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MEG Energy Corp.

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MEG Energy reports second quarter 2018 results, achieving new production record of 98,000 bpd in July with Phase 2B eMSAGP essentially complete
MEG Energy reports second quarter 2018 results, achieving new production record of 98,000 bpd in July with Phase 2B eMSAGP essentially complete

Canada NewsWire

Increases 2018 production guidance and lowers non-energy operating cost per barrel guidance; remains on-track to reach 113,000 bpd in 2020 

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

CALGARY, Aug. 2, 2018 /CNW/ -  MEG Energy Corp. (TSX:MEG) today reported second quarter 2018 operating and financial results. Highlights include:

  • Quarterly production volumes of 71,325 barrels per day, while completing planned maintenance activities. With strong first half production, annual production guidance has been revised higher to 87,000 to 90,000 barrels per day (bpd), from 85,000 to 88,000 bpd;

  • Record low per barrel net operating costs of $5.64, including non-energy operating costs of $5.47, which were impacted by lower sales volumes in the quarter. Annual non-energy operating cost guidance has been reduced by 5% to $4.50 to $5.00 per barrel, from $4.75 to $5.25 per barrel to reflect strong cost performance to-date;

  • Adjusted funds flow from operations of $18 million, impacted by lower sales volumes due to turnaround activities, realized losses on commodity derivatives, and mark-to-market, unrealized cash-settled stock-based compensation; 

  • Total cash capital investment of $183 million in the quarter, primarily directed to planned turnaround activities and advancing key growth projects. The 2018 capital plan has been revised to $670 million from the previously announced $700 million, to reflect improved capital cost efficiencies and strong operational results on the Phase 2B eMSAGP implementation; and 

  • Cash and cash equivalents of $564 million, MEG's covenant-lite US$1.4 billion facility remains undrawn.

During the second quarter of 2018, MEG completed a large-scale turnaround at Christina Lake Phase 2B, lasting 33 days. Production in the quarter averaged 71,325 bpd, which was in-line with the second quarter of 2017, and 23% lower than the first quarter of 2018. The lower quarter-over-quarter production is the result of planned maintenance activities.

Subsequent to the quarter, MEG completed essentially all investment required for the application of eMSAGP to the Phase 2B producing assets. This led to strong production at Christina Lake during the month of July, averaging over 98,000 bpd. The Company has increased its annual production guidance to 87,000 to 90,000 bpd, and year-end exit production is anticipated to average just over 100,000 bpd.

"MEG executed the largest turnaround in its history during the second quarter. The value of our diligent approach to regular plant maintenance was demonstrated as the turnaround confirmed the overall integrity of the plant," said Harvey Doerr, Interim President and CEO. "The turnaround allowed us to tie-in and modify a number of pieces of equipment, which enable us to reliably run at higher production levels. We saw record production day rates in excess of 100,000 bpd for several days in July as new Phase 2B eMSAGP wells were brought on-stream."  

MEG's blend sales realization averaged $62.32 per barrel in the second quarter of 2018, 22% higher than the first quarter of 2018. The higher blend sales realization was the result of stronger benchmark crude oil prices and tighter differentials. The Company sold approximately 32,000 bpd of blend into the U.S. Gulf Coast during the second quarter, reflecting apportionment of approximately 46% on the Enbridge Mainline system. The majority of the Company's remaining barrels were sold in Edmonton. MEG's bitumen realization averaged $47.20 per barrel in the second quarter of 2018, 34% higher than the first quarter of 2018.

"MEG's marketing strategy has been focused on diversifying our markets, intended to minimize risk and maximize the value received for our barrels. Our rail loading and strategic storage facilities have helped to mitigate the impact of apportionment, and together with our commitment on the Flanagan South and Seaway pipelines, support better price realizations," said Doerr. "However, pipeline apportionment is expected to continue to impact the industry in the short term. We continue to be supportive of Enbridge's initiative to address the nomination methodology on the Mainline system, which should have a positive impact. In the medium term, completion of the Line 3 expansion will further enhance MEG's ability to take advantage of its commitment on the Flanagan South/Seaway, which doubles to 100,000 bpd in mid-2020."

Transportation costs for the second quarter of 2018 were $8.28 per barrel, 20% higher than the second quarter of 2017, and 38% higher than the first quarter of 2018. The higher transportation expense reflects the first full quarter impact of the recent sale of the Company's 50% share in the Access Pipeline and 100% of Stonefell Terminal, as well as lower sales volumes due to the plant turnaround.

Capital and Operational Update

Total cash capital investment in the quarter was $183 million, with funds directed towards planned turnaround activities, implementation of Phase 2B eMSAGP, advancement of the eMVAPEX pilot, and continued work on the Phase 2B brownfield expansion. During the quarter, MEG invested $22 million on the Phase 2B eMSAGP implementation. All spending on the project was completed subsequent to the quarter, with total costs coming in at $340 million. The final costs were lower than both the original capital estimate of $400 million and the revised estimate of $350 million. The 2018 capital program has been reduced to $670 million from the previously announced $700 million to reflect ongoing capital cost efficiencies.

MEG's hedging philosophy over the last two years has been focused on protecting its capital program. With current cash reserves, higher commodity prices and lower anticipated levels of capital spend in 2019, the Company expects to hedge a substantially lower percentage of its barrels going forward.

As a result of a review of the Company's marketing assets, MEG has engaged TD Securities Inc. to review strategic alternatives with respect to its proprietary HI-Q® partial upgrading technology. This technology has the potential to eliminate the use of diluent for bitumen transport. MEG is seeking a third-party transaction, which will take HI-Q® to commerciality while retaining access to the technology and will not require the Company to invest additional capital.

Net operating costs for the second quarter of 2018 averaged $5.64 per barrel, which is 24% and 6% lower than the second quarter of 2017 and first quarter of 2018, respectively. The strong per barrel net operating costs were achieved despite lower bitumen sales volumes in the quarter. The ongoing reduction in net operating costs reflects efficiency gains and continued focus on cost management. Annual non-energy operating cost guidance has been reduced to $4.50 to $5.00 per barrel, from $4.75 to $5.25 per barrel, to account for strong cost performance year-to-date.

Adjusted Funds Flow

MEG realized adjusted funds flow from operations of $18 million for the second quarter of 2018, compared to $55 million in the second quarter of 2017, and $83 million in the first quarter of 2018. Higher crude oil prices in the quarter were more than offset by lower production volumes, a realized loss on commodity derivatives and mark-to-market unrealized cash-settled stock-based compensation expense. Realized losses on commodity derivatives totalled $89 million, as crude oil benchmark prices exceeded the Company's crude oil contract prices.

Mark-to-market on the unrealized portion of cash-settled stock-based compensation reduced second quarter adjusted funds flow by $14 million, or $0.05 per share. MEG's stock price increased approximately 140% from March 31, 2018 to June 30, 2018, resulting in an increase in the fair value of the cash-settled units outstanding. MEG adopted cash-settled stock-based compensation for a portion of its long-term incentive (LTI) program for 2016 and 2017, which vest over a three-year period. The Company's LTI plans are designed to align compensation to corporate performance and are linked to the Company's stock price performance.  

Outlook

The search committee of the Board has identified, interviewed and subsequently shortlisted a small number of qualified candidates for the role of permanent CEO. The Board expects to make a final decision in the third quarter of 2018.

"With 100,000 bpd in reach, MEG remains firmly on-track to deliver on our Vision 20/20. As the turnaround is now behind us, and spending on Phase 2B eMSAGP is essentially complete, capital in the second half of the year will be primarily focused on the Phase 2B brownfield expansion. Given our strong cash balance of $564 million and significantly higher cash flow anticipated in the second half of 2018, we are well-positioned to internally fund our capital plans to 2020," said Doerr. "While we have realized significant improvements across our business, we continue to look for ways to further advance our technology, improve our highly competitive overall cost position and maximize the revenue we receive for our barrels."

Operational and Financial Highlights







Six months ended

June 30

2018

2017

2016

($ millions, except as indicated)

2018

2017

Q2

Q1

Q4

Q3

Q2

Q1

Q4

Q3

Bitumen production - bbls/d

82,205

74,883

71,325

93,207

90,228

83,008

72,448

77,245

81,780

83,404












Bitumen realization - $/bbl

40.67

38.80

47.20

35.31

48.30

39.89

39.66

37.93

36.17

30.98












Net operating costs - $/bbl(1)

5.82

7.92

5.64

5.98

5.86

6.00

7.42

8.43

8.24

7.76












Non-energy operating costs - $/bbl

4.96

4.71

5.47

4.55

4.53

4.57

4.23

5.20

4.99

5.32












Cash operating netback - $/bbl(2)

19.43

22.66

18.53

20.16

33.83

26.84

22.96

22.33

21.73

16.74












Adjusted funds flow from operations(3)

102

98

18

83

192

83

55

43

40

23


 Per share, diluted(3)

0.34

0.35

0.06

0.28

0.65

0.28

0.19

0.16

0.18

0.10

Operating earnings (loss)(3)

(88)

(115)

(70)

(18)

44

(43)

(36)

(79)

(72)

(88)


Per share, diluted(3)

(0.30)

(0.40)

(0.24)

(0.06)

0.15

(0.14)

(0.12)

(0.29)

(0.32)

(0.39)

Revenue(4)

1,410

1,143

689

721

755

576

584

560

566

497

Net earnings (loss)

(38)

106

(179)

141

(1)

84

104

2

(305)

(109)


Per share, basic

(0.13)

0.37

(0.61)

0.48

(0.00)

0.29

0.36

0.01

(1.34)

(0.48)


Per share, diluted

(0.13)

0.37

(0.61)

0.47

(0.00)

0.28

0.35

0.01

(1.34)

(0.48)













Total cash capital investment

330

236

183

148

163

103

158

78

63

19












Cash and cash equivalents

564

512

564

675

464

398

512

549

156

103

Long-term debt

3,607

4,813

3,607

3,543

4,637

4,636

4,813

4,945

5,053

4,910



(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, blend purchases, 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. 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 consolidated statement of earnings and comprehensive income. Effective January 1, 2018, petroleum revenues are presented on a gross basis as they represent separate performance obligations, as discussed in the "NEW ACCOUNTING STANDARDS" section of MEG's "Management Discussion and Analysis" dated August 1, 2018. Prior quarters have been revised as applicable to reflect the new presentation.

 

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, realized gain on foreign exchange derivatives not considered part of ordinary continuing operating results, 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)

2018

2017

2018

2017

Net cash provided by (used in) operating activities

$

65,243

$

63,612

$

183,269

$

109,418


Net change in non-cash operating working capital items

(51,836)

(14,024)

(59,972)

(22,211)

Funds flow from (used in) operations

13,407

49,588

123,297

87,207

   Adjustments:






Realized gain on foreign exchange derivatives(1)

-

-

(35,362)

-


Payments on onerous contracts

4,236

5,468

10,244

9,602


Decommissioning expenditures

750

39

3,371

1,461

Adjusted funds flow from (used in) operations

$

18,393

$

55,095

$

101,550

$

98,270



(1)    

A gain related to the settlement of forward currency contracts to manage the foreign exchange risk on those Canadian dollar denominated proceeds related to the sale of assets designated for U.S. dollar denominated long-term debt repayment.

 

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, realized gains and losses on foreign exchange derivatives, gain on asset dispositions, 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. 





Three months ended June 30

Six months ended June 30

($000)

2018

2017

2018

2017

Net earnings (loss)

$

(178,570)

$

104,282

$

(37,997)

$

105,870

Adjustments:






Unrealized loss (gain) on foreign exchange(1)

62,377

(127,961)

203,675

(164,668)


Unrealized loss (gain) on derivative financial liabilities(2)

(110)

(1,615)

2,866

(3,856)


Unrealized loss (gain) on commodity risk management(3)

61,288

(17,224)

119,320

(76,823)


Realized foreign exchange loss (gain) on foreign exchange derivatives(4)

-

-

(35,362)

-


Gain on asset dispositions(5)

-

-

(318,398)

-


Onerous contracts expense

145

3,333

789

5,708


Deferred tax expense (recovery) relating to these adjustments

(15,304)

3,529

(23,082)

18,761

Operating earnings (loss)

$

(70,174)

$

(35,656)

$

(88,189)

$

(115,008)



(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)

A gain related to the settlement of forward currency contracts to manage the foreign exchange risk on those Canadian dollar denominated proceeds related to the sale of assets designated for U.S. dollar denominated long-term debt repayment.



(5)

A gain related to the sale of the Corporation's 50% interest in the Access Pipeline.

 

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, the securing of adequate supplies and access to markets and transportation infrastructure and the commitments and risks therein; 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 company's website at www.megenergy.com/investors and through the SEDAR website 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 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 a.m. Mountain Time (10 a.m. Eastern Time) on Thursday, August 2, 2018. The North American toll-free conference call number is 1-888-390-0546. The international conference call number is 587-880-2171.

A recording of the call will be available by 12 noon Mountain Time (2 p.m. Eastern Time) on August 2, 2018 on the Company's website at www.megenergy.com/investors/presentations-and-events. A phone recording will also be available until 9:59 p.m. Mountain Time (11:59 p.m. Eastern Time) on September 1, 2018. To access the phone recording, dial toll-free (+1) 888-390-0541 or local 416-764-8677 and enter the pass code 242663.

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
Megan Hjulfors
Senior Advisor, Investor Relations
403-767-6211
megan.hjulfors@megenergy.com

SOURCE MEG Energy Corp.

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