CALGARY, AB–(Marketwired – May 11, 2017) – MEG Energy Corp. (TSX: MEG) today reported first quarter 2017 operating and financial results. Highlights include:
- Quarterly production volumes of 77,245 barrels per day (bpd);
- Net operating costs of $8.43 per barrel and non-energy operating costs of $5.20 per barrel;
- Total cash capital investment of $78 million, primarily directed towards the eMSAGP growth initiative at Christina Lake Phase 2B;
- Cash and cash equivalents of $549 million as of March 31, 2017; and
- The completion of a comprehensive refinancing which has contributed to a strengthened financial profile, with its equity component primarily funding MEG’s 20,000 bpd growth plans at Christina Lake.
MEG’s first quarter 2017 production was 77,245 bpd, compared to 76,640 bpd for the first quarter of 2016. Production for the first quarter met the forecast provided by the company in its 2016 year end disclosure, and was partially impacted by preparatory work to facilitate the drilling of infill wells and pipeline maintenance at the Christina Lake project. MEG increased production over first quarter 2016 levels primarily due to the continued implementation of eMSAGP, which has improved reservoir efficiency and allowed for redeployment of steam, enabling the company to place additional wells into production. MEG is on track to meet its annual production guidance of 80,000 bpd to 82,000 bpd and targets exit production for 2017 of 86,000 bpd to 89,000 bpd.
“By initiating the expansion of eMSAGP to our Phase 2B assets which represent 75% of our production, we are embarking on a step change for MEG’s business,” said Bill McCaffrey, President and Chief Executive Officer. “We are very excited that our drilling program is proceeding on time and on budget and when we see production ramp up beginning in the third quarter, the benefits of this technology will become evident. Where we have already implemented it, the eMSAGP process has enabled us to increase production, reduce costs and cut the steam-oil ratio by about 50% to an industry-leading range of 1.0 to 1.25.”
MEG anticipates that the company’s next project, known as the Phase 2B brownfield expansion, will proceed in 2018, with actual timing to be determined as the company formulates its 2018 capital budget later this year. This expansion will add a further 13,000 barrels per day and can be done concurrently with the implementation of eMSAGP. The company expects the eMSAGP and brownfield expansions to bring production to approximately 113,000 barrels per day and reduce corporate cash costs by $6 to $7 per barrel.
For the first quarter of 2017, non-energy operating costs averaged $5.20 per barrel compared to $6.45 per barrel for the same period in 2016, mainly due to efficiency gains and a continued focus on cost management. Energy operating costs averaged $4.18 per barrel for the first quarter of 2017 compared to $2.90 per barrel for the first quarter of 2016, primarily due to increased natural gas prices.
MEG realized adjusted funds flow of $43 million for the first quarter of 2017 compared to negative adjusted funds flow of $131 million for the same period in 2016. The increase in adjusted funds flow is directly correlated to increased bitumen realization as a result of an increase in average U.S. crude oil benchmark pricing. Adjusted funds flow was also impacted by MEG’s bitumen production exceeding sales volumes as the company focused on maximizing future revenues, as well as a transitional one-time $9 million interest expense associated with MEG’s debt restructuring incurred to take advantage of a lower early redemption premium on MEG’s 2021 notes.
The company recorded a first quarter 2017 operating loss of $79 million compared to an operating loss of $197 million for the same period in 2016. The decrease in operating loss reflects the same factors impacting adjusted funds flow.
Capital Investment and Financial Liquidity
Total cash capital investment during the first quarter of 2017 was $78 million, compared to $35 million for the same period in 2016. Capital investment in 2017 was primarily directed towards the company’s eMSAGP production growth initiative at Christina Lake Phase 2B. In the first quarter, the company drilled 14 out of a total of 39 infill wells planned for 2017, with as many as 28 additional SAGD well pairs planned for the remainder of the year. MEG expects to fund the remaining 2017 capital program with a combination of internally generated funds flow and $549 million of cash on hand as of March 31, 2017.
MEG has entered into a series of hedges designed to protect its capital program against downward movements in crude oil prices. MEG’s five-year covenant-lite US$1.4 billion credit facility remains undrawn.
Operational and Financial Highlights
The following table summarizes selected operational and financial information of the Corporation for the periods noted. All dollar amounts are stated in Canadian dollars ($ or C$) unless otherwise noted:
|($ millions, except as indicated)||Q1||Q4||Q3||Q2||Q1||Q4||Q3||Q2|
|Bitumen production – bbls/d||77,245||81,780||83,404||83,127||76,640||83,514||82,768||71,376|
|Bitumen realization – $/bbl||37.93||36.17||30.98||30.93||11.43||23.17||31.03||44.54|
|Net operating costs – $/bbl(1)||8.43||8.24||7.76||7.43||8.53||8.52||9.10||9.43|
|Non-energy operating costs – $/bbl||5.20||4.99||5.32||5.81||6.45||5.66||5.98||7.01|
|Cash operating netback – $/bbl(2)||22.33||21.73||16.74||16.09||(3.71)||9.05||16.41||29.64|
|Adjusted funds flow(3)||43||40||23||7||(131)||(44)||24||99|
|Per share, diluted(3)||0.16||0.18||0.10||0.03||(0.58)||(0.20)||0.11||0.44|
|Operating earnings (loss)(3)||(79)||(72)||(88)||(98)||(197)||(140)||(87)||(23)|
|Per share, diluted(3)||(0.29)||(0.32)||(0.39)||(0.43)||(0.88)||(0.62)||(0.39)||(0.10)|
|Net earnings (loss)(5)||2||(305)||(109)||(146)||131||(297)||(428)||63|
|Per share, basic||0.01||(1.34)||(0.48)||(0.65)||0.58||(1.32)||(1.90)||0.28|
|Per share, diluted||0.01||(1.34)||(0.48)||(0.65)||0.58||(1.32)||(1.90)||0.28|
|Total cash capital investment(6)||78||63||19||20||35||54||32||90|
|Cash and cash equivalents||549||156||103||153||125||408||351||438|
|(1)||Net operating costs include energy and non-energy operating costs, reduced by power revenue.|
|(2)||Cash operating netback is calculated by deducting the related diluent expense, transportation, operating expenses, royalties and realized commodity risk management gains (losses) from proprietary blend revenues and power revenues, on a per barrel of bitumen sales volume basis.|
|(3)||Adjusted funds flow, Operating earnings (loss) and the related per share amounts do not have standardized meanings prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. For the three months ended March 31, 2017 and March 31, 2016, the non-GAAP measure of adjusted funds flow is reconciled to net cash provided by (used in) operating activities and the non-GAAP measure of operating earnings (loss) is reconciled to net earnings (loss) in accordance with IFRS under the heading “NON-GAAP MEASURES” and discussed further in the “ADVISORY” section.|
|(4)||The total of Petroleum revenue, net of royalties and Other revenue as presented on the Interim Consolidated Statement of Earnings and Comprehensive Income.|
|(5)||Includes a net unrealized foreign exchange gain of $36.7 million on the Corporation’s U.S. dollar denominated debt and U.S. dollar denominated cash and cash equivalents for the three months ended March 31, 2017. The net earnings for the three months ended March 31, 2016 includes a net unrealized foreign exchange gain of $320.3 million.|
|(6)||Defined as total capital investment excluding dispositions, capitalized interest, capitalized cash-settled stock-based compensation and non-cash items.|
|(7)||On December 8, 2016, Fitch Ratings (“Fitch”) assigned the Corporation a first-time Long-Term Issuer Default Rating of B, and assigned a rating of BB to the Corporation’s covenant-lite revolving credit facility and term loan and a rating of B to the Corporation’s Senior Unsecured Notes. On January 12, 2017, Fitch assigned a BB rating to the Corporation’s new Senior Secured Second Lien Notes (see the “Capital Resources” section of the MD&A contained in MEG’s First Quarter 2017 Report to Shareholders). Fitch’s rating outlook is negative. On January 12, 2017, Standard & Poor’s Ratings Services (“S&P”) assigned a BB+ rating to the Corporation’s new Senior Secured Second Lien Notes. On January 12, 2017, Moody’s Investors Service (“Moody’s”) upgraded the Corporation’s Corporate Family Rating to B3 from Caa2, the Probability of Default Rating to B3-PD from Caa2-PD and the Corporation’s Senior Unsecured Notes rating to Caa2 from Caa3. Moody’s Speculative Grade Liquidity Rating was raised to SGL-1 from SGL-2. Moody’s also assigned a rating of Ba3 to the Corporation’s covenant-lite revolving credit facility and refinanced term loan and a rating of Caa1 to the new Senior Secured Second Lien Notes. Moody’s rating outlook was changed to stable from negative.|
Basis of Presentation
MEG prepares its financial statements in accordance with International Financial Reporting Standards (“IFRS”) and presents financial results in Canadian dollars ($ or C$), which is the corporation’s functional currency.
Certain financial measures in this new release including: net marketing activity, funds flow, adjusted funds flow, operating earnings (loss), operating cash flow and total debt are non-GAAP measures. These terms are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. These non-GAAP financial measures should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS.
Funds Flow and Adjusted Funds Flow
Funds flow and adjusted funds flow are non-GAAP measures utilized by the Corporation to analyze operating performance and liquidity. Funds flow excludes the net change in non-cash operating working capital while the IFRS measurement “net cash provided by (used in) operating activities” includes these items. Adjusted funds flow excludes the net change in non-cash operating working capital, payments on onerous contracts, and decommissioning expenditures while the IFRS measurement “net cash provided by (used in) operating activities” includes these items. Funds flow and adjusted funds flow are not intended to represent net cash provided by (used in) operating activities calculated in accordance with IFRS. Funds flow and adjusted funds flow are reconciled to net cash provided by (used in) operating activities in the table below.
|Three months ended March 31|
|Net cash provided by (used in) operating activities||$||45,806||$||(220,671)|
|Net change in non-cash operating working capital items||(8,187)||87,840|
|Payments on onerous contracts||4,134||629|
|Adjusted funds flow||$||43,175||$||(131,240)|
Operating Earnings (Loss)
Operating earnings (loss) is a non-GAAP measure which the Corporation uses as a performance measure to provide comparability of financial performance between periods by excluding non-operating items. Operating earnings (loss) is defined as net earnings (loss) as reported, excluding unrealized foreign exchange gains and losses, unrealized gains and losses on derivative financial instruments, unrealized gains and losses on commodity risk management, onerous contracts expense, and the respective deferred tax impact on these adjustments. Operating earnings (loss) is reconciled to “Net earnings (loss)”, the nearest IFRS measure, in the table below.
|Three months ended March 31|
|Net earnings (loss)||$||1,588||$||130,829|
|Unrealized net loss (gain) on foreign exchange(1)||(36,707)||(320,281)|
|Unrealized loss (gain) on derivative financial liabilities(2)||(2,241)||5,489|
|Unrealized loss (gain) on commodity risk management(3)||(59,599)||(16,963)|
|Onerous contracts expense(4)||2,375||4,371|
|Deferred tax expense (recovery) relating to these adjustments||15,230||(731)|
|Operating earnings (loss)||$||(79,354)||$||(197,286)|
|(1)||Unrealized net foreign exchange gains and losses result from the translation of U.S. dollar denominated long-term debt and cash and cash equivalents using period-end exchange rates.|
|(2)||Unrealized gains and losses on derivative financial liabilities result from the interest rate floor on the Corporation’s long-term debt and interest rate swaps entered into to effectively fix a portion of its variable rate long-term debt.|
|(3)||Unrealized gains or losses on commodity risk management contracts represent the change in the mark-to-market position of the unsettled commodity risk management contracts during the period.|
|(4)||During the three months ended March 31, 2017, onerous contracts expense was recognized primarily due to changes in estimated future cash flow sublease recoveries related to the onerous office lease provision for certain corporate office building lease contracts. During the three months ended March 31, 2016, onerous contracts expenses were recognized primarily due to the reduction of the Corporation’s capital program for 2016 and its impact on drilling contracts.|
This document may contain forward-looking information including but not limited to: expectations of future production, revenues, expenses, cash flow, operating costs, steam-oil ratios, pricing differentials, reliability, profitability and capital investments; estimates of reserves and resources; anticipated reductions in operating costs as a result of optimization and scalability of certain operations; and anticipated sources of funding for operations and capital investments. Such forward-looking information is based on management’s expectations and assumptions regarding future growth, results of operations, production, future capital and other expenditures, plans for and results of drilling activity, environmental matters, and business prospects and opportunities.
By its nature, such forward-looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: risks associated with the oil and gas industry, for example, results securing access to markets and transportation infrastructure; availability of capacity on the electricity transmission grid; uncertainty of reserve and resource estimates; uncertainty associated with estimates and projections relating to production, costs and revenues; health, safety and environmental risks; risks of legislative and regulatory changes to, amongst other things, tax, land use, royalty and environmental laws; assumptions regarding and the volatility of commodity prices, interest rates and foreign exchange rates, and, risks and uncertainties related to commodity price, interest rate and foreign exchange rate swap contracts and/or derivative financial instruments that MEG may enter into from time to time to manage its risk related to such prices and rates; risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with MEG’s future phases and the expansion and/or operation of MEG’s projects; risks and uncertainties related to the timing of completion, commissioning, and start-up, of MEG’s future phases, expansions and projects; the operational risks and delays in the development, exploration, production, and the capacities and performance associated with MEG’s projects; and uncertainties arising in connection with any future disposition of assets.
Although MEG believes that the assumptions used in such forward-looking information are reasonable, there can be no assurance that such assumptions will be correct. Accordingly, readers are cautioned that the actual results achieved may vary from the forward-looking information provided herein and that the variations may be material. Readers are also cautioned that the foregoing list of assumptions, risks and factors is not exhaustive.
Further information regarding the assumptions and risks inherent in the making of forward-looking statements can be found in MEG’s most recently filed Annual Information Form (“AIF”), along with MEG’s other public disclosure documents. Copies of the AIF and MEG’s other public disclosure documents are available through the SEDAR website which is available at www.sedar.com.
The forward-looking information included in this document is expressly qualified in its entirety by the foregoing cautionary statements. Unless otherwise stated, the forward-looking information included in this document is made as of the date of this document and MEG assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law.
A conference call will be held to review the financial results at 7:30 a.m. Mountain Time (9:30 a.m. Eastern Time) on Thursday, May 11, 2017. The U.S./Canada toll-free conference call number is 1 866-225-0198. The international/local conference call number is 416-340-2218.
MEG Energy Corp. is focused on sustainable in situ oil sands development and production in the southern Athabasca oil sands region of Alberta, Canada. MEG is actively developing enhanced oil recovery projects that utilize SAGD extraction methods. MEG’s common shares are listed on the Toronto Stock Exchange under the symbol “MEG.”
For further information, please contact:
Director, Investor Relations
Senior Advisor, External Communications