 7 | $ | 887 | $ | 1,101 | |||||||||||||||||||||||||||||
Integrated Oil Division | |||||||||||||||||||||||||||||||||||||||||||||
Oil * | Downstream Refining | Other * | Total | ||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 277 | $ | 298 | $ | 1,313 | $ | 2,769 | $ | 66 | $ | 48 | $ | 1,656 | $ | 3,115 | |||||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||||||
Transportation and selling | 100 | 123 | - | - | 5 | 15 | 105 | 138 | |||||||||||||||||||||||||||||||||||||
Operating | 38 | 50 | 112 | 127 | 12 | 19 | 162 | 196 | |||||||||||||||||||||||||||||||||||||
Purchased product | - | - | 1,047 | 2,300 | (18 | ) | (46 | ) | 1,029 | 2,254 | |||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 139 | $ | 125 | $ | 154 | $ | 342 | $ | 67 | $ | 60 | $ | 360 | $ | 527 | |||||||||||||||||||||||||||||
* | Oil and Other comprise Integrated Oil - Canada. Other includes production of natural gas and bitumen from the Athabasca and Senlac properties. |
Segment and Geographic Information | |||||||||||||||||||||||||||||||||||||
Canada | USA | Downstream Refining | |||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 3,953 | $ | 5,313 | $ | 2,300 | $ | 2,879 | $ | 2,239 | $ | 4,815 | |||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 32 | 54 | 61 | 214 | - | - | |||||||||||||||||||||||||||||||
Transportation and selling | 366 | 604 | 248 | 235 | - | - | |||||||||||||||||||||||||||||||
Operating | 577 | 780 | 214 | 355 | 230 | 259 | |||||||||||||||||||||||||||||||
Purchased product | (31 | ) | (81 | ) | - | - | 1,796 | 4,121 | |||||||||||||||||||||||||||||
3,009 | 3,956 | 1,777 | 2,075 | 213 | 435 | ||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 1,007 | 1,139 | 795 | 818 | 97 | 88 | |||||||||||||||||||||||||||||||
Segment Income (Loss) | $ | 2,002 | $ | 2,817 | $ | 982 | $ | 1,257 | $ | 116 | $ | 347 | |||||||||||||||||||||||||
Market Optimization | Corporate & Other | Consolidated | |||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 858 | $ | 1,272 | $ | (980 | ) | $ | (1,423 | ) | $ | 8,370 | $ | 12,856 | |||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||
Production and mineral taxes | - | - | - | - | 93 | 268 | |||||||||||||||||||||||||||||||
Transportation and selling | - | - | - | - | 614 | 839 | |||||||||||||||||||||||||||||||
Operating | 15 | 19 | 29 | (8 | ) | 1,065 | 1,405 | ||||||||||||||||||||||||||||||
Purchased product | 829 | 1,235 | - | - | 2,594 | 5,275 | |||||||||||||||||||||||||||||||
14 | 18 | (1,009 | ) | (1,415 | ) | 4,004 | 5,069 | ||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 9 | 8 | 55 | 79 | 1,963 | 2,132 | |||||||||||||||||||||||||||||||
Segment Income (Loss) | $ | 5 | $ | 10 | $ | (1,064 | ) | $ | (1,494 | ) | 2,041 | 2,937 | |||||||||||||||||||||||||
Administrative | 205 | 381 | |||||||||||||||||||||||||||||||||||
Interest, net | 233 | 281 | |||||||||||||||||||||||||||||||||||
Accretion of asset retirement obligation | 36 | 41 | |||||||||||||||||||||||||||||||||||
Foreign exchange (gain) loss, net | (2 | ) | 60 | ||||||||||||||||||||||||||||||||||
(Gain) loss on divestitures | 2 | (17 | ) | ||||||||||||||||||||||||||||||||||
474 | 746 | ||||||||||||||||||||||||||||||||||||
Net Earnings Before Income Tax | 1,567 | 2,191 | |||||||||||||||||||||||||||||||||||
Income tax expense | 366 | 877 | |||||||||||||||||||||||||||||||||||
Net Earnings | $ | 1,201 | $ | 1,314 |
Product and Divisional Information | |||||||||||||||||||||||||||||||||||||||||||||
Canada Segment | |||||||||||||||||||||||||||||||||||||||||||||
Canadian Plains | Canadian Foothills | Integrated Oil - Canada | Total | ||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 1,595 | $ | 2,416 | $ | 1,822 | $ | 2,264 | $ | 536 | $ | 633 | $ | 3,953 | $ | 5,313 | |||||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 21 | 37 | 11 | 16 | - | 1 | 32 | 54 | |||||||||||||||||||||||||||||||||||||
Transportation and selling | 115 | 224 | 75 | 110 | 176 | 270 | 366 | 604 | |||||||||||||||||||||||||||||||||||||
Operating | 211 | 289 | 263 | 358 | 103 | 133 | 577 | 780 | |||||||||||||||||||||||||||||||||||||
Purchased product | - | - | - | - | (31 | ) | (81 | ) | (31 | ) | (81 | ) | |||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 1,248 | $ | 1,866 | $ | 1,473 | $ | 1,780 | $ | 288 | $ | 310 | $ | 3,009 | $ | 3,956 | |||||||||||||||||||||||||||||
Canadian Plains Division | |||||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | ||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 996 | $ | 1,219 | $ | 593 | $ | 1,193 | $ | 6 | $ | 4 | $ | 1,595 | $ | 2,416 | |||||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 8 | 18 | 13 | 19 | - | - | 21 | 37 | |||||||||||||||||||||||||||||||||||||
Transportation and selling | 21 | 37 | 94 | 187 | - | - | 115 | 224 | |||||||||||||||||||||||||||||||||||||
Operating | 102 | 147 | 106 | 140 | 3 | 2 | 211 | 289 | |||||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 865 | $ | 1,017 | $ | 380 | $ | 847 | $ | 3 | $ | 2 | $ | 1,248 | $ | 1,866 | |||||||||||||||||||||||||||||
Canadian Foothills Division | |||||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | ||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 1,671 | $ | 1,909 | $ | 131 | $ | 322 | $ | 20 | $ | 33 | $ | 1,822 | $ | 2,264 | |||||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 9 | 14 | 2 | 2 | - | - | 11 | 16 | |||||||||||||||||||||||||||||||||||||
Transportation and selling | 71 | 104 | 4 | 6 | - | - | 75 | 110 | |||||||||||||||||||||||||||||||||||||
Operating | 244 | 324 | 12 | 23 | 7 | 11 | 263 | 358 | |||||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 1,347 | $ | 1,467 | $ | 113 | $ | 291 | $ | 13 | $ | 22 | $ | 1,473 | $ | 1,780 | |||||||||||||||||||||||||||||
USA Division | |||||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | ||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 2,162 | $ | 2,491 | $ | 79 | $ | 229 | $ | 59 | $ | 159 | $ | 2,300 | $ | 2,879 | |||||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 54 | 194 | 7 | 20 | - | - | 61 | 214 | |||||||||||||||||||||||||||||||||||||
Transportation and selling | 248 | 235 | - | - | - | - | 248 | 235 | |||||||||||||||||||||||||||||||||||||
Operating | 159 | 207 | - | - | 55 | 148 | 214 | 355 | |||||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 1,701 | $ | 1,855 | $ | 72 | $ | 209 | $ | 4 | $ | 11 | $ | 1,777 | $ | 2,075 | |||||||||||||||||||||||||||||
Integrated Oil Division | |||||||||||||||||||||||||||||||||||||||||||||
Oil * | Downstream Refining | Other * | Total | ||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 440 | $ | 536 | $ | 2,239 | $ | 4,815 | $ | 96 | $ | 97 | $ | 2,775 | $ | 5,448 | |||||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | - | - | - | - | - | 1 | - | 1 | |||||||||||||||||||||||||||||||||||||
Transportation and selling | 166 | 243 | - | - | 10 | 27 | 176 | 270 | |||||||||||||||||||||||||||||||||||||
Operating | 78 | 91 | 230 | 259 | 25 | 42 | 333 | 392 | |||||||||||||||||||||||||||||||||||||
Purchased product | - | - | 1,796 | 4,121 | (31 | ) | (81 | ) | 1,765 | 4,040 | |||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 196 | $ | 202 | $ | 213 | $ | 435 | $ | 92 | $ | 108 | $ | 501 | $ | 745 | |||||||||||||||||||||||||||||
* | Oil and Other comprise Integrated Oil - Canada. Other includes production of natural gas and bitumen from the Athabasca and Senlac properties. |
Capital Expenditures | ||||||||||||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||
Capital | ||||||||||||||||||||||||||
Canadian Plains | $ | 69 | $ | 158 | $ | 228 | $ | 420 | ||||||||||||||||||
Canadian Foothills | 280 | 583 | 745 | 1,363 | ||||||||||||||||||||||
Integrated Oil - Canada | 103 | 144 | 229 | 352 | ||||||||||||||||||||||
Canada | 452 | 885 | 1,202 | 2,135 | ||||||||||||||||||||||
USA | 385 | 660 | 925 | 1,179 | ||||||||||||||||||||||
Downstream Refining | 227 | 122 | 429 | 177 | ||||||||||||||||||||||
Market Optimization | - | 5 | (3 | ) | 7 | |||||||||||||||||||||
Corporate & Other | 14 | 46 | 33 | 69 | ||||||||||||||||||||||
1,078 | 1,718 | 2,586 | 3,567 | |||||||||||||||||||||||
Acquisition Capital | ||||||||||||||||||||||||||
Canadian Plains | 1 | - | 1 | - | ||||||||||||||||||||||
Canadian Foothills | 1 | 20 | 74 | 92 | ||||||||||||||||||||||
Canada | 2 | 20 | 75 | 92 | ||||||||||||||||||||||
USA | 8 | 258 | 14 | 244 | ||||||||||||||||||||||
10 | 278 | 89 | 336 | |||||||||||||||||||||||
Total | $ | 1,088 | $ | 1,996 | $ | 2,675 | $ | 3,903 |
On September 25, 2008, EnCana acquired certain land and property in Louisiana for approximately $101 million before closing adjustments. The purchase was facilitated by an unrelated party, Brown Haynesville Leasehold LLC ("Brown Haynesville"), which held the majority of the assets in trust for the Company in anticipation of a qualifying like kind exchange for U.S. tax purposes. The relationship with Brown Haynesville represented an interest in a Variable Interest Entity ("VIE") from September 25, 2008 to March 24, 2009. During this period, EnCana was the primary beneficiary of the VIE and consolidated Brown Haynesville. On March 24, 2009, when the arrangement with Brown Haynesville was completed, the assets were transferred to EnCana.
On July 23, 2008, EnCana acquired certain land and mineral interests in Louisiana for approximately $457 million before closing adjustments. The purchase was facilitated by an unrelated party, Brown Southwest Minerals LLC ("Brown Southwest"), which held the majority of the assets in trust for the Company in anticipation of a qualifying like kind exchange for U.S. tax purposes. On November 12, 2008, an unrelated party exercised an option to purchase certain interests as part of the above acquisition for approximately $157 million, reducing the qualifying like kind exchange to approximately $300 million. The relationship with Brown Southwest represented an interest in a VIE from July 23, 2008 to January 19, 2009. During this period, EnCana was the primary beneficiary of the VIE and consolidated Brown Southwest. On January 19, 2009, when the arrangement with Brown Southwest was completed, the assets were transferred to EnCana.
Property, Plant and Equipment and Total Assets by Segment | |||||||||||||||||||||
Property, Plant and Equipment | Total Assets | ||||||||||||||||||||
As at | As at | ||||||||||||||||||||
June 30, | December 31, | June 30, | December 31, | ||||||||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||||||||||
Canada | $ | 18,362 | $ | 17,082 | $ | 24,889 | $ | 23,419 | |||||||||||||
USA | 13,677 | 13,541 | 14,752 | 14,635 | |||||||||||||||||
Downstream Refining | 4,376 | 4,032 | 5,075 | 4,637 | |||||||||||||||||
Market Optimization | 134 | 140 | 419 | 429 | |||||||||||||||||
Corporate & Other | 828 | 629 | 3,203 | 4,127 | |||||||||||||||||
Total | $ | 37,377 | $ | 35,424 | $ | 48,338 | $ | 47,247 |
On February 9, 2007, EnCana announced that it had entered into a 25 year lease agreement with a third party developer for The Bow office project. As at June 30, 2009, Corporate and Other Property, Plant and Equipment and Total Assets includes EnCana's accrual to date of $442 million ($252 million at December 31, 2008) related to this office project as an asset under construction.
On January 4, 2008, EnCana signed the contract for the design and construction of the Production Field Centre ("PFC") for the Deep Panuke project. As at June 30, 2009, Canada Property, Plant, and Equipment and Total Assets includes EnCana's accrual to date of $311 million ($199 million at December 31, 2008) related to this offshore facility as an asset under construction.
Corresponding liabilities for these projects are included in Other Liabilities in the Consolidated Balance Sheet. There is no effect on the Company's net earnings or cash flows related to the capitalization of The Bow office project or the Deep Panuke PFC.
5. Acquisitions and Divestitures
Acquisitions
On May 5, 2009, the Company acquired the common shares of Kerogen Resources Canada, ULC for net cash consideration of $24 million. The acquisition included $37 million of property, plant and equipment and the assumption of $6 million of current liabilities and $7 million of future income taxes. The operations are included in the Canadian Foothills Division.
Divestitures
Total year-to-date proceeds received on the sale of assets were $53 million (2008 - $151 million). The significant items are described below:
Canada
In 2009, the Company completed the divestiture of mature conventional oil and natural gas assets for proceeds of $44 million (2008 - $70 million) in Canadian Foothills and did not complete any divestitures in Canadian Plains (2008 - $31 million).
6. Interest, Net
Three Months Ended | Six Months Ended | ||||||||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||
Interest Expense - Long-Term Debt | $ | 123 | $ | 144 | $ | 241 | $ | 284 | |||||||||||||||||
Interest Expense - Other * | 50 | 56 | 89 | 110 | |||||||||||||||||||||
Interest Income * | (44 | ) | (53 | ) | (97 | ) | (113 | ) | |||||||||||||||||
$ | 129 | $ | 147 | $ | 233 | $ | 281 | ||||||||||||||||||
* Interest Expense - Other and Interest Income are primarily due to the Partnership Contribution Payable and Receivable, respectively. |
7. Foreign Exchange (Gain) Loss, Net | |||||||||||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||
Unrealized Foreign Exchange (Gain) Loss on: | |||||||||||||||||||||||||||
Translation of U.S. dollar debt issued from Canada * | $ | (439 | ) | $ | (52 | ) | $ | (289 | ) | $ | 165 | ||||||||||||||||
Translation of U.S. dollar partnership contribution receivable issued from Canada * | 247 | 44 | 160 | (99 | ) | ||||||||||||||||||||||
Other Foreign Exchange (Gain) Loss on: | |||||||||||||||||||||||||||
Monetary revaluations and settlements | 132 | (27 | ) | 127 | (6 | ) | |||||||||||||||||||||
$ | (60 | ) | $ | (35 | ) | $ | (2 | ) | $ | 60 | |||||||||||||||||
* Reflects the current year change in foreign exchange rates calculated on the period end balance. | |||||||||||||||||||||||||||
8. Income Taxes | |||||||||||||||||||||||||||
The provision for income taxes is as follows: | |||||||||||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||
Current | |||||||||||||||||||||||||||
Canada | $ | 268 | $ | 172 | $ | 440 | $ | 406 | |||||||||||||||||||
United States | 38 | 256 | 114 | 385 | |||||||||||||||||||||||
Other Countries | 7 | 12 | 6 | 13 | |||||||||||||||||||||||
Total Current Tax | 313 | 440 | 560 | 804 | |||||||||||||||||||||||
Future | (231 | ) | 152 | (194 | ) | 73 | |||||||||||||||||||||
$ | 82 | $ | 592 | $ | 366 | $ | 877 | ||||||||||||||||||||
9. Inventories | |||||||||||||||||||||||||||
As at | As at | ||||||||||||||||||||||||||
June 30, | December 31, | ||||||||||||||||||||||||||
2009 | 2008 | ||||||||||||||||||||||||||
Product | |||||||||||||||||||||||||||
Canada | $ | 57 | $ | 46 | |||||||||||||||||||||||
USA | 5 | 8 | |||||||||||||||||||||||||
Downstream Refining | 480 | 323 | |||||||||||||||||||||||||
Market Optimization | 154 | 127 | |||||||||||||||||||||||||
Parts and Supplies | 14 | 16 | |||||||||||||||||||||||||
$ | 710 | $ | 520 |
10. Long-Term Debt
As at | As at | ||||||||||||||||
June 30, | December 31, | ||||||||||||||||
2009 | 2008 | ||||||||||||||||
Canadian Dollar Denominated Debt | |||||||||||||||||
Revolving credit and term loan borrowings | $ | 914 | $ | 1,410 | |||||||||||||
Unsecured notes | 1,075 | 1,020 | |||||||||||||||
1,989 | 2,430 | ||||||||||||||||
U.S. Dollar Denominated Debt | |||||||||||||||||
Revolving credit and term loan borrowings | 125 | 247 | |||||||||||||||
Unsecured notes | 6,850 | 6,350 | |||||||||||||||
6,975 | 6,597 | ||||||||||||||||
Increase in Value of Debt Acquired | 49 | 49 | |||||||||||||||
Debt Discounts and Financing Costs | (75 | ) | (71 | ) | |||||||||||||
Current Portion of Long-Term Debt | (250 | ) | (250 | ) | |||||||||||||
$ | 8,688 | $ | 8,755 |
On May 4, 2009, EnCana completed a public offering in the United States of senior unsecured notes in the aggregate principal amount of US$500 million. The notes have a coupon rate of 6.5 percent and mature on May 15, 2019. The net proceeds of the offering were used to repay a portion of EnCana's existing bank and commercial paper indebtedness.
11. Asset Retirement Obligation
The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas assets and refining facilities:
As at | As at | ||||||||||||||||
June 30, | December 31, | ||||||||||||||||
2009 | 2008 | ||||||||||||||||
Asset Retirement Obligation, Beginning of Year | $ | 1,265 | $ | 1,458 | |||||||||||||
Liabilities Incurred | 10 | 54 | |||||||||||||||
Liabilities Settled | (31 | ) | (115 | ) | |||||||||||||
Liabilities Divested | - | (38 | ) | ||||||||||||||
Change in Estimated Future Cash Flows | (8 | ) | 54 | ||||||||||||||
Accretion Expense | 36 | 79 | |||||||||||||||
Foreign Currency Translation | 53 | (227 | ) | ||||||||||||||
Asset Retirement Obligation, End of Period | $ | 1,325 | $ | 1,265 |
12. Share Capital
June 30, 2009 | December 31, 2008 | ||||||||||||||||||||||
(millions) | Number | Amount | Number | Amount | |||||||||||||||||||
Common Shares Outstanding, Beginning of Year | 750.4 | $ | 4,557 | 750.2 | $ | 4,479 | |||||||||||||||||
Common Shares Issued under Option Plans | 0.2 | 2 | 3.0 | 80 | |||||||||||||||||||
Common Shares Issued from PSU Trust | 0.5 | 19 | - | - | |||||||||||||||||||
Stock-Based Compensation | - | 1 | - | 11 | |||||||||||||||||||
Common Shares Purchased | - | - | (2.8 | ) | (13 | ) | |||||||||||||||||
Common Shares Outstanding, End of Period | 751.1 | $ | 4,579 | 750.4 | $ | 4,557 |
Performance Share Units ("PSUs")
In April, 2009, the remaining 0.5 million Common Shares held in trust relating to EnCana's PSU plan were sold for total consideration of $25 million. Of the amount received, $19 million was credited to Share capital and $6 million to Paid in surplus, representing the excess consideration received over the original price of the Common Shares acquired by the trust. Effective May 15, 2009, EnCana's PSU plan was complete and the trust agreement was terminated.
Normal Course Issuer Bid
EnCana has received regulatory approval each year under Canadian securities laws to purchase Common Shares under seven consecutive Normal Course Issuer Bids ("Bids"). EnCana is entitled to purchase, for cancellation, up to approximately 75.0 million Common Shares under the renewed Bid which commenced on November 13, 2008 and terminates on November 12, 2009. To June 30, 2009, there have been no purchases under the current bid (2008 - 4.8 million Common Shares for approximately $326 million).
Stock Options
EnCana has stock-based compensation plans that allow employees to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were granted. Options granted under the plans are generally fully exercisable after three years and expire five years after the date granted. Options granted under predecessor and/or related company replacement plans expire up to 10 years from the date the options were granted.
The following tables summarize the information related to options to purchase Common Shares that do not have Tandem Share Appreciation Rights ("TSARs") attached to them at June 30, 2009. Information related to TSARs is included in Note 14.
Stock | Weighted | ||||||||||||||||||
Outstanding, Beginning of Year | 0.5 | 11.62 | |||||||||||||||||
Exercised | (0.2 | ) | 11.58 | ||||||||||||||||
Outstanding, End of Period | 0.3 | 11.79 | |||||||||||||||||
Exercisable, End of Period | 0.3 | 11.79 | |||||||||||||||||
Outstanding & Exercisable Options | |||||||||||||||||||
Range of Exercise Price (C$) |
Number of |
Weighted |
Weighted | ||||||||||||||||
11.50 to 14.50 | 0.3 | 0.6 | 11.79 |
13. Capital Structure
The Company's capital structure is comprised of Shareholders' Equity plus Long-Term Debt. The Company's objectives when managing its capital structure are to:
i) maintain financial flexibility to preserve EnCana's access to capital markets and its ability to meet its financial obligations;
ii) finance internally generated growth as well as potential acquisitions.
The Company monitors its capital structure and short-term financing requirements using non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization ("EBITDA"). These metrics are used to steward the Company's overall debt position as measures of the Company's overall financial strength.
EnCana targets a Debt to Capitalization ratio of less than 40 percent. At June 30, 2009, EnCana's Debt to Capitalization ratio was 27 percent (December 31, 2008 - 28 percent) calculated as follows:
As at | ||||||||||||||||||||||||
June 30, | December 31, | |||||||||||||||||||||||
2009 | 2008 | |||||||||||||||||||||||
Debt | $ | 8,938 | $ | 9,005 | ||||||||||||||||||||
Total Shareholders' Equity | 24,247 | 22,974 | ||||||||||||||||||||||
Total Capitalization | $ | 33,185 | $ | 31,979 | ||||||||||||||||||||
Debt to Capitalization ratio | 27 | % | 28 | % |
EnCana targets a Debt to Adjusted EBITDA of less than 2.0 times. At June 30, 2009, Debt to Adjusted EBITDA was 0.7x (December 31, 2008 - 0.7x) calculated on a trailing twelve-month basis as follows:
As at | |||||||||||||||||||||
June 30, | December 31, | ||||||||||||||||||||
2009 | 2008 | ||||||||||||||||||||
Debt | $ | 8,938 | $ | 9,005 | |||||||||||||||||
Net Earnings | $ | 5,831 | $ | 5,944 | |||||||||||||||||
Add (deduct): | |||||||||||||||||||||
Interest, net | 538 | 586 | |||||||||||||||||||
Income tax expense | 2,122 | 2,633 | |||||||||||||||||||
Depreciation, depletion and amortization | 4,054 | 4,223 | |||||||||||||||||||
Accretion of asset retirement obligation | 74 | 79 | |||||||||||||||||||
Foreign exchange (gain) loss, net | 361 | 423 | |||||||||||||||||||
(Gain) loss on divestitures | (121 | ) | (140 | ) | |||||||||||||||||
Adjusted EBITDA | $ | 12,859 | $ | 13,748 | |||||||||||||||||
Debt to Adjusted EBITDA | 0.7x | 0.7x |
EnCana has a long-standing practice of maintaining capital discipline, managing its capital structure and adjusting its capital structure according to market conditions to maintain flexibility while achieving the objectives stated above. To manage the capital structure, the Company may adjust capital spending, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new shares, issue new debt or repay existing debt.
The Company's capital management objectives, evaluation measures and definitions have remained unchanged over the periods presented. EnCana is subject to certain financial covenants in its credit facility agreements and is in compliance with all financial covenants.
14. Compensation Plans
The following tables outline certain information related to EnCana's compensation plans at June 30, 2009. Additional information is contained in Note 19 of the Company's annual audited Consolidated Financial Statements for the year ended December 31, 2008.
A) Pensions
The following table summarizes the net benefit plan expense:
Three Months Ended | Six Months Ended | |||||||||||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||
Current Service Cost | $ | 3 | $ | 4 | $ | 7 | $ | 8 | ||||||||||||||||||||
Interest Cost | 5 | 6 | 10 | 11 | ||||||||||||||||||||||||
Expected Return on Plan Assets | (3 | ) | (5 | ) | (7 | ) | (10 | ) | ||||||||||||||||||||
Amortization of Net Actuarial Losses | 2 | 1 | 4 | 2 | ||||||||||||||||||||||||
Amortization of Past Service Costs | - | - | 1 | 1 | ||||||||||||||||||||||||
Amortization of Transitional Obligation | 1 | - | 1 | (1 | ) | |||||||||||||||||||||||
Expense for Defined Contribution Plan | 11 | 10 | 22 | 20 | ||||||||||||||||||||||||
Net Benefit Plan Expense | $ | 19 | $ | 16 | $ | 38 | $ | 31 |
For the six months ended June 30, 2009, contributions of $3 million have been made to the defined benefit pension plans (2008 - $7 million).
B) Tandem Share Appreciation Rights ("TSARs")
The following table summarizes information related to the TSARs at June 30, 2009:
Outstanding | Weighted | ||||||||||||||
Canadian Dollar Denominated (C$) | |||||||||||||||
Outstanding, Beginning of Year | 19,411,939 | 53.97 | |||||||||||||
Granted | 3,937,960 | 55.33 | |||||||||||||
Exercised - SARs | (1,457,058 | ) | 42.20 | ||||||||||||
Exercised - Options | (45,264 | ) | 33.97 | ||||||||||||
Forfeited | (257,684 | ) | 59.12 | ||||||||||||
Outstanding, End of Period | 21,589,893 | 55.00 | |||||||||||||
Exercisable, End of Period | 12,544,910 | 50.64 |
For the period ended June 30, 2009, EnCana recorded compensation costs of $32 million related to the outstanding TSARs (2008 - $340 million).
C) Performance Tandem Share Appreciation Rights ("Performance TSARs")
The following table summarizes information related to the Performance TSARs at June 30, 2009:
Outstanding | Weighted | ||||||||||||||
Canadian Dollar Denominated (C$) | |||||||||||||||
Outstanding, Beginning of Year | 12,979,725 | 63.13 | |||||||||||||
Granted | 7,751,720 | 55.31 | |||||||||||||
Exercised - SARs | (99,163 | ) | 56.09 | ||||||||||||
Exercised - Options | (765 | ) | 56.09 | ||||||||||||
Forfeited | (1,768,602 | ) | 62.87 | ||||||||||||
Outstanding, End of Period | 18,862,915 | 59.98 | |||||||||||||
Exercisable, End of Period | 3,839,884 | 60.46 |
For the period ended June 30, 2009, EnCana recorded compensation costs of $14 million related to the outstanding Performance TSARs (2008 - $126 million).
D) Share Appreciation Rights ("SARs")
The following table summarizes information related to the SARs at June 30, 2009:
Outstanding | Weighted | |||||||||||||||
Canadian Dollar Denominated (C$) | ||||||||||||||||
Outstanding, Beginning of Year | 1,285,065 | 72.13 | ||||||||||||||
Granted | 1,112,020 | 55.41 | ||||||||||||||
Forfeited | (37,205 | ) | 68.14 | |||||||||||||
Outstanding, End of Period | 2,359,880 | 64.31 | ||||||||||||||
Exercisable, End of Period | 281,758 | 72.33 |
For the period ended June 30, 2009, EnCana has recorded compensation costs of $1 million related to the outstanding SARs (2008 - $5 million).
E) Performance Share Appreciation Rights ("Performance SARs")
The following table summarizes information related to the Performance SARs at June 30, 2009:
Outstanding | Weighted | |||||||||||||||
Canadian Dollar Denominated (C$) | ||||||||||||||||
Outstanding, Beginning of Year | 1,620,930 | 69.40 | ||||||||||||||
Granted | 2,140,440 | 55.31 | ||||||||||||||
Forfeited | (221,323 | ) | 68.62 | |||||||||||||
Outstanding, End of Period | 3,540,047 | 60.93 | ||||||||||||||
Exercisable, End of Period | 298,663 | 69.40 |
For the period ended June 30, 2009, EnCana has recorded compensation costs of $1 million related to the outstanding Performance SARs (2008 - $4 million).
F) Deferred Share Units ("DSUs")
The following table summarizes information related to the DSUs at June 30, 2009:
Outstanding | |||||||||||||
Canadian Dollar Denominated | |||||||||||||
Outstanding, Beginning of Year | 656,841 | ||||||||||||
Granted | 72,808 | ||||||||||||
Converted from HPR awards | 46,884 | ||||||||||||
Units, in Lieu of Dividends | 13,434 | ||||||||||||
Redeemed | (45,352 | ) | |||||||||||
Outstanding, End of Period | 744,615 |
For the period ended June 30, 2009, EnCana has recorded compensation costs of $5 million related to the outstanding DSUs (2008 - $23 million).
In 2009, employees had the option to convert either 25 or 50 percent of their annual High Performance Results ("HPR") award into DSUs. The number of DSUs is based on the value of the award divided by the closing value of EnCana's share price at the end of the performance period of the HPR award. DSUs vest immediately, can be redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of termination.
15. Per Share Amounts
The following table summarizes the Common Shares used in calculating Net Earnings per Common Share:
Three Months Ended | Six Months Ended | ||||||||||||||||||||||
March 31, | June 30, | June 30, | |||||||||||||||||||||
(millions) | 2009 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||
Weighted Average Common Shares Outstanding - Basic | 750.5 | 751.0 | 750.2 | 750.8 | 749.8 | ||||||||||||||||||
Effect of Dilutive Securities | 0.9 | 0.4 | 1.1 | 0.6 | 2.5 | ||||||||||||||||||
Weighted Average Common Shares Outstanding - Diluted | 751.4 | 751.4 | 751.3 | 751.4 | 752.3 |
16. Financial Instruments and Risk Management
EnCana's financial assets and liabilities are comprised of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, the partnership contribution receivable and payable, risk management assets and liabilities, and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments. Fair values of financial assets and liabilities, summarized information related to risk management positions, and discussion of risks associated with financial assets and liabilities are presented as follows:
A) Fair Value of Financial Assets and Liabilities
The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amount due to the short-term maturity of those instruments.
The fair values of the partnership contribution receivable and partnership contribution payable approximate their carrying amount due to the specific nature of these instruments in relation to the creation of the integrated oil joint venture. Further information about these notes is disclosed in Note 11 to the Company's annual audited Consolidated Financial Statements for the year ended December 31, 2008.
Risk management assets and liabilities are recorded at their estimated fair value based on the mark-to-market method of accounting, using quoted market prices or, in their absence, third-party market indications and forecasts.
Long-term debt is carried at amortized cost using the effective interest method of amortization. The estimated fair values of long-term borrowings have been determined based on market information where available, or by discounting future payments of interest and principal at estimated interest rates expected to be available to the Company at period end.
The fair value of financial assets and liabilities were as follows:
As at June 30, 2009 | As at December 31, 2008 | |||||||||||||||||||||||
Carrying | Fair |
Carrying |
Fair | |||||||||||||||||||||
Financial Assets | ||||||||||||||||||||||||
Held-for-Trading: | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 330 | $ | 330 | $ | 383 | $ | 383 | ||||||||||||||||
Risk management assets * | 1,971 | 1,971 | 3,052 | 3,052 | ||||||||||||||||||||
Loans and Receivables: | ||||||||||||||||||||||||
Accounts receivable and accrued revenues | 1,472 | 1,472 | 1,568 | 1,568 | ||||||||||||||||||||
Partnership contribution receivable * | 2,993 | 2,993 | 3,147 | 3,147 | ||||||||||||||||||||
Financial Liabilities | ||||||||||||||||||||||||
Held-for-Trading: | ||||||||||||||||||||||||
Risk management liabilities * | $ | 40 | $ | 40 | $ | 50 | $ | 50 | ||||||||||||||||
Other Financial Liabilities: | ||||||||||||||||||||||||
Accounts payable and accrued liabilities | 2,401 | 2,401 | 2,871 | 2,871 | ||||||||||||||||||||
Long-term debt * | 8,938 | 9,349 | 9,005 | 8,242 | ||||||||||||||||||||
Partnership contribution payable * | 3,012 | 3,012 | 3,163 | 3,163 | ||||||||||||||||||||
* Including current portion. |
B) Risk Management Assets and Liabilities
Net Risk Management Position | As at | As at | ||||||||||||||||||||||||||||||
June 30, | December 31, | |||||||||||||||||||||||||||||||
2009 | 2008 | |||||||||||||||||||||||||||||||
Risk Management | ||||||||||||||||||||||||||||||||
Current asset | $ | 1,927 | $ | 2,818 | ||||||||||||||||||||||||||||
Long-term asset | 44 | 234 | ||||||||||||||||||||||||||||||
1,971 | 3,052 | |||||||||||||||||||||||||||||||
Risk Management | ||||||||||||||||||||||||||||||||
Current liability | 14 | 43 | ||||||||||||||||||||||||||||||
Long-term liability | 26 | 7 | ||||||||||||||||||||||||||||||
40 | 50 | |||||||||||||||||||||||||||||||
Net Risk Management Asset (Liability) | $ | 1,931 | $ | 3,002 | ||||||||||||||||||||||||||||
Summary of Unrealized Risk Management Positions | ||||||||||||||||||||||||||||||||
As at June 30, 2009 | As at December 31, 2008 | |||||||||||||||||||||||||||||||
Risk Management | Risk Management | |||||||||||||||||||||||||||||||
Asset | Liability | Net | Asset | Liability | Net | |||||||||||||||||||||||||||
Commodity Prices | ||||||||||||||||||||||||||||||||
Natural gas | $ | 1,952 | $ | 27 | $ | 1,925 | $ | 2,941 | $ | 10 | $ | 2,931 | ||||||||||||||||||||
Crude oil | 13 | 13 | - | 92 | 40 | 52 | ||||||||||||||||||||||||||
Power | 6 | - | 6 | 19 | - | 19 | ||||||||||||||||||||||||||
Total Fair Value | $ | 1,971 | $ | 40 | $ | 1,931 | $ | 3,052 | $ | 50 | $ | 3,002 | ||||||||||||||||||||
Net Fair Value Methodologies Used to Calculate Unrealized Risk Management Positions | ||||||||||||||||||||||||||||||||
As at | As at | |||||||||||||||||||||||||||||||
June 30, | December 31, | |||||||||||||||||||||||||||||||
2009 | 2008 | |||||||||||||||||||||||||||||||
Prices actively quoted | $ | 1,501 | $ | 2,055 | ||||||||||||||||||||||||||||
Prices sourced from observable data or market corroboration | 430 | 947 | ||||||||||||||||||||||||||||||
Total Fair Value | $ | 1,931 | $ | 3,002 |
Prices actively quoted refers to the fair value of contracts valued using quoted prices in an active market. Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.
Net Fair Value of Commodity Price Positions at June 30, 2009 | ||||||||||||||||||||||||||
Notional Volumes | Term | Average Price | Fair Value | |||||||||||||||||||||||
Natural Gas Contracts | ||||||||||||||||||||||||||
Fixed Price Contracts | ||||||||||||||||||||||||||
NYMEX Fixed Price | 1,897 | MMcf/d | 2009 | 8.35 | US$/Mcf | $ | 1,388 | |||||||||||||||||||
NYMEX Fixed Price | 1,415 | MMcf/d | 2010 | 6.13 | US$/Mcf | 112 | ||||||||||||||||||||
Purchased Options | ||||||||||||||||||||||||||
NYMEX Call | (120 | ) | MMcf/d | 2009 | 11.67 | US$/Mcf | (10 | ) | ||||||||||||||||||
NYMEX Put | 414 | MMcf/d | 2009 | 9.10 | US$/Mcf | 355 | ||||||||||||||||||||
Basis Contracts | ||||||||||||||||||||||||||
Canada | 80 | MMcf/d | 2009 | 6 | ||||||||||||||||||||||
United States | 373 | MMcf/d | 2009 | (3 | ) | |||||||||||||||||||||
Canada and United States * | 2010-2013 | 31 | ||||||||||||||||||||||||
1,879 | ||||||||||||||||||||||||||
Other Financial Positions ** | 1 | |||||||||||||||||||||||||
Total Unrealized Gain on Financial Contracts | 1,880 | |||||||||||||||||||||||||
Premiums Paid on Unexpired Options | 45 | |||||||||||||||||||||||||
Natural Gas Fair Value Position | $ | 1,925 | ||||||||||||||||||||||||
* EnCana has entered into swaps to protect against widening natural gas price differentials between production areas, including Canada, the U.S. Rockies and Texas, and various sales points. These basis swaps are priced using both fixed prices and basis prices determined as a percentage of NYMEX. | ||||||||||||||||||||||||||
** Other financial positions are part of the ongoing operations of the Company's proprietary production management. | ||||||||||||||||||||||||||
Notional Volumes | Term | Average Price | Fair Value | |||||||||||||||||||||||
Crude Oil Contracts | ||||||||||||||||||||||||||
Fixed Price Contracts | ||||||||||||||||||||||||||
WTI NYMEX Fixed Price | 19,000 | bbls/d | 2010 | 76.46 | US$/bbl | $ | 8 | |||||||||||||||||||
Other Financial Positions * | (8 | ) | ||||||||||||||||||||||||
Crude Oil Fair Value Position | $ | - | ||||||||||||||||||||||||
* Other financial positions are part of the ongoing operations of the Company's proprietary production and condensate management and its share of downstream crude supply positions. | ||||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||||
Power Purchase Contracts | ||||||||||||||||||||||||||
Power Fair Value Position | $ | 6 |
Net Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions | |||||||||||||||||||||||||||
Realized Gain (Loss) | |||||||||||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 1,345 | $ | (586 | ) | $ | 2,414 | $ | (566 | ) | |||||||||||||||||
Operating Expenses and Other | (5 | ) | (2 | ) | (29 | ) | - | ||||||||||||||||||||
Gain (Loss) on Risk Management | $ | 1,340 | $ | (588 | ) | $ | 2,385 | $ | (566 | ) | |||||||||||||||||
Unrealized Gain (Loss) | |||||||||||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||
Revenues, Net of Royalties | $ | (1,114 | ) | $ | (328 | ) | $ | (981 | ) | $ | (1,424 | ) | |||||||||||||||
Operating Expenses and Other | (4 | ) | 10 | (26 | ) | 13 | |||||||||||||||||||||
Gain (Loss) on Risk Management | $ | (1,118 | ) | $ | (318 | ) | $ | (1,007 | ) | $ | (1,411 | ) | |||||||||||||||
Reconciliation of Unrealized Risk Management Positions from January 1 to June 30, 2009 | |||||||||||||||||||||||||||
2009 | 2008 | ||||||||||||||||||||||||||
Fair Value | Total |
Total | |||||||||||||||||||||||||
Fair Value of Contracts, Beginning of Year | $ | 2,892 | |||||||||||||||||||||||||
Change in Fair Value of Contracts in Place at Beginning of Year
and Contracts | 1,378 | $ | 1,378 | $ | (1,977 | ) | |||||||||||||||||||||
Foreign Exchange Gain (Loss) on Canadian Dollar Contracts | 1 | - | - | ||||||||||||||||||||||||
Fair Value of Contracts Realized During the Period | (2,385 | ) | (2,385 | ) | 566 | ||||||||||||||||||||||
Fair Value of Contracts Outstanding | $ | 1,886 | $ | (1,007 | ) | $ | (1,411 | ) | |||||||||||||||||||
Premiums Paid on Unexpired Options | 45 | ||||||||||||||||||||||||||
Fair Value of Contracts and Premiums Paid, End of Period | $ | 1,931 |
Commodity Price Sensitivities
The following table summarizes the sensitivity of the fair value of the Company's risk management positions to fluctuations in commodity prices, with all other variables held constant. The Company has used a 10% variability to assess the potential impact of commodity price changes. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting net earnings as at June 30, 2009 as follows:
10% Price |
10% Price | ||||||||||||||||||
Natural gas price | $ | (469 | ) | $ | 469 | ||||||||||||||
Crude oil price | (57 | ) | 57 | ||||||||||||||||
Power price | 10 | (10 | ) |
C) Risks Associated with Financial Assets and Liabilities
The Company is exposed to financial risks arising from its financial assets and liabilities. Financial risks include market risks (such as commodity prices, foreign exchange and interest rates), credit risk and liquidity risk. The fair value or future cash flows of financial assets or liabilities may fluctuate due to movement in market prices and the exposure to credit and liquidity risks.
Commodity Price Risk
Commodity price risk arises from the effect that fluctuations of future commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company's policy is to not use derivative financial instruments for speculative purposes.
Natural Gas - To partially mitigate the natural gas commodity price risk, the Company has entered into option contracts and swaps, which fix the NYMEX prices. To help protect against widening natural gas price differentials in various production areas, EnCana has entered into swaps to manage the price differentials between these production areas and various sales points.
Crude Oil - The Company has partially mitigated its commodity price risk on crude oil and condensate supply with swaps which fix WTI NYMEX prices.
Power - The Company has in place two Canadian dollar denominated derivative contracts, which commenced January 1, 2007 for a period of 11 years, to manage its electricity consumption costs.
Credit Risk
Credit risk arises from the potential the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit policies governing the Company's credit portfolio and with credit practices that limit transactions according to counterparties' credit quality. Any foreign currency agreements entered into are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings. A substantial portion of the Company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at June 30, 2009, approximately 94 percent of EnCana's accounts receivable and financial derivative credit exposures are with investment grade counterparties.
At June 30, 2009, EnCana had three counterparties whose net settlement position individually account for more than 10 percent of the fair value of the outstanding in-the-money net financial instrument contracts by counterparty. The maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets and the partnership contribution receivable is the total carrying value.
Liquidity Risk
Liquidity risk is the risk the Company will encounter difficulties in meeting a demand to fund its financial liabilities as they come due. The Company manages its liquidity risk through cash and debt management. As disclosed in Note 13, EnCana targets a Debt to Capitalization ratio between 30 and 40 percent and a Debt to Adjusted EBITDA of 1.0 to 2.0 times to steward the Company's overall debt position.
In managing liquidity risk, the Company has access to a wide range of funding at competitive rates through commercial paper, capital markets and banks. As at June 30, 2009, EnCana had available unused committed bank credit facilities in the amount of $3.4 billion and unused capacity under shelf prospectuses, the availability of which is dependent on market conditions, for $5.2 billion. The Company believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements.
EnCana maintains investment grade credit ratings on its senior unsecured debt. Standard & Poor’s Ratings Services has assigned a rating of "A-" with a “Negative” outlook, Moody’s Investors Service has assigned a rating of "Baa2" with a “Stable” outlook and DBRS Limited has assigned a rating of "A (low)" and placed the rating “Under Review with Developing Implications”. DBRS Limited placed the rating "Under Review" following the May 11, 2008 announcement of the proposed corporate reorganization.
The timing of cash outflows relating to financial liabilities are outlined in the table below: | ||||||||||||||||||||||||||||
Less Than 1 Year | 1 - 3 Years | 4 - 5 Years | Thereafter | Total | ||||||||||||||||||||||||
Accounts Payable and Accrued Liabilities | $ | 2,401 | $ | - | $ | - | $ | - | $ | 2,401 | ||||||||||||||||||
Risk Management Liabilities | 14 | 26 | - | - | 40 | |||||||||||||||||||||||
Long-Term Debt * | 736 | 2,046 | 3,341 | 9,924 | 16,047 | |||||||||||||||||||||||
Partnership Contribution Payable * | 489 | 978 | 978 | 1,344 | 3,789 | |||||||||||||||||||||||
* Principal and interest, including current portion. |
Included in EnCana's total long-term debt obligations of $16,047 million at June 30, 2009 are $1,039 million in principal obligations related to Commercial Paper. These amounts are fully supported and Management expects that they will continue to be supported by revolving credit and term loan facilities that have no repayment requirements within the next year. The revolving credit and term loan facilities are fully revolving for a period of up to five years. Based on the current maturity dates of the credit facilities, these amounts are included in cash outflows for the period disclosed as 4 - 5 Years. Further information on Long-term Debt is contained in Note 10.
Foreign Exchange Risk
Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. As EnCana operates primarily in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on the Company's reported results. EnCana's functional currency is Canadian dollars, however, the Company reports its results in U.S. dollars as most of its revenue is closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies. As the effects of foreign exchange fluctuations are embedded in the Company's results, the total effect of foreign exchange fluctuations are not separately identifiable.
To mitigate the exposure to the fluctuating U.S./Canadian exchange rate, EnCana maintains a mix of both U.S. dollar and Canadian dollar debt.
As disclosed in Note 7, EnCana's foreign exchange (gain) loss is primarily comprised of unrealized foreign exchange gains and losses on the translation of U.S. dollar debt issued from Canada and the translation of the U.S. dollar partnership contribution receivable issued from Canada. At June 30, 2009, EnCana had $5,850 million in U.S. dollar debt issued from Canada ($5,350 million at December 31, 2008) and $2,993 million related to the U.S. dollar partnership contribution receivable ($3,147 million at December 31, 2008). A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $25 million change in foreign exchange (gain) loss at June 30, 2009 (2008 - $21 million).
Interest Rate Risk
Interest rate risk arises from changes in market interest rates that may affect the fair value or future cash flows from the Company’s financial assets or liabilities. The Company partially mitigates its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt.
At June 30, 2009, the increase or decrease in net earnings for each one percent change in interest rates on floating rate debt amounts to $7 million (2008 - $16 million).
17. Contingencies
Legal Proceedings
The Company is involved in various legal claims associated with the normal course of operations. The Company believes it has made adequate provision for such legal claims.
Discontinued Merchant Energy Operations
During the period between 2003 and 2005, EnCana and its indirect wholly owned U.S. marketing subsidiary, WD Energy Services Inc. (“WD”), along with other energy companies, were named as defendants in several lawsuits, some of which were class action lawsuits, relating to sales of natural gas from 1999 to 2002. The lawsuits allege that the defendants engaged in a conspiracy with unnamed competitors in the natural gas markets in California in violation of U.S. and California anti-trust and unfair competition laws. All but one of these lawsuits has been settled prior to 2009, without admitting any liability in the lawsuits.
The remaining lawsuit was commenced by E. & J. Gallo Winery (“Gallo”). The Gallo lawsuit claims damages in excess of $30 million. California law allows for the possibility that the amount of damages assessed could be tripled.
The Company and WD intend to vigorously defend against this outstanding claim; however, the Company cannot predict the outcome of these proceedings or any future proceedings against the Company, whether these proceedings would lead to monetary damages which could have a material adverse effect on the Company’s financial position, or whether there will be other proceedings arising out of these allegations.
18. Reclassification
Certain information provided for prior periods has been reclassified to conform to the presentation adopted in 2009.
Contacts:
Investor
contact:
EnCana Corporate Communications
Paul
Gagne
Vice-President, Investor Relations
(403) 645-4737
Ryder
McRitchie
Manager, Investor Relations
(403) 645-2007
Susan
Grey
Manager, Investor Relations
(403) 645-4751
Media
contact:
Alan Boras
Manager, Media Relations
(403)
645-4747