MEG Energy reports solid second quarter 2017 results supported by record low per barrel non-energy operating costs, while successfully completing major turnaround activities

Company anticipates production increases from highly economic eMSAGP growth to commence in third quarter, driving a reduction of $4-$5 per barrel in overall cash costs when fully ramped-up in early 2019

All financial figures in Canadian dollars ($ or C$) unless otherwise noted

CALGARY, July 27, 2017 /CNW/ - MEG Energy Corp. (TSX:MEG) today reported second quarter 2017 operating and financial results. Highlights include:

• Quarterly production volumes of 72,448 barrels per day (bpd), while completing planned maintenance activities;
   
  
• Net operating costs of $7.42 per barrel supported by unadjusted record low quarterly non-energy operating costs of $4.23 per barrel;
  
  
• Total cash capital investment of $158 million, primarily directed towards the eMSAGP growth initiative at Christina Lake Phase 2B which is proceeding on schedule and ahead of budget;
   
  
• Strong liquidity contributing to cash and cash equivalents of $512 million as of June 30, 2017. The company's US$1.4 billion, four-year covenant-lite revolving credit facility remains undrawn; and,
  
  
• A reduction in per barrel non-energy operating cost guidance from a range of $5.75 - $6.75 per barrel to $5.00 - $5.50 per barrel to reflect ongoing efficiency gains and a continued focus on cost management, while re-affirming annual production guidance of 80,000 to 82,000 bpd, year-end exit production guidance of 86,000 to 89,000 bpd, and 2017 capital budget guidance of $590 million.

MEG's second quarter 2017 production averaged 72,448 bpd, compared to 77,245 bpd for the first quarter of the year. Production for the second quarter was at the upper end of the forecast provided by the company in its first quarter 2017 disclosure which took into account 37 days of planned maintenance. The company remains on track to meet its 2017 average production guidance of 80,000 to 82,000 bpd.

"We had three corporate objectives for 2017 as we work to accomplish our long-term vision of continuing to strengthen our financial position while economically growing production. These objectives were completion of the comprehensive refinancing of the company's balance sheet, the active pursuit of our highly economic growth plan, and our continued focus on the further reduction of our corporate cash costs," said Bill McCaffrey, President and Chief Executive Officer. "With the successful refinancing of MEG's balance sheet in January 2017 and our annual turnaround activities behind us, our focus is now on the implementation of our highly economic Phase 2B eMSAGP growth project. Our proprietary reservoir technology which we are deploying has done more than just improve the efficiencies of our business, it has fundamentally changed the way we grow, allowing us to further lower our breakeven costs."

To date, eMSAGP has been deployed at MEG's Phase 1 and 2 wells, which represent about 25% of the company's production, and has been very successful. The Phase 2B eMSAGP project now being undertaken involves the implementation of MEG's proprietary reservoir enhancement technology to the remaining 75% of the company's production not currently under eMSAGP production. The implementation of eMSAGP has significantly improved reservoir efficiency and allowed for redeployment of steam, enabling the company to place additional wells into production. Since employing eMSAGP, the company's overall steam-oil ratio (SOR) has been reduced to 2.3, and on an eMSAGP-only basis is averaging an industry-leading range of 1.0 to 1.25.

"Given our low sustaining capital requirements and strong cash position, we remain confident that we are on track to complete the highly economic Phase 2B eMSAGP project while meaningfully lowering our corporate cash costs," said Bill. "We expect the current growth phase of 20,000 bpd production from eMSAGP to reduce our cash costs by approximately $4 to $5 per barrel when fully on stream in early 2019, meaningfully improving the ongoing sustainability of our business."

For the second quarter of 2017, net operating costs were $7.42 per barrel, compared to $8.43 per barrel in the previous quarter. Non-energy operating costs were $4.23 per barrel compared to $5.20 per barrel for the first quarter of this year. These per barrel numbers are inclusive of a $0.66 per barrel, or $4.5 million, property tax reduction related to a one-time municipal reassessment of MEG's Christina Lake facility. MEG's second quarter non-energy operating per barrel costs were a record low even excluding the reassessment, reflecting the positive results from operational efficiency gains and a continued focus on cost management.

As a result of ongoing operating cost management, including lower operations staffing and associated camp and site services costs, and continued efficiency gains over the first half of 2017, annual non-energy operating costs for 2017 are now targeted to be in the range of $5.00 - $5.50 per barrel, approximately 16% lower than the original guidance of $5.75 - $6.75 per barrel at its mid-point.

MEG realized adjusted funds flow from operations of $55 million for the second quarter of 2017 compared to adjusted funds flow from operations of $7 million for the same period in 2016. The increase in adjusted funds flow from operations was primarily due to an increase in bitumen realization driven by the increase in average crude oil benchmark pricing and narrower differentials. The company recorded a second quarter 2017 operating loss of $36 million compared to an operating loss of $79 million for the first quarter of this year.

Capital Investment and Financial Liquidity

Total cash capital investment during the second quarter of 2017 was $158 million, compared to $78 million for the first quarter of 2017. Capital investment in 2017 is primarily directed towards the company's eMSAGP production growth initiative at Christina Lake Phase 2B, which is proceeding on schedule and ahead of budget. The company expects production to increase in the third quarter, supporting year-end exit production guidance of 86,000 to 89,000 bpd.

In the second quarter of 2017, costs from the major planned turnaround of $37 million were incurred and will be depreciated on a straight-line basis over the period to the next major planned turnaround.

MEG's 2017 capital budget guidance remains at $590 million, of which approximately 55% is directed towards the Phase 2B eMSAGP growth initiative, 35% towards sustaining and turnaround costs, and the remainder towards supporting marketing, corporate and other initiatives. The company expects to fund the remainder of its 2017 capital program with a portion of the $512 million of cash on hand at June 30, 2017.

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. MEG has hedges in place for approximately half of its blend sales at an average floor price of US$50 WTI per barrel and for approximately 40% of its condensate purchases for the rest of 2017. MEG's four-year covenant-lite US$1.4 billion credit facility also remains undrawn.

The company is taking steps to address its financial leverage.  In January 2017, MEG successfully completed a refinancing which pushed the first maturity of any of the Corporation's outstanding long-term debt obligations to 2023. The ongoing implementation of the eMSAGP growth project will grow production and associated cash flow while further de-risking the business through a reduction in its overall cash costs of $4 to $5 per barrel. In addition, taking into account the company's debt maturity profile and the ongoing commodity price environment, MEG continues to consider its options to reduce its overall amount of debt.

Operational and Financial Highlights

		Six months ended June 30		2017		2016				2015
($ millions, except as indicated)		2017	2016	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Bitumen production - bbls/d		74,833	79,883	72,448	77,245	81,780	83,404	83,127	76,640	83,514	82,768
Bitumen realization - $/bbl		38.80	21.56	39.66	37.93	36.17	30.98	30.93	11.43	23.17	31.03
Net operating costs - $/bbl^(1)		7.92	7.97	7.42	8.43	8.24	7.76	7.43	8.53	8.52	9.10
Non-energy operating costs - $/bbl		4.71	6.12	4.23	5.20	4.99	5.32	5.81	6.45	5.66	5.98
Cash operating netback - $/bbl^(2)		22.66	6.57	22.96	22.33	21.73	16.74	16.09	(3.71)	9.05	16.41
Adjusted funds flow from (used in)
	operations^(3)	98	(124)	55	43	40	23	7	(131)	(44)	24
	Per share, diluted^(3)	0.35	(0.55)	0.19	0.16	0.18	0.10	0.03	(0.58)	(0.20)	0.11
Operating earnings (loss)^(3)		(115)	(295)	(36)	(79)	(72)	(88)	(98)	(197)	(140)	(87)
	Per share, diluted^(3)	(0.40)	(1.31)	(0.12)	(0.29)	(0.32)	(0.39)	(0.43)	(0.88)	(0.62)	(0.39)
Revenue^(4)		1,134	804	574	560	566	497	513	290	445	460
Net earnings (loss)^(5)		106	(15)	104	2	(305)	(109)	(146)	131	(297)	(428)
	Per share, basic	0.37	(0.07)	0.36	0.01	(1.34)	(0.48)	(0.65)	0.58	(1.32)	(1.90)
	Per share, diluted	0.37	(0.07)	0.35	0.01	(1.34)	(0.48)	(0.65)	0.58	(1.32)	(1.90)
Total cash capital investment^(6)		236	55	158	78	63	19	20	35	54	32
Cash and cash equivalents		512	153	512	549	156	103	153	125	408	351
Long-term debt		4,813	4,871	4,813	4,945	5,053	4,910	4,871	4,859	5,190	5,024

(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 six months ended June 30, 2017 and June 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 $128.0 million and $164.7 million on the Corporation's U.S. dollar denominated debt and U.S. dollar denominated cash and cash equivalents for the three and six months ended June 30, 2017, respectively. The net loss for the three and six months ended, June 30, 2016 includes a net unrealized foreign exchange loss of $13.8 million and a net unrealized foreign exchange gain of $306.5 million, respectively.
(6)	Defined as total capital investment excluding dispositions, capitalized interest, capitalized cash-settled stock-based compensation and non-cash items.

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, net change in other liabilities, payments on onerous contracts, and decommissioning expenditures 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 June 30				Six months ended June 30
($000)			2017		2016		2017		2016
Net cash provided by (used in) operating activities			$	63,612	$	64,587	$	109,418	$	(156,084)
		Net change in non-cash operating working capital items	(14,024)		(56,923)		(22,211)		30,917
Funds flow from (used in) operations			49,588		7,664		87,207		(125,167)
	Adjustments:
		Net change in other liabilities	-		(1,451)		-		(1,451)
		Payments on onerous contracts	5,468		717		9,602		1,346
		Decommissioning expenditures	39		34		1,461		996
Adjusted funds flow from (used in) operations			$	55,095	$	6,964	$	98,270	$	(124,276)

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 June 30				Six months ended June 30
($000)			2017		2016		2017		2016
Net earnings (loss)			$	104,282	$	(146,165)	$	105,870	$	(15,336)
Adjustments:
	Unrealized net loss (gain) on foreign exchange^(1)		(127,961)		13,789		(164,668)		(306,492)
	Unrealized loss (gain) on derivative financial liabilities^(2)		(1,615)		516		(3,856)		6,005
	Unrealized loss (gain) on commodity risk management^(3)		(17,224)		37,434		(76,823)		20,471
	Onerous contracts expense^(4)		3,333		9,055		5,708		13,426
	Deferred tax expense (recovery) relating to these
		adjustments	3,529		(12,523)		18,761		(13,254)
Operating earnings (loss)			$	(35,656)	$	(97,894)	$	(115,008)	$	(295,180)

(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)	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 Second Quarter 2017 Report to Shareholders, including unaudited financial statements, is available at www.megenergy.com/investors and at www.sedar.com.

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
[email protected]

Media
Davis Sheremata
Senior Advisor, External Communications
587-233-8311
[email protected]

SOURCE MEG Energy Corp.

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