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 guidance

Print 🖨

Strong 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 /CNW/ – 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 September 30		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.