Second quarter 2010 results July 29, 2010 Conference call notes

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1 Second quarter 2010 results July 29, 2010 Conference call notes Susan Grey Director, Investor Relations Thank you operator and welcome to our discussion of Cenovus s results for the second quarter of I would like to refer you to the advisory on forward looking information, oil and gas information and non- GAAP measures in today s news release. In particular, we draw your attention to the risk factors and assumptions outlined in the advisory and discussed further in our annual information form and our annual and quarterly reports. Our second quarter results have been presented on a before royalties basis and in Canadian dollars. Our discussion today will be provided on the same basis unless otherwise noted. Brian Ferguson, President and Chief Executive Officer will begin with an overview of our results and then turn the call over to Ivor Ruste, Executive Vice-President and Chief Financial Officer who will discuss our financial performance. Following some closing comments from Brian, our Executive team will be available for questions. Please go ahead Brian. Brian Ferguson President & Chief Executive Officer Thanks Susan. Good morning everyone. I am pleased to be here with you today at the mid-point of 2010 to talk not only about Cenovus s performance in the quarter but also some significant achievements so far this year. We have: Quantified the significant bitumen resource initially-in-place on Cenovus lands; Unveiled our 10 year plan to grow net oil sands production more than five-fold to 300,000 barrels per day in 2019; Indicated our intent to implement a dividend growth strategy; and Set out the milestones that will allow you to track our progress in our goal of doubling net asset value over the next five year period. All of which will help to increase total shareholder return. We have had a busy start to 2010 and I am very happy with the progress that we have made. We have also maintained our solid operating performance and have established a very strong financial position that will allow us to execute our 10 year plan. This quarter we have delivered strong results and I believe we are on track to meet our overall guidance estimates for production and cash flow. Our operating performance is exceeding our expectations with production ahead of guidance and the company s operating and capital expenditures below what was anticipated at this point in the year. 1

2 Our strong performance is somewhat muted by the fact that our reported cash flow is down about $400 million in the second quarter when compared to the prior year. The drop is essentially due to two items. About half is due to a 38 percent lower realized natural gas price. The other half is due to volatility in crude oil prices and its impact on our downstream operating cash flow as a result of the first-in first-out inventory valuation methodology required by Canadian GAAP. The things we can control such as production, operating and capital costs are doing very well. Ivor Ruste will elaborate on these. Second quarter production from Foster Creek and Christina Lake increased 42 percent compared with the same period in 2009 to about 59 thousand barrels per day net to Cenovus. The continued success of these two SAGD projects reinforces our strong track record of project execution and production growth. These projects, along with our emerging oil sands opportunities will continue to drive growth at Cenovus. At both Christina Lake and Foster Creek we have a history of efficient operations and low cost expansions. At our Investor Day last month we announced increased total production capacity estimates for each of these projects. We now expect Foster Creek will have an ultimate gross production capacity of 235,000 barrels per day and Christina Lake of 258,000 barrels per day. Our share represents more than 245,000 barrels per day net to Cenovus. We also announced plans to accelerate the timing of the next expansion phase at each of Foster Creek, which would be phase F, and Christina Lake, which would be phase E, by as much as 12 months. Applications for these next phases were submitted to the regulators in 2009 and we anticipate receiving approval on Foster Creek phases F, G and H later this year and on Christina Lake phases E, F and G in At Christina Lake, phase C is approximately 70 percent complete. We are on budget and slightly ahead of schedule, but continue to target first production from this phase in the second half of We have begun construction on phase D with site grading, piling and concrete work in progress. Detailed engineering has also begun and is expected to be complete by the end of the third quarter. We are also moving forward with plans to realize value from some of our emerging plays. We are continuing to assess our undeveloped oil sands assets with an annual stratigraphic well drilling program of 400 to 500 wells in each of the next five years. As we mentioned at our Investor Day, more than half of our lands currently have no delineation wells drilled on them. The assessment wells we are planning will provide reservoir data to support the next phases of development at current operations and to contribute to the regulatory approval process for emerging projects. So far in 2010, we have drilled approximately 200 gross stratigraphic wells with an additional 40 wells planned for later this year. A regulatory application for our 50 percent owned Narrows Lake property was submitted to the regulator in late June. The application allows for a combination of SAGD and a solvent aided process or SAP to develop gross production capacity of 130,000 barrels per day. The successful implementation of SAP has the potential to increase recovery factors, reduce steam to oil ratio, decrease well densities, lower emissions intensity, and drive higher overall project returns. Pending receipt of approvals, first production from Narrows Lake is expected in We also recently achieved a significant milestone at our 100 percent owned Grand Rapids project in the Greater Pelican Region. Following a 3 month review the ERCB has granted approval for a single well pair SAGD pilot. The test is expected to begin by the end of this year, pending approval from Alberta Environment and is a critical step in the progress of this play. We expect to be in a position to file an 2

3 application for a commercial SAGD project in Total production capacity is expected to be 180,000 barrels per day and first production from this formation is targeted for On the refining front, the CORE project at Wood River continues to move forward and is approximately 82 percent complete with start up expected mid next year. Once the project is complete, we anticipate an increase of about $200 million (US) in annual operating cash flow net to Cenovus from the refinery based on current market price projections. Our established oil and natural gas properties in Alberta and Saskatchewan continued to demonstrate their strong cash generating abilities despite lower commodity prices and weather related delays. During the quarter these oil and gas properties, which we manage as financial assets, delivered operating cash flow of about $400 million in excess of capital expenditures. With the continued support of our solid and consistent hedging program, we are forecasting that these assets will provide operating cash flow in the $2.0 to $2.4 billion range this year while requiring a capital investment of approximately $725 to $925 million. Our natural gas financial assets are in-line with guidance for operating cash flow. Production from these assets is slightly ahead of guidance for the full year, but we were slightly lower than expected in the second quarter due to weather related drilling and completion delays. Natural declines for our gas properties continue as expected and we anticipate full year production to be in line with guidance. In terms of natural gas capital we expect to be at or below the low end of our guidance as we have taken advantage of opportunities to shift capital spending to oil given the strong oil netbacks. Overall for the company, capital investment for the quarter was $430 million which is down about 12 percent year over year largely due to decreased spending in several areas. In southern Alberta and southwestern Saskatchewan wet weather and a long spring break up limited activity and spending, but we are expecting to catch up through the third quarter. In our integrated oil operations, quarterly spending was down compared with 2009 on our CORE project and at Foster Creek with the completion of the upstream expansion phases in early These decreases were partially offset by increased spending at Christina Lake for pad drilling related to the phase C expansion. We expect total company capital spending for the full year to be within our guidance range of $2.1 to $2.5 billion dollars. With respect to our divestiture program we have received total proceeds of $144 million so far in We also recently agreed to sell certain natural gas properties in southeastern Alberta and southwestern Saskatchewan for proceeds of $165 million. These properties currently produce about 37 million cubic feet per day. The transaction is subject to normal closing adjustments and conditions and is expected to close in the third quarter of this year. On the acquisitions front we also took advantage of some small tuck-in acquisition opportunities in the quarter at our Narrows Lake and Wainwright oil properties. Overall, we had a strong second quarter. We are on track to meet our full year expectations and I am pleased with our performance and our achievements so far in Looking forward to the third quarter, we expect continued strong oil sands production. In our established oil and gas properties our focus will be on catching up on drilling activity that was impacted by wet weather during the second quarter. With our downstream operations we anticipate higher utilization due to fewer planned turnarounds and stronger margins as summer driving season has arrived. I will now turn the call over to Ivor to discuss our second quarter financial performance. 3

4 Ivor Ruste Executive Vice-President & Chief Financial Officer Thanks Brian and good morning everyone. Brian mentioned that we recently unveiled our 10-year development plan and I m pleased to confirm that Cenovus has the financial strength and financial capacity to support that long term plan. At the end of the second quarter our debt metrics were within or slightly below our managed ranges and the capital structure we ve put in place provides significant unused credit capacity and financial flexibility while also supporting our strong credit ratings. Overall, our financial position remains strong. We also demonstrated solid operating performance in the second quarter. Our year-to-date cash flow remains on track with guidance expectations for the year. In the quarter, Cenovus reported cash flow per share of $0.71 which was 44 percent lower than the cash flow for the same period of The most significant factor in the decrease related to lower realized natural gas prices primarily due to weaker contract prices on natural gas hedges in 2010 as compared to The downstream specific factors which I am about to discuss also contributed to the decreased cash flow. Improved oil prices and increased oil production provided some offset. In the second quarter our downstream refining operations reported an operating cash flow deficiency of $24 million, $202 million less than the same period in Nearly all of this decrease, about $180 million, was due to the first-in first-out (FIFO) inventory valuation method and the fact that WTI crude prices were approximately $8.00 per barrel lower at the end of the second quarter when compared to the end of the first quarter. As a result, higher cost inventory reported in the first quarter was processed and sold during the second quarter contributing to lower operating cash flows. The specific negative impact of the FIFO adjustment on the second quarter of 2010 was nearly $60 million. In the second quarter of 2010 crude utilization was lower, at approximately 84 percent, as a result of scheduled turnarounds and refinery optimization. This also negatively affected downstream operating cash flow. Clearly downstream operating cash flow has come up short of expectations. Typically, refining margins are stronger in the third quarter and we expect to see crude utilization improve for the remainder of the year. We currently anticipate crude utilization to be approximately 90 to 95 percent for the next two quarters. If operating cash flow doesn t improve in the third quarter we will revisit our guidance expectations and make adjustments as necessary. Cenovus s operating earnings for the second quarter of 2010 were $0.19 per share - $0.49 per share lower than the same period in As with our quarterly cash flow, operating earnings were negatively impacted by lower realized natural gas pricing, higher refining purchased product costs and lower refinery utilization which were somewhat offset by better upstream oil results. Our net earnings of $0.23 per share for the quarter were slightly better than the second quarter of 2009, reflecting the strong upstream operating results discussed earlier as well as the impact of the nonoperating items, including foreign exchange gains/losses and mark-to-market accounting of our hedge positions. 4

5 While we continued to benefit from our hedging activity and our $6.00 natural gas hedges, the positive 2010 impact was not as large as we experienced in 2009 when we had $9.00 gas hedges. Realized gains from hedging in the quarter were $64 million after tax compared to $250 million in At the end of the second quarter we had approximately 68 percent of our expected 2010 natural gas volumes, net of internal use, hedged at about $6.12 (US) per thousand cubic feet. For 2011, we have added to our hedge position and now have about 351 million cubic feet per day of natural gas hedged at $5.82 (US) per thousand cubic feet. When you think of our natural gas production don t forget that we are a large and growing consumer of natural gas through our SAGD and refining operations. This quarter we also increased our 2010 and 2011 WTI oil hedge positions. Approximately 9,500 barrels per day of oil were added for the last six months of 2010 and 11,000 barrels per day were added for In total for oil, we have more than 34,000 barrels per day of oil hedges in place for the rest of 2010 priced at approximately $80.00 (US) per barrel. Our 2011 hedge position of about 11,000 barrels per day is hedged at $89.00 (US) per barrel. We continue to use our hedging program as part of our financial strategy, as a tool to create increased certainty for our cash flow and capital program. Last quarter we mentioned that Foster Creek had become Alberta s largest producing SAGD project to reach payout for royalty purposes an indication of strong project economics. As a result of hitting this milestone, our average royalty rate at Foster Creek increased to approximately 19 percent or about $45 million this quarter. This compares to 1.5 percent or $2 million in the same quarter of 2009 and nearly 10 percent or $25 million in the first quarter of 2010 which reflected the higher rate for only a portion of the quarter. In terms of operating costs for the quarter, we saw improvement at Foster Creek and Christina Lake, which together averaged $11.17 per barrel, down 8 percent compared to the second quarter last year due to higher production volumes and lower workovers, repairs and maintenance. This is lower than the mid-point of our full year guidance of $13.75 per barrel. Our non-fuel operating costs for the quarter were $8.98 per barrel which is about 5 percent below the lower end of our full year guidance. We will consider making adjustments to these forecasts in the third quarter once we have additional information on expectations for full year production and costs. Operating costs for other oil and liquids remained in line with guidance, but increased 30 percent compared to the second quarter of last year to $12.80 per barrel, due primarily to increased polymer usage, higher maintenance and workover activity as well as higher property taxes. In 2009 as a response to low commodity prices we deferred some maintenance and workover projects. As we resumed a more typical pace of activity in 2010 we saw costs increase accordingly. Quarterly operating costs for natural gas continue to hold steady, trending slightly better than guidance at $0.94 per thousand cubic feet. General and administrative expenses were $59 million or about $2.56 per barrel of oil equivalent, which is at the lower end of the range of our full year guidance of $2.50 to $3.00 per BOE. Costs were higher compared to the same quarter last year due to higher staffing costs as we began to implement our 10 year strategic plan and continued our transition to a stand-alone company. 5

6 We have had a good start to the year and look to stay on track and deliver within our 2010 forecasts. I will now turn the call back to Brian. Brian Ferguson President & Chief Executive Officer Thank you Ivor. Our performance and activity in the first six months of 2010 has positioned us well for the full year. We had solid operating results and strong financial results and we have established a 10 year plan to bring forward the value that exists within our resource base. We have established a set of objectives that will guide us in developing our huge resource and turning it into production. With the submission of our application at Narrows Lake and the ERCB approval of our Grand Rapids pilot we are already showing progress in achieving some of the milestones that will help measure our success. Over the next decade we expect to grow our oil sands production more than five-fold to about 300,000 barrels per day, based on our current long term development scenario. However, setting a growth rate was not and is not our goal. We are focused on realizing value from the significant resource on our lands while maintaining our industry leading cost structures and preserving our balance sheet. We are focused on developing responsibly and are continuously looking for new ways to improve the way we operate. Our challenge is to bring forward the tremendous value opportunity on our lands and crystallize that for our shareholders. Our overarching goal is to build total shareholder return and increase net asset value. We have the financial strength to be self-funding and the capacity to provide a strong dividend to our shareholders, and one that we plan to increase over time. Earlier this year, our Board approved a Dividend Reinvestment Plan which was made available to our shareholders for our second quarter dividend, allowing easy and cost effective reinvestment in the company. For the third quarter our Board of Directors has declared a dividend of $0.20 per share, representing a yield of almost 3 percent. Today s results demonstrate the strength of our assets and build on our track record of strong operational performance. We are on track with our overall guidance for the year, but some individual items are trending at the high or low end the ranges that we had provided earlier. For example, right now gas prices look to be lower than expected while Foster Creek and Christina Lake volumes are stronger than we anticipated. We know that there will be several puts and takes in the upstream and downstream businesses over the next three months and we plan to revisit our estimates at the end of the third quarter when we have a better indication of the full year outlook. Through the busy first half of 2010 our teams have maintained their focus on delivering on our targets and applying continuous innovation. This is an essential part of our culture and will be key to executing the development plan we have put in place and in achieving our goal of doubling net asset value. The Cenovus team is now ready to take your questions. POST Q&A SESSION Brian Ferguson President & Chief Executive Officer Thank you for joining us today. Our call is now complete. 6

7 ADVISORY NON-GAAP MEASURES This news release contains references to non-gaap measures as follows: Operating cash flow is defined as net revenues, less production and mineral taxes, transportation and selling, operating and purchased product expenses and is used to provide a consistent measure of the cash generating performance of our assets and improves the comparability of our underlying financial performance between periods. Cash flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital from continuing operations, both of which are defined on the Consolidated Statement of Cash Flows, in Cenovus s interim consolidated financial statements. Operating earnings show 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 views operating earnings as a better measure of performance than net earnings because the 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. Free cash flow is defined 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. Debt to capitalization and debt to adjusted EBITDA are two ratios that management uses to steward the company s overall debt position as measures of the company s overall financial strength. Capitalization is a measure defined as debt plus shareholders equity. Adjusted EBITDA is defined as net earnings from continuing operations 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. Debt is defined as the current and long term portions of long term debt. These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding Cenovus s liquidity and its ability to generate funds to finance its operations. For further information, refer to Cenovus s most recent Management s Discussion and Analysis (MD&A) available at OIL AND GAS INFORMATION The following estimates were prepared effective December 31, 2009 by McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator (IQRE) and are based on definitions contained in the Canadian Oil and Gas Evaluation Handbook (COGEH). For further discussion regarding our economic contingent resources and our total bitumen initially-in-place and all subcategories thereof, see our April 22, 2010, news release and our June 16, 2010, news release, respectively, available at Actual resources may be greater than or less than the estimates provided. All quantities expressed are best estimate. Total Bitumen Initially-In-Place (BIIP) (137 Bbbls) (equivalent to total resources ) is that quantity of bitumen that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in 7

8 accumulations yet to be discovered. BIIP estimates include unrecoverable volumes and are not an estimate of the volume of the substances that will ultimately be recovered. Discovered Bitumen Initially-In-Place (56 Bbbls) (equivalent to discovered resources ) is that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered bitumen initially-in-place includes production, reserves, and contingent resources; the remainder is categorized as unrecoverable. There is no certainty that it will be commercially viable to produce any portion of the estimate. Undiscovered Bitumen Initially-In-Place (82 Bbbls) (equivalent to undiscovered resources ) is that quantity of bitumen that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered bitumen initially-in-place is referred to as prospective resources, the remainder as unrecoverable. There is no certainty that any portion of the estimate will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Contingent resources are quantities of bitumen estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. For Cenovus, the contingencies which must be overcome to enable the classification of bitumen contingent resources as reserves include regulatory application submission with no major issues raised, access to markets and intent to proceed by the operator and partners as evidenced by major capital expenditures planned within five years. Economic contingent resources (5.4 Bbbls) are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. The IQRE used the same commodity price assumptions that were used for the 2009 reserves evaluation, which were determined in accordance with U.S. Securities and Exchange Commission requirements. The estimate of economic contingent resources has not been adjusted for risk based on the chance of development. There is no certainty that it will be commercially viable to produce any portion of the resources. Prospective resources (12.6 Bbbls) are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity. Unrecoverable (49 Bbbls discovered; 69 Bbbls undiscovered) is that portion of discovered or undiscovered BIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Best estimate, when used in reference to contingent resources, is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. The term best estimate, when used in reference to an in-place estimate, is not defined in COGEH; however, it was determined by the IQRE to the same 50% confidence level as was applied to previously disclosed estimates of 2P reserves and best estimate economic contingent resources. FORWARD-LOOKING INFORMATION This news release contains certain forward-looking statements and information about our current expectations, estimates and projections about the future, based on certain assumptions made by the Company in light of its experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. 8

9 Forward-looking statements and information are typically identified by words such as anticipate, believe, expect, plan, intend, forecast, target, project, objective, could, focus, vision, goal, proposed, scheduled, outlook or similar expressions suggesting future outcomes or statements regarding an outlook, including statements about our strategy, our projected future value or net asset value, operating and financial results, schedules, land positions, production, including, without limitation, the stability or growth thereof, reserves and resources, material properties, uses and development of our technology, risk mitigation efforts, commodity prices, shareholder value, cash flow, funding alternatives, costs and expected impact of future commitments in respect of our ongoing operations generally and with respect to certain properties and interests held by Cenovus. Readers are cautioned not to place undue reliance on forward-looking statements and information as our actual results may differ materially from those expressed or implied. Our forward-looking information respecting anticipated 2010 cash flow and operating cash flow is based on the following assumptions: achieving average 2010 production of approximately 120,200 bbls/d to 129,700 bbls/d of crude oil and liquids and 740 MMcf/d to 760 MMcf/d of natural gas; average commodity prices for 2010 of a WTI price of US$65 per bbl to US$85 per bbl and a WCS price of US$54 per bbl to US$71 per bbl for oil, a NYMEX price of US$5.50 per Mcf to US$6.15 per Mcf and AECO price of $5.15 per GJ to $5.70 per GJ for natural gas; an average U.S./Canadian dollar foreign exchange rate of $0.85 to $0.96 US$/CDN$; an average Chicago crack spread for 2010 of US$7.50 per bbl to US$9.50 per bbl for refining margins; and an average number of outstanding shares of approximately 752 million. Forward-looking statements involve a number of assumptions, risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The risk factors and uncertainties that could cause actual results to differ materially, and the factors or assumptions on which the forward-looking information is based, include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions inherent in our current guidance; our projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; the effect of our risk management program, including the impact of derivative financial instruments and our access to various sources of capital; accuracy of cost estimates; fluctuations in commodity, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; success of hedging strategies; maintaining a desirable debt to cash flow ratio; accuracy of our reserves, resources and future production estimates; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our ability to replace and expand oil and gas reserves; the ability of us and ConocoPhillips to maintain our relationship and to successfully manage and operate the North American integrated heavy oil business and to obtain necessary regulatory approvals; the successful and timely implementation of capital projects; reliability of our assets; 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 synthetic crude oil; risks associated with technology and its application to our business; our ability to generate sufficient cash flow from operations to meet our current and future obligations; our ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or the interpretations of such laws or regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on us, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in 9

10 which we operate; the occurrence of unexpected events such as war, terrorist threats, hostilities, civil insurrection and instability affecting countries in which we operate; risks associated with existing and potential future lawsuits and regulatory actions made against us; our financing plans and initiatives; the expected impacts of the plan of arrangement with Encana Corporation ( Arrangement ) on our employees, operations, suppliers, business partners and stakeholders and our ability to realize the expected benefits of the Arrangement; our ability to obtain financing in the future on a stand alone basis; the historical financial information pertaining to our assets as operated by Encana Corporation prior to November 30, 2009 may not be representative of our results as an independent entity; our limited operating history as a separate entity and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities. Readers are cautioned that the foregoing list is not exhaustive. Many of these risk factors are discussed in further detail in our Annual Information Form/Form 40-F and our annual and interim MD&A as filed with Canadian securities regulatory authorities at and the U.S. Securities and Exchange Commission at and available at The forward-looking statements and information contained in this document, including the assumptions, risks and uncertainties underlying such statements, are made as of the date of this document and, except as required by law, we do not undertake any obligation to update publicly or to revise any of such information, whether as a result of new information, future events or otherwise. The forwardlooking statements and information contained in this document are expressly qualified by this cautionary statement. 10