MEG Energy reports strong operating and financial results and ongoing efficiency gains for the third quarter of 2017
Contributing to an $80 million reduction in its 2017 capital investment and a further decrease in non-energy operating cost guidanceStrong cash position, proven technology and significant cost reductions position MEG well to continue highly-economic growth
All financial figures in Canadian dollars ($ or C$) unless otherwise noted
CALGARY, Oct. 26, 2017 - MEG Energy Corp. (TSX:MEG) today reported third quarter 2017 operating and financial results. Highlights include:
- Quarterly production volumes of 83,008 barrels per day (bpd) with October production currently averaging approximately 85,000 bpd, reflecting the ramp-up of MEG's eMSAGP growth initiative at Christina Lake Phase 2B which is proceeding on schedule and under budget;
- Record-low quarterly net operating costs of $6.00 per barrel supported by non-energy operating costs of $4.57 per barrel;
- A 14% reduction in the company's capital budget guidance, from $590 million to $510 million, with the majority of the reduction driven by ongoing efficiency improvements, lower construction costs and improved facility design;
- Strong operational and financial results contributing to cash and cash equivalents of $398 million as of September 30, 2017; and
- A second sequential reduction in MEG's non-energy operating cost guidance to $4.75 - $5.00 per barrel, reflecting ongoing efficiency gains and a continued focus on cost management. The new guidance compares to the previous guidance of $5.00 - $5.50 per barrel and is 22% lower than the initial guidance of $5.75 - $6.75 per barrel at its mid-point.
MEG's third quarter 2017 production averaged 83,008 bpd, compared to 72,448 bpd for the previous quarter. Production for the third quarter reflected ramp-up from the company's second quarter turnaround and was partially affected by adverse weather conditions at the company's Christina Lake facility and the timing of tying in new wells that are part of the eMSAGP Phase 2B implementation. The company remains on track to meet its 2017 average production guidance of 80,000 to 82,000 bpd and exit the year with production between 86,000 and 89,000 bpd.
"MEG's ongoing technological developments are significantly changing the way we operate and grow," said Bill McCaffrey, President and Chief Executive Officer. "These technologies are enabling MEG to meaningfully reduce its steam-oil ratio, making it possible to reduce capital requirements for steam and water handling and decrease operating costs. It also allows for future expansions on a continuous basis as opposed to project by project, while offering significantly higher returns and reducing the company's greenhouse gas emissions intensity."
In those specific well patterns where eMSAGP has already been deployed, the company is currently seeing a steam-oil ratio of approximately 1.3, with the freed-up steam being diverted into new wells to further increase production.
"Our evolving technologies form the basis of the majority of MEG's future growth," said McCaffrey. "The targeted cost reductions associated with incremental production growth allow us to continue to lower our costs on a per barrel basis, and better position the company to carry out this highly-economic growth going forward."
For the third quarter of 2017, net operating costs were a record-low $6.00 per barrel, compared to $7.42 per barrel in the previous quarter, due to a per barrel decrease in energy operating costs and an increase in per barrel power revenue.
Non-energy operating costs were $4.57 per barrel in the third quarter. The continued decrease in non-energy operating costs compared to the company's guidance is primarily the result of efficiency gains and a continued focus on cost management, resulting in lower operations staffing and materials and services costs.
On a year-to-date basis, non-energy operating costs have decreased 20% compared to the first nine months of 2016. As a result of MEG's continued focus on cost control and efficiency improvements, annual non-energy operating costs for 2017 are now targeted to be in the range of $4.75 - $5.00 per barrel, below the original guidance of $5.75 - $6.75 per barrel and the adjusted $5.00 - $5.50 per barrel guidance provided in the company's second quarter 2017 disclosure.
In the third quarter, MEG continued to benefit from increases in its realized sales price. The average US$WTI price increased 7% in the third quarter of 2017 compared with the same period of 2016. However, the WCS differential narrowed by US$3.56 per barrel, or 26%, due to higher demand for Canadian heavy oil from U.S. Gulf Coast refineries. These factors increased the company's bitumen realization by approximately C$9 per barrel compared to the third quarter of 2016.
Blend sales in the third quarter of 2017 were approximately 6,000 bpd less than production, as these volumes were in transit over the quarter end, destined for the U.S. Gulf Coast. These sales volumes will be recognized in the fourth quarter of 2017.
MEG realized adjusted funds flow from operations of $83 million for the third quarter of 2017 compared to adjusted funds flow from operations of $55 million in the previous quarter. The increase in adjusted funds flow from operations was primarily due to an increase in bitumen realization and a reduction in net operating costs.
Capital Investment and Financial Liquidity
Total cash capital investment during the third quarter of 2017 was $103 million. Primarily as a result of ongoing efficiency improvements, lower construction costs, improved facility design and the optimization of MEG's investment profile, the company has reduced its 2017 capital investment program to $510 million, compared to the original budget of $590 million. Capital investment in 2017 is primarily directed towards the company's eMSAGP growth initiative at Christina Lake Phase 2B, which is proceeding on schedule and under budget.
"MEG's focus on innovation and cost containment is resulting in the company being able to achieve better results with lower investment dollars," said McCaffrey. "We are seeing significant reductions in our capital needs because of the efficiency improvements in our reservoir processes and fundamental changes to our pad and facility designs. As a result, we now anticipate spending $350 million on the implementation of eMSAGP on Phase 2B, which comes to $17,500 per flowing barrel, a 13% reduction from the original estimates of $400 million. This cost reduction contributes to the company's overall objective of generating higher returns from its capital investments."
MEG has entered into a series of hedges designed to protect its capital program against downward oil price movements and mitigate volatility in cash flow.
For the fourth quarter of 2017, MEG has entered into WTI hedges on approximately 50% of the company's forecast blend sales with 26% fixed at US$54.20/bbl and 24% hedged utilizing costless collars that provide it with downside price protection at US$47.90/bbl and upside participation to US$58.60/bbl. The company has also entered into financial hedges on approximately 45% of its WCS differential exposure at a price differential to WTI of US$15.00/bbl and 74% of its condensate exposure through a combination of financial and physical transactions at an average price of 99% of WTI.
MEG is also executing its hedge program for 2018. The company has now entered into WTI hedges on 42,000 bpd of blend sales with 12,500 bpd fixed at US$51.10/bbl and 29,500 bpd hedged utilizing costless collars that provide the company with downside price protection at US$45.45/bbl and upside participation to US$54.60/bbl. MEG has also entered into financial hedges on 29,375 bpd of its WCS differential exposure at a price differential to WTI of US$14.20/bbl and 12,675 bpd of its condensate exposure with physical transactions at an average price of 101% of WTI.
MEG's four-year covenant-lite US$1.4 billion credit facility remains undrawn.
Operational and Financial Highlights
| Nine months ended | 2017 | 2016 | 2015 | ||||||||
| ($ millions, except as indicated) | 2017 | 2016 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | |
| Bitumen production - bbls/d | 77,588 | 81,065 | 83,008 | 72,448 | 77,245 | 81,780 | 83,404 | 83,127 | 76,640 | 83,514 | |
| Bitumen realization - $/bbl | 39.17 | 24.91 | 39.89 | 39.66 | 37.93 | 36.17 | 30.98 | 30.93 | 11.43 | 23.17 | |
| Net operating costs - $/bbl(1) | 7.26 | 7.89 | 6.00 | 7.42 | 8.43 | 8.24 | 7.76 | 7.43 | 8.53 | 8.52 | |
| Non-energy operating costs - $/bbl | 4.66 | 5.83 | 4.57 | 4.23 | 5.20 | 4.99 | 5.32 | 5.81 | 6.45 | 5.66 | |
| Cash operating netback - $/bbl(2) | 24.09 | 10.18 | 26.84 | 22.96 | 22.33 | 21.73 | 16.74 | 16.09 | (3.71) | 9.05 | |
| Adjusted funds flow from (used in) operations(3) | 182 | (102) | 83 | 55 | 43 | 40 | 23 | 7 | (131) | (44) | |
| Per share, diluted(3) | 0.63 | (0.45) | 0.28 | 0.19 | 0.16 | 0.18 | 0.10 | 0.03 | (0.58) | (0.20) | |
| Operating earnings (loss)(3) | (158) | (383) | (43) | (36) | (79) | (72) | (88) | (98) | (197) | (140) | |
| Per share, diluted(3) | (0.55) | (1.70) | (0.14) | (0.12) | (0.29) | (0.32) | (0.39) | (0.43) | (0.88) | (0.62) | |
| Revenue(4) | 1,680 | 1,301 | 546 | 574 | 560 | 566 | 497 | 513 | 290 | 445 | |
| Net earnings (loss)(5) | 190 | (124) | 84 | 104 | 2 | (305) | (109) | (146) | 131 | (297) | |
| Per share, basic | 0.66 | (0.55) | 0.29 | 0.36 | 0.01 | (1.34) | (0.48) | (0.65) | 0.58 | (1.32) | |
| Per share, diluted | 0.66 | (0.55) | 0.28 | 0.35 | 0.01 | (1.34) | (0.48) | (0.65) | 0.58 | (1.32) | |
| Total cash capital investment | 339 | 74 | 103 | 158 | 78 | 63 | 19 | 20 | 35 | 54 | |
| Cash and cash equivalents | 398 | 103 | 398 | 512 | 549 | 156 | 103 | 153 | 125 | 408 | |
| Long-term debt | 4,636 | 4,910 | 4,636 | 4,813 | 4,945 | 5,053 | 4,910 | 4,871 | 4,859 | 5,190 | |
| (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 from (used in) operations, 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 and nine months ended September 30, 2017 and September 30, 2016, the non-GAAP measure of adjusted funds flow from (used in) operations 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 $180.4 million and $345.1 million on the Corporation's U.S. dollar denominated debt and U.S. dollar denominated cash and cash equivalents for the three and nine months ended September 30, 2017, respectively. The net loss for the three and nine months ended, September 30, 2016 includes a net unrealized foreign exchange loss of $38.7 million and a net unrealized foreign exchange gain of $267.8 million, respectively. |
ADVISORY
Basis of Presentation
MEG prepares its financial statements in accordance with International Financial Reporting Standards ("IFRS") and presents financial results in Canadian dollars ($ or C$), which is the corporation's functional currency.
Non-GAAP Measures
Certain financial measures in this news release including: net marketing activity, funds flow from (used in) operations, adjusted funds flow from (used in) operations, 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 From (Used in) Operations and Adjusted Funds Flow From (Used in) Operations
Funds flow from (used in) operations and adjusted funds flow from (used in) operations are non-GAAP measures utilized by the Corporation to analyze operating performance and liquidity. Funds flow from (used in) operations 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 from (used in) operations excludes the net change in non-cash operating working capital and charges not incurred in the normal course of operations, while the IFRS measurement "net cash provided by (used in) operating activities" includes these items. Funds flow from (used in) operations and adjusted funds flow from (used in) operations are not intended to represent net cash provided by (used in) operating activities calculated in accordance with IFRS. Funds flow from (used in) operations and adjusted funds flow from (used in) operations are reconciled to net cash provided by (used in) operating activities in the table below.
| Three months ended September 30 | Nine months ended September 30 | |||||||||
| ($000) | 2017 | 2016 | 2017 | 2016 | ||||||
| Net cash provided by (used in) operating activities | $ | 7,979 | $ | (19,894) | $ | 117,397 | $ | (175,978) | ||
| Net change in non-cash operating working capital items | 51,133 | 45,492 | 28,922 | 76,409 | ||||||
| Funds flow from (used in) operations | 59,112 | 25,598 | 146,319 | (99,569) | ||||||
| Adjustments: | ||||||||||
| Contract cancellation expense | 18,765 | - | 18,765 | - | ||||||
| Net change in other liabilities | - | (4,044) | - | (5,495) | ||||||
| Payments on onerous contracts | 5,089 | 1,049 | 14,691 | 2,395 | ||||||
| Decommissioning expenditures | 386 | 99 | 1,847 | 1,095 | ||||||
| Adjusted funds flow from (used in) operations | $ | 83,352 | $ | 22,702 | $ | 181,622 | $ | (101,574) | ||
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, contract cancellation expense, onerous contracts expense, insurance proceeds 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 September 30 | Nine months ended September 30 | ||||||||
| ($000) | 2017 | 2016 | 2017 | 2016 | |||||
| Net earnings (loss) | $ | 83,885 | $ | (108,632) | $ | 189,755 | $ | (123,968) | |
| Adjustments: | |||||||||
| Unrealized net loss (gain) on foreign exchange(1) | (180,448) | 38,729 | (345,116) | (267,763) | |||||
| Unrealized loss (gain) on derivative financial liabilities(2) | (3,490) | (11,367) | (7,346) | (5,362) | |||||
| Unrealized loss (gain) on commodity risk management(3) | 57,470 | (32,207) | (19,353) | (11,736) | |||||
| Contract cancellation expense(4) | 18,765 | - | 18,765 | - | |||||
| Onerous contracts expense(5) | (27) | 18,057 | 5,681 | 31,483 | |||||
| Insurance proceeds | (183) | - | (183) | - | |||||
| Deferred tax expense (recovery) relating to these adjustments | (18,543) | 7,491 | 218 | (5,763) | |||||
| Operating earnings (loss) | $ | (42,571) | $ | (87,929) | $ | (157,579) | $ | (383,109) | |
| (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 third quarter of 2017, the Corporation recognized a contract cancellation expense of $18.8 million relating to the termination of a long-term marketing transportation contract that had not yet commenced. |
| (5) | Onerous contracts expense primarily includes changes in estimated future cash flow sublease recoveries related to the onerous office lease provision for the Corporation's office building lease contracts. |
Forward-Looking Information
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 full version of MEG's Third Quarter 2017 Report to Shareholders, including unaudited financial statements, is available at www.megenergy.com/investors and at www.sedar.com.
A conference call will be held to review the operating and financial results at 8:30 a.m. Mountain Time (10:30 a.m. Eastern Time) on Thursday, October 26, 2017. The North American toll-free conference call number is 1-888-231-8191. The international conference call number is 647-427-7450.
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:
Investors
Helen Kelly
Director, Investor Relations
403-767-6206
helen.kelly@megenergy.com
Media
Davis Sheremata
Senior Advisor, External Communications
587-233-8311
davis.sheremata@megenergy.com
SOURCE MEG Energy Corp.