CALGARY, AB–(Marketwired – April 26, 2017) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) continued to deliver strong operational performance in the first quarter of 2017, increasing oil sands production by almost one-third while further reducing per-barrel crude oil operating costs compared with the same period in 2016. As a result of its reduced cost structure, significant liquidity and strong financial position, the company was also able to pursue the agreement, announced March 29, 2017, to acquire assets in Alberta and British Columbia from ConocoPhillips for approximately $17.7 billion. The agreement includes ConocoPhillips’ 50% interest in the FCCL Partnership, the companies’ jointly owned oil sands venture, as well as its Deep Basin assets. The transaction, which will be immediately accretive to key performance measures, is expected to close in the second quarter.
- Legacy assets at Pelican Lake and Suffield are being actively marketed
- On track with plan to integrate Deep Basin assets and staff upon closing
- Raised $3.0 billion gross proceeds through a bought-deal offering of common shares
- Closed long-term senior unsecured notes offering for US$2.9 billion gross proceeds
Key first quarter developments
- Generated adjusted funds flow of $323 million, compared with $26 million in 2016. Adjusted funds flow benefited from higher crude oil sales prices, partially offset by about $90 million in realized hedging losses, $29 million in acquisition-related transaction costs and about $20 million related to higher crude oil inventories
- Cash from operating activities was $328 million, an 80% increase from 2016
- Resumed field construction of the Christina Lake phase G expansion project
- Successfully drilled 252 oil wells using an average of 21 drilling rigs. This included 232 gross stratigraphic test wells and 20 gross horizontal wells
|Production & financial summary|
|(For the period ended March 31) Production (before royalties)||2017
|Oil sands (bbls/d)||181,501||137,975||32|
|Conventional oil1 (bbls/d)||53,413||59,576||-10|
|Total oil (bbls/d)||234,914||197,551||19|
|Natural gas (MMcf/d)||363||408||-11|
($ millions, except per share2 amounts)
|Cash from operating activities||328||182||80|
|Adjusted funds flow3||323||26||1,142|
|Per share diluted||0.39||0.03|
|Per share diluted||-0.05||-0.51|
|Per share diluted||0.25||-0.14|
1 Includes natural gas liquids (NGLs).
2 Per share amounts exclude the impact of the bought-deal offering of common shares which closed April 6, 2017.
3 Adjusted funds flow and operating earnings are non-GAAP measures. For more information, refer to the Non-GAAP Measures section of the Advisory at the end of this news release.
Asset acquisition update
Since announcing its agreement to purchase the ConocoPhillips assets, Cenovus has made significant progress in executing its acquisition plan. To reduce debt associated with the transaction and strengthen its balance sheet, the company has been marketing its legacy Pelican Lake and Suffield conventional assets with data rooms open to prospective buyers.
“These assets have attracted strong initial interest from a wide variety of potential purchasers,” said Brian Ferguson, Cenovus President & Chief Executive Officer. “Our data rooms have been very busy, and that bodes well as we look to successfully conclude transactions to further streamline our asset portfolio, help preserve our financial resilience and deleverage our balance sheet.”
Asset sale proceeds are expected to be applied against anticipated draws on Cenovus’s asset-sale bridge facility and existing credit facility, which are part of the company’s acquisition financing plan. On April 6, 2017, Cenovus successfully closed a bought-deal offering of common shares with gross proceeds of $3.0 billion. In addition, on April 7, 2017, the company completed a US$2.9 billion long-term debt offering of 4.9% (weighted average) senior unsecured notes. Cenovus has also obtained commitments from its lending syndicate to extend the maturities of its existing credit facility tranches to 2020 and 2021 and increase the total capacity from $4.0 billion to $4.5 billion. The company expects this credit facility transaction to close later this week.
Upon closing, the acquisition will give Cenovus two attractive growth platforms in Western Canada, providing the company with enhanced opportunities to increase total shareholder return, including assessing the optimal level of its dividend once the company’s divestiture of legacy assets is complete. If the acquisition had closed on the January 1, 2017 effective date, the transaction would have been expected to more than double the company’s production, increasing 2017 forecast volumes by approximately 298,000 barrels of oil equivalent per day (BOE/d). After completing the transaction, Cenovus will have total combined regulatory approval for 735,000 barrels per day (bbls/d) of production capacity at its FCCL assets, including existing operating capacity and potential capacity additions. Cenovus will also gain 1,500 potential drilling opportunities in the Deep Basin. The acquisition is expected to be immediately accretive to key performance measures and to give Cenovus capacity to generate forecast 2018 free funds flow of approximately $500 million, net of planned asset divestitures, with West Texas Intermediate (WTI) oil prices at US$50/bbl and New York Mercantile Exchange (NYMEX) natural gas prices at US$3 per million British thermal units (MMBtu).
If the acquisition had closed on the January 1, 2017 effective date, forecast capital investment for the year in the acquired Deep Basin assets would have been anticipated to be approximately $170 million, with plans for increased investment levels in the following two years. The company believes these properties, which will continue to be operated by staff joining Cenovus from ConocoPhillips, have the potential to achieve a more than 40% increase in production to average approximately 170,000 BOE/d in 2019. With this moderate amount of capital investment, these assets are expected to make a significant contribution to increased adjusted funds flow. Additionally, the Deep Basin is expected to offset Cenovus’s demand for natural gas as oil sands production increases, as well as provide NGLs that could be used as solvents. The company plans to implement a solvent-aided process at its oil sands operations to potentially enhance in-situ recovery and improve environmental and economic performance.
“With the successful completion of this transaction, we’ll have a combined portfolio of long-cycle oil sands development, complemented by the short-cycle opportunities in the Deep Basin, which we believe will provide us with a clear line of sight to a decade of growth and value creation for our company and shareholders,” said Ferguson. “We are focused on completing this acquisition and executing our transition plan to help ensure a smooth and timely transfer of staff and facilities to Cenovus.”
At its Investor Day in June 2017, Cenovus intends to provide an update on its plans for Foster Creek phase H and Narrows Lake phase A, including expectations for capital efficiencies and timing for each project. Foster Creek phase H has an expected design capacity of 30,000 bbls/d and Narrows Lake phase A has an expected design capacity of 45,000 bbls/d. The company continues to advance engineering work on the two deferred expansion projects using the same rigour that was applied to Christina Lake phase G. Cenovus also expects to provide additional information on its plans for the new Deep Basin assets and on technologies being developed to potentially enhance operating performance across its oil sands projects.
From 2014 to 2016, Cenovus’s focus on cost efficiency and innovation led to a 30% reduction in its per-barrel oil sands non-fuel operating costs as well as a 50% reduction in oil sands sustaining capital costs. In that same period, the company has also reduced general and administrative (G&A) expenses per BOE by about one-third, excluding charges related to severance and office building leases in Calgary that exceed Cenovus’s current and near-term requirements. With anticipated future cost reductions, opportunities to improve reservoir performance and the potential to develop its large portfolio of emerging assets, Cenovus expects to be well positioned at the close of the acquisition to create significant value across a substantially larger oil sands resource and production base.
Cenovus has made all required regulatory filings in connection with the acquisition and is awaiting the required approvals. In addition, on March 31, 2017, the Toronto Stock Exchange approved the listing of 208 million common shares to be issued to ConocoPhillips upon closing of the acquisition, subject to customary closing conditions. The New York Stock Exchange approved the listing of such shares on April 11, 2017.
First quarter overview
In the first quarter of 2017, the ramp-up of the Christina Lake phase F and Foster Creek phase G expansion projects continued as expected. Incremental volumes from the new phases contributed to first quarter oil sands production, net to Cenovus, of more than 181,000 bbls/d, a 32% increase from the same period in 2016. The expansions increased the company’s total oil sands production capacity by 26%, or 80,000 bbls/d gross, to 390,000 bbls/d gross. The new 100-megawatt natural gas fired cogeneration plant at Christina Lake, which provides reliable, energy-efficient power to the project, completed its start up in the first quarter.
Field construction has resumed at Christina Lake phase G and is expected to ramp up through the remainder of the second quarter. The company anticipates the expansion can be completed with go-forward capital investment of between $16,000 and $18,000 per flowing barrel. Phase G has an expected design capacity of 50,000 bbls/d gross. First oil is anticipated in the second half of 2019. At its oil sands business, Cenovus drilled 206 gross stratigraphic test wells in the first quarter of 2017. These wells are drilled to help identify pad locations for sustaining wells and near-term expansion phases as well as to further evaluate emerging assets.
Cenovus’s conventional oil and natural gas portfolio remains the most flexible part of its capital investment program and with moderate spending is expected to be able to generate significant free funds flow to invest in growth opportunities. In the first quarter of 2017, the conventional portfolio generated $57 million in free funds flow. Cenovus more than doubled capital investment in its conventional portfolio to $88 million in the first quarter of 2017 compared with a year earlier, mostly due to the company’s targeted drilling program on the Palliser Block, which is proceeding as expected. Cenovus drilled 20 horizontal oil wells and 26 stratigraphic test wells during the first three months of the year. The completion of wells drilled in late 2016, combined with drilling in the first quarter, resulted in the addition of approximately 1,300 bbls/d of crude oil production from the Palliser Block for the period, with incremental volumes reaching 3,300 bbls/d as of March 31. Overall, conventional oil production in the first quarter of 2017 was 53,413 bbls/d, a 10% decrease from the same period a year earlier, largely due to expected natural declines. Cenovus plans to sell a significant portion of its legacy conventional properties to help finance the company’s acquisition of the Deep Basin and FCCL assets.
Cenovus continued to achieve additional operating cost and sustaining capital reductions in the first quarter of 2017. Oil sands operating costs were $8.97/bbl in the first quarter, a 6% decrease from the same period a year earlier, while non-fuel oil sands operating costs were $6.23/bbl, a 15% decline. At Cenovus’s conventional assets, despite expected production declines, per-unit liquids operating costs continued to improve, declining 2% to $14.47/bbl compared with the first quarter of 2016. G&A costs declined 28% compared with the first quarter of 2016, mostly as a result of lower expenses associated with Cenovus’s employee long-term incentives and its Calgary real estate commitments.
Financial performance and resilience
In the first quarter of 2017, Cenovus generated adjusted funds flow of $323 million, compared with $26 million in 2016. Adjusted funds flow improved due to the nearly three-fold increase in Cenovus’s crude oil sales price and higher refining and marketing operating margins compared with 2016. This was partially offset by about $90 million in realized hedging losses, $29 million in transaction costs related to the acquisition and approximately $20 million related to linefill inventory for additional pipeline takeaway capacity from Christina Lake and oil held in storage. Cash from operating activities increased 80% to $328 million from the same period in 2016. Cenovus’s average crude oil sales price was $41.41/bbl in the first quarter, up from $15.97/bbl in the same period of 2016. Cenovus had a companywide netback of $19.11/BOE on its crude oil and natural gas production in the first quarter of 2017 compared with a loss of $0.12/BOE in the year earlier period.
Cenovus has an active hedging program to support cash outflows and to help maintain financial resilience. As of April 25, 2017, the company had hedges in place on approximately 87,500 bbls/d of crude oil for the remainder of this year at an average floor price of US$49.20/bbl and 50,000 bbls/d of crude oil hedged for the first half of 2018 with an average floor price of US$49.74/bbl. To further support Cenovus’s financial resilience while the asset sale bridge loan remains outstanding, the company plans to hedge a greater percentage of forecast liquids and natural gas volumes, allowing increased certainty on a greater portion of expected cash outflows.
|Current hedge positions for 2017|
|Hedges at April 25, 2017||Volume||Price|
|Crude – WTI Fixed Price
January – June
|Crude – Brent Fixed Price
July – December
|Crude – WTI Collars
July – December
|50,000 bbls/d||US$44.84/bbl – US$56.47/bbl|
|Crude – Brent – WTI Spread
July – December
|Current hedge positions for 2018|
|Hedges at April 25, 2017||Volume||Price|
|Crude – Brent Collars
January – June
|30,000 bbls/d||US$49.78/bbl – US$62.08/bbl|
|Crude – Brent Fixed Price
January – June
|Crude – WTI Collars
January – June
|10,000 bbls/d||US$45.30/bbl – US$62.77/bbl|
First quarter details
- Production averaged 80,866 bbls/d net in the first quarter of 2017, 33% more than in the same period of 2016, due to incremental crude oil volumes from the phase G expansion and additional wells being brought online.
- Operating costs declined 17% to $9.99/bbl in the first quarter from the same period the previous year. Non-fuel operating costs were $7.06/bbl, a 26% decrease from the first quarter of 2016.
- The steam to oil ratio (SOR), the amount of steam needed to produce one barrel of oil, was 2.5 in the first quarter of 2017 compared with 3.0 in the same period of 2016.
- In the first quarter, production averaged 100,635 bbls/d net, a 31% increase from the same period in 2016, largely due to the start-up of expansion phase F, which began contributing volumes in late 2016, and continued reliable facility performance.
- Operating costs were $8.08/bbl, a 6% increase from the first quarter a year earlier. Non-fuel operating costs were $5.51/bbl, down 2% from a year ago.
- The SOR was 1.8 in the first quarter of 2017 compared with 1.9 a year earlier.
- Total conventional oil production decreased 10% to 53,413 bbls/d in the first quarter of 2017 compared with the same period the previous year, primarily due to expected natural reservoir declines.
- Liquids operating costs were $14.47/bbl in the first quarter of 2017, 2% lower than the same period a year earlier. This was primarily the result of lower chemical costs due to more efficient use, decreased repairs, maintenance and workovers, a decline in waste fluid handling and trucking costs, lower electricity costs due to reduced consumption, and decreased workforce costs.
- Natural gas production averaged 363 million cubic feet per day (MMcf/d) in the first quarter of 2017, down 11% from the same period a year earlier, primarily due to expected natural declines.
- Per-unit operating costs increased 9% to $1.34 per thousand cubic feet (Mcf) in the first quarter of 2017 largely due to reduced output compared with the same period in 2016.
- The Wood River Refinery in Illinois and Borger Refinery in Texas, which Cenovus jointly owns with the operator, Phillips 66, processed a combined average of 406,000 bbls/d gross of oil (88% utilization) in the first quarter of 2017, compared with 435,000 bbls/d gross in the year earlier period (95% utilization).
- The refineries’ financial performance in the first quarter of 2017 improved compared with the same period a year earlier. The improvement was mostly due to a 20% increase in the average 3-2-1 Chicago market crack spread, which was partially offset by lower crude oil runs and refined product output due to planned turnarounds.
- Cenovus had refining and marketing operating margin of $53 million in the quarter, compared with a shortfall of $23 million in the same period of 2016. The company’s refining operating margin is calculated on a first-in, first-out (FIFO) inventory accounting basis. Using the last-in, first-out (LIFO) accounting method employed by most U.S. refiners, Cenovus’s operating margin from refining and marketing would have been $44 million lower in the quarter. In the first quarter of 2016, operating margin would have been $37 million higher on a LIFO reporting basis.
Corporate and financial information
- Operating margin was $450 million in the first quarter of 2017, a three-fold increase from the same period in 2016, largely due to higher commodity prices, higher operating margin from refining and marketing and an 11% increase in crude oil sales. The increase in operating margin was partially offset by realized risk management losses of $90 million, excluding refining and marketing, compared with gains of $145 million in the first quarter of 2016, a rise in transportation and blending expenses largely due to increased condensate prices and higher consumption, as well as higher royalties.
- Cash from operating activities and adjusted funds flow increased largely due to higher operating margin.
- Cenovus had free funds flow of $10 million, compared with a free funds flow shortfall of $297 million a year earlier.
- The company’s operating loss was $39 million in the first quarter of 2017 compared with a loss of $423 million in the same period a year earlier. The improvement was primarily due to an increase in cash from operating activities and adjusted funds flow, a decline in depreciation, depletion and amortization (DD&A) due to a $170 million impairment recorded in the first quarter of 2016, and a lower non-cash expense recorded for office space in excess of Cenovus’s current and near-term needs.
- Cenovus had net earnings of $211 million in the first quarter of 2017. This compares with a net loss of $118 million in the same period a year earlier when benchmark crude oil prices fell to a 13-year low.
- G&A costs were $43 million in the first quarter of 2017, down from $60 million in the same period of 2016. The decline in G&A costs was related to reduced long-term employee incentive costs primarily due to a lower share price. G&A costs also included an $8 million non-cash expense related to office building leases in Calgary that exceed Cenovus’s current and near-term requirements, compared with a $14 million non-cash expense in the first quarter of 2016.
- The company ended the first quarter of 2017 with cash and cash equivalents of approximately $3.5 billion as well as $4.0 billion in undrawn capacity under its committed credit facility and no debt maturities until the fourth quarter of 2019. At the end of the first quarter, Cenovus’s net debt to capitalization was 19% compared with 16% a year ago. The company’s net debt to adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) was 1.6 times on a trailing 12-month basis compared with 1.3 times a year earlier.
- For the second quarter of 2017, the Board of Directors has declared a dividend of $0.05 per share, payable on June 30, 2017 to common shareholders of record as of June 15, 2017. Based on the April 25, 2017 closing share price on the Toronto Stock Exchange of $14.26, this represents an annualized yield of about 1.4%. Declaration of dividends is at the sole discretion of the Board and will continue to be evaluated on a quarterly basis.
Conference Call Today
9 a.m. Mountain Time (11 a.m. Eastern Time)
Cenovus will host a conference call today, April 26, 2017, starting at 9 a.m. MT (11 a.m. ET). To participate, please dial 888-231-8191 (toll-free in North America) or 647-427-7450 approximately 10 minutes prior to the conference call. A live audio webcast of the conference call will also be available via cenovus.com. The webcast will be archived for approximately 90 days.
Basis of Presentation
Cenovus reports financial results in Canadian dollars and presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated. Cenovus prepares its financial statements in accordance with International Financial Reporting Standards (IFRS).
Oil and Gas Information
Barrels of Oil Equivalent
Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one barrel (bbl). BOE 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 wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
This news release discloses potential future drilling locations in two categories: (a) proved locations and (b) probable locations. This news release also discloses additional un-booked future drilling opportunities. Proved locations and probable locations are proposed drilling locations identified in reserve reports prepared for assets acquired pursuant to the ConocoPhillips asset acquisition that have proved and/or probable reserves, as applicable, attributed to them in such reports. Un-booked future drilling opportunities are internal Cenovus estimates based on prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal Cenovus technical analysis and review. Un-booked future drilling opportunities have been identified by Cenovus management based on evaluation of applicable geologic, seismic, engineering, production and reserves information. Un-booked future drilling opportunities do not have proved or probable reserves attributed to them in the relevant reserves reports. Of the approximately 1,500 identified drilling opportunities within the Deep Basin assets to be acquired, 212 are proved locations, 221 are probable locations and the remainder are un-booked future drilling opportunities.
Cenovus’s ability to drill and develop these locations and opportunities and the drilling locations on which Cenovus actually drills wells depends on a number of uncertainties and factors, including, but not limited to, the availability of capital, equipment and personnel, oil and natural gas prices, capital and operating costs, inclement weather, seasonal restrictions, drilling results, additional geological, geophysical and reservoir information that is obtained, production rate recovery, gathering system and transportation constraints, net price received for commodities produced, regulatory approvals and regulatory changes. As a result of these uncertainties, there can be no assurance that the potential future drilling locations and opportunities Cenovus has identified will ever be drilled or if Cenovus will be able to produce oil, NGL or natural gas from these or any other potential drilling locations or opportunities. As such, Cenovus’s actual drilling activities may differ materially from those presently identified, which could adversely affect Cenovus’s business. While certain of the identified un-booked drilling opportunities have been de-risked by drilling existing wells in relatively close proximity to such un-booked drilling opportunities, some of the other un-booked drilling opportunities are farther away from existing wells where Cenovus management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled and, if drilled, there is further uncertainty that such wells will result in additional proved or probable reserves or production.
Non-GAAP Measures and Additional Subtotal
The following measures do not have a standardized meaning as prescribed by IFRS and therefore are considered non-GAAP measures. You should not consider these measures in isolation or as a substitute for analysis of our results as reported under IFRS. These measures are defined differently by different companies in our industry. These measures may not be comparable to similar measures presented by other issuers.
Adjusted Funds Flow is used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as Cash From Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital. Net change in other assets and liabilities is composed of site restoration costs and pension funding. Non-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents and risk management.
Free Funds Flow is defined as Adjusted Funds Flow less capital investment.
Operating earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.
Debt to capitalization, net debt to capitalization, debt to adjusted EBITDA and net debt to adjusted EBITDA are ratios that management uses to steward the company’s overall debt position as measures of the company’s overall financial strength. Debt is defined as short-term borrowings and long-term debt, including the current portion. Net debt is defined as debt net of cash and cash equivalents. Capitalization is defined as debt plus shareholders’ equity. Net debt to capitalization is defined as net debt divided by net debt plus shareholders’ equity. Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, goodwill and asset impairments, unrealized gains or losses on risk management, foreign exchange gains or losses, gains or losses on divestiture of assets and other income and loss, calculated on a trailing 12-month basis.
Operating margin is an additional subtotal found in Note 1 of the Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin.