MEG Energy reports record operational results for 2018

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

CALGARY, March 7, 2019 /CNW/ - MEG Energy Corp. (TSX:MEG, "MEG") today reported full-year 2018 results.

"While 2018 saw strong operational successes, the challenging commodity price environment, particularly during the fourth quarter, hindered bitumen realizations and adjusted funds flow for the company.  Notwithstanding commodity price volatility and significant organizational changes, MEG's solid foundation remains intact. Our world class 100,000 barrels per day operations tied to an exceptional resource base, our dedicated workforce, and our well-structured balance sheet, enables us to move forward with a renewed business focus," says Derek Evans, President and Chief Executive Officer. "In the current commodity price environment, financial discipline and balance sheet protection takes precedence over production growth.  MEG's 2019 base capital investment plan of $200 million signals our commitment to living within our means, while retaining the flexibility to pursue debt reduction and advance profitable development in line with market conditions to realize long-term sustainable returns going forward. Based on current strip pricing, we expect our Net Debt to LTM EBITDA to come into the range of 3.50x to 3.75x by the end of 2019."

Operational and financial highlights in 2018 include:

  • The appointment of Derek Evans to Chief Executive Officer in August 2018;

  • Closing of the sale of MEG's 50% interest in the Access Pipeline and its 100% interest in the Stonefell Terminal for cash proceeds of $1.52 billion and other consideration of $90 million, and the repayment of $1.2 billion of the Corporation's senior secured term loan in the first quarter of 2018;

  • Record bitumen production volumes of 87,731 barrels per day (bbls/d) and a record low steam-oil-ratio (SOR) of 2.19, compared to 2.30 in 2017;

  • Record low per barrel net operating costs of $5.09 per barrel, including low non-energy operating costs of $4.62 per barrel, compared to guidance of $4.50 to $5.00 per barrel;

  • Total cash capital investment of $619 million, $51 million below the revised guidance, primarily focused on advancing the Phase 2B brownfield expansion and the successful application of MEG's proprietary reservoir enhancement technology eMSAGP on Phase 2B, increasing overall production capacity from 80,000 to 100,000 bbls/d;

  • Adjusted funds flow of $180 million or $0.60 per share, impacted by the significant widening of the WTI:WCS differential during the fourth quarter; and

  • Year-end cash and cash equivalents of $318 million, which along with expected adjusted funds flow, will more than enable MEG to fully fund its 2019 capital program.

"In response to the challenging, short-term volatility in commodity prices during the fourth quarter, the company preserved its liquidity by restricting the number of barrels it sold into an unprofitable market environment. We accomplished this by moving forward a portion of our 2019 turnaround into November, voluntarily reducing production during the month of December, and ramping up the use of rail to sell our product into higher-priced markets," says Derek Evans. "Since January, in conjunction with the provincially mandated curtailments for the industry and the increase in overall crude by rail exports, commodity prices have improved significantly, and our barrels have returned to profitability. Our objective of generating free cash flow in 2019 remains intact."  

Bitumen production in the fourth quarter of 2018 averaged 87,582 bbls/d as a result of the Corporation's direct response to mitigate the effects of the significant widening of the WTI:WCS differential by voluntarily curtailing production. 2018 Bitumen production averaged 87,731 bbls/d compared to 80,774 bbls/d in 2017. The increase in average production volumes for the year ended December 31, 2018 was primarily due to the efficiency gains achieved from eMSAGP at the Christina Lake Project.

Net operating costs for the fourth quarter of 2018 averaged $4.55 per barrel, supported by near-record low non-energy operating costs of $4.25 per barrel. The Corporation realized record low net operating costs of $5.09 per barrel in 2018, 26% below the record of $6.84 per barrel achieved in the prior year. The decrease in net operating costs was primarily the result of a per barrel decrease in energy operating costs and an increase in per barrel power revenue. Non-energy operating costs averaged $4.62 per barrel for each of the years ended December 31, 2018, and 2017.

Pricing and Market Access

The fourth quarter of 2018 was a challenging period for Canadian oil producers due to a rapid decline in Canadian heavy crude oil prices. MEG's blend sales price of $36.59 per barrel in the fourth quarter of 2018 was negatively impacted by historically wide WTI:WCS differentials of US$39.43 per barrel. In comparison, MEG's blend sales price was $57.01 per barrel in the fourth quarter of 2017 with a WTI:WCS differential of US$12.26 per barrel. The Corporation partially mitigated the wider differentials during the fourth quarter of 2018 by selling 33% of blend volumes into the higher-priced U.S. Gulf Coast market via the Flanagan South/Seaway pipelines and rail. On an annual basis, in contrast to the 27% increase in WTI benchmark price,  MEG's blend sales price increased by 4% to average $53.26 per barrel in 2018 compared to $51.20 per barrel in 2017 due to the widening WTI:WCS differential.

MEG's bitumen realization during the fourth quarter averaged $13.90 per barrel, as a result of the significant widening of the WTI:WCS differential negatively impacting both the blend sales price and the cost recovered on the Corporation's diluent purchases. The increase in average condensate benchmark prices and the timing of inventory purchases negatively impacted diluent expense during the fourth quarter. Bitumen realization averaged $36.25 per barrel in 2018, compared to $41.89 per barrel in 2017. The Corporation's cost of diluent averaged $89.28 per barrel in the fourth quarter and $91.60 per barrel in 2018, compared to $72.32 per barrel of diluent in 2017, primarily due to an increase in average condensate benchmark pricing.

During the fourth quarter of 2018 MEG doubled its rail volumes from the prior quarter to 14,700 bbls/d, 56% of which were delivered to the U.S. Gulf Coast. The Corporation estimates rail volumes to average 20,000 bbls/d in the first quarter, increasing to 30,000 bbls/d by the third quarter of 2019. As a mechanism to clear barrels during periods of high pipeline apportionment and reduce exposure to the post-apportionment market, the use of rail enables MEG to maximize the price received on its barrels until additional egress capacity from Western Canada is secured.

Transportation costs averaged $10.28 per barrel during the fourth quarter of 2018, compared to $8.42 per barrel and $6.89 per barrel for full-year 2018 and 2017 respectively. The increase in costs on a per barrel basis is primarily the result of incremental costs associated with the Access Transportation Services Agreement that was put in place after the sale of MEG's 50% interest in the pipeline and its 100% interest in the Stonefell Terminal on March 22, 2018, as well as additional costs associated with increased volumes transported by rail to the U.S Gulf Coast.

"The production curtailments put in place by the Alberta government since January have helped to strengthen the price we receive for our products. With nearly one-third of our blend sales exposed to the higher-price Gulf Coast market in 2019, we anticipate our blend sales realization to be above the WCS benchmark for the full year," says Evans. "By mid-2020, we expect to double the number of barrels we will sell into the U.S. Gulf Coast as our commitment on Flanagan South/Seaway increases from 50,000 to 100,000 bbls/d."

Capital Investment

Total cash capital investment in 2018 totaled $619 million, compared to $503 million in 2017 and the previously revised guidance of $670 million announced in August 2018. Capital investment in 2018 was primarily directed towards completing the rollout of eMSAGP on Christina Lake Phase 2B, advancement of the Corporation's Phase 2B Brownfield expansion and sustaining and maintenance activities.

Adjusted Funds Flow and Net Earnings

The Corporation realized a cash operating netback of $5.73 per barrel in fourth quarter of 2018 as a direct result of the WTI:WCS differential which negatively impacted bitumen realizations, partially offset by a realized gain on commodity risk management contracts of $6.81 per barrel. Cash operating netback for 2018 averaged $17.17 per barrel compared to $27.00 per barrel for 2017, impacted by similar factors.

Adjusted funds flow was impacted by the same primary factors as cash operating netback, resulting in realized negative adjusted funds flow of $38 million, or $(0.13) per share in the fourth quarter of 2018. Adjusted funds flow for the full-year 2018 was $180 million, or $0.60 per share, compared to $374 million for 2017. The decrease was primarily the result of the significant widening of the WTI:WCS differential, particularly during the fourth quarter of 2018, which resulted in a decrease in bitumen realization year-over-year, combined with realized losses on commodity risk management contracts during 2018.

The Corporation recognized a net loss of $199 million in the fourth quarter of 2018, which in addition to the impact of depressed prices, reflects a net foreign exchange loss of $198 million, partially offset by a gain on commodity risk management contracts of $228 million. The Corporation recognized a net loss of $119 million for the year ended December 31, 2018 compared to net earnings of $166 million for the year ended December 31, 2017. The net loss in 2018 included a net foreign exchange loss of $311 million, offset by a gain on commodity risk management contracts of $23 million and a gain on asset dispositions of $325 million, primarily related to the sale of the Corporation's 50% interest in the Access Pipeline.

Outlook

Announced in January, MEG's 2019 capital investment plan includes a base capital budget of $200 million, designed to sustain production capability at 100,000 bbls/d and advance growth projects beyond 2019.  While MEG has the ability to average 100,000 bbls/d of production, the Corporation's 2019 production guidance of 90,000 to 92,000 bbls/d reflects the impact of the Alberta Government's mandated production curtailment, with the assumption that it eases throughout the year. Subject to market conditions, the Corporation has the option to layer in discretionary capital spend of $75 million in 2H19 to support highly economic production growth to 113,000 bbls/d by early 2021.

General and administrative (G&A) expense averaged $2.58 per barrel in 2018, a 12% decrease from $2.94 per barrel in 2017. To align with lower levels of capital spending and to further optimize operational efficiencies, the Corporation made the difficult decision to reduce its staffing levels in February. Based on the current production guidance, MEG anticipates 2019 G&A costs of $1.95 to $2.05 per barrel.  

Board Renewal Update

MEG's Board renewal process is well underway. Korn Ferry has been engaged and is actively searching for three new board members with the necessary skillsets and experience, that would stand for election at the Corporation's upcoming annual general meeting in June 2019.

Unsuccessful Take-Over Offer from Husky

On October 2, 2018, Husky Energy Inc. made an unsolicited offer directly to MEG shareholders to acquire all of the issued and outstanding common shares of the Corporation.  At expiry on January 16, 2019, the offer did not meet minimum tender conditions and Husky chose not to extend its offer. 

Conference Call

A conference call will be held to review the Corporation's full-year 2018 operating and financial results at 6:30 a.m. Mountain Time (8:30 a.m. Eastern Time) on Friday, March 8, 2019. The North American toll-free conference call number is 1-888-390-0546. The international conference call number is 1-587-880-2171.

A recording of the call will be available by 12 noon Mountain Time (2 p.m. Eastern Time) on March 8, 2019 on the Company's website at www.megenergy.com/investors/presentations-and-events.

Operational and Financial Highlights






Year ended
December 31

2018

2017

($ millions, except as indicated)

2018

2017

Q4

Q3

Q2

Q1

Q4

Q3

Q2

Q1

Bitumen production - bbls/d

87,731

80,774

87,582

98,751

71,325

93,207

90,228

83,008

72,448

77,245












Bitumen realization - $/bbl

36.25

41.89

13.90

49.58

47.20

35.31

48.30

39.89

39.66

37.93












Net operating costs - $/bbl(1)

5.09

6.84

4.55

4.34

5.64

5.98

5.86

6.00

7.42

8.43












Non-energy operating costs - $/bbl

4.62

4.62

4.25

4.38

5.47

4.55

4.53

4.57

4.23

5.20












Cash operating netback - $/bbl(2)

17.17

27.00

5.73

23.96

18.53

20.16

33.83

26.84

22.96

22.33












Adjusted funds flow(3)

180

374

(38)

116

18

83

192

83

55

43

Per share, diluted(3)

0.60

1.29

(0.13)

0.39

0.06

0.28

0.65

0.28

0.19

0.16

Operating earnings (loss)(3)

(225)

(114)

(118)

(19)

(70)

(18)

44

(43)

(36)

(79)

Per share, diluted(3)

(0.76)

(0.39)

(0.40)

(0.06)

(0.24)

(0.06)

0.15

(0.14)

(0.12)

(0.29)

Revenue(4)

2,733

2,474

520

803

689

721

755

576

584

560

Net earnings (loss)

(119)

166

(199)

118

(179)

141

(24)

84

104

2

Per share, basic

(0.40)

0.57

(0.67)

0.40

(0.61)

0.48

(0.08)

0.29

0.36

0.01

Per share, diluted

(0.40)

0.57

(0.67)

0.39

(0.61)

0.47

(0.08)

0.28

0.35

0.01












Total cash capital investment

619

503

144

145

183

148

163

103

158

78












Cash and cash equivalents

318

464

318

373

564

675

464

398

512

549

Long-term debt

3,740

4,668

3,740

3,544

3,607

3,543

4,668

4,636

4,813

4,945















(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, 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 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 the Corporation's Management's Discussion and Analysis ("MD&A") dated December 31, 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: funds flow from (used in) operations, adjusted funds flow, operating earnings (loss), cash operating netback, Net Debt to LTM EBITDA and free cash flow 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

Funds flow from (used in) operations and adjusted funds flow 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 excludes the net change in non-cash operating working capital, realized gain on foreign exchange derivatives not considered part of ordinary continuing operating results, defense costs related to unsolicited bid, contract cancellation expense, 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 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 are reconciled to net cash provided by (used in) operating activities in the table below.




Year ended December 31

($000)

2018


2017

Net cash provided by (used in) operating activities

$

280,032


$

317,935

Net change in non-cash operating working capital items

(111,291)


24,517

Funds flow from (used in) operations

168,741


342,452

Adjustments:




Realized gain on foreign exchange derivatives(1)

(35,362)


Defense costs related to unsolicited bid(2)

19,152


Contract cancellation expense(3)


18,765

Net change in other liabilities(4)

3,251


(9,389)

Payments on onerous contracts

18,727


19,569

Decommissioning expenditures

5,225


2,403

Adjusted funds flow

$

179,734


$

373,800



(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.

(2)

The Corporation incurred costs of $19.2 million in the fourth quarter of 2018 related to Husky Energy Inc.'s unsolicited bid to acquire all of the outstanding shares of the Corporation.

(3)

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.

(4)

Excludes change in long-term cash-settled stock-based compensation liability.

 

Operating Cash Flow and Cash Operating Netback

Operating cash flow is a non-GAAP measure widely used in the oil and gas industry as a supplemental measure of a company's efficiency and its ability to fund future capital investments. The Corporation's operating cash flow is calculated by deducting the related diluent expense, blend purchases, transportation, operating expenses, royalties and realized commodity risk management gains or losses from proprietary blend sales revenue and power revenue. The per-unit calculation of operating cash flow, defined as cash operating netback, is calculated by deducting the related diluent expense, blend purchases, transportation, operating expenses, royalties and realized commodity risk management gains or losses from proprietary blend revenue and power revenue, on a per barrel of bitumen sales volume basis.

Net Debt to last twelve months earnings before interest, tax, depreciation and amortization (Net Debt to LTM EBITDA)

Net Debt to LTM EBITDA is a non-GAAP measure used to monitor the Corporation's capital structure and financial position. Net debt is calculated as current and long-term portions of long-term debt, net of cash and cash equivalents. LTM EBITDA is defined as net earnings before financing costs, interest income, income tax expense/(recovery), DD&A, gains/(losses) on asset divestiture, and other income/(loss), excluding all unrealized gains/(losses), on a trailing 12-month basis. The ratio of Net Debt to LTM EBITDA is used to measure the Corporation's financial strength.

Free Cash Flow

Free cash flow is presented to assist management and investors in analyzing performance by the Corporation as a measure of the capacity of the business to repay debt, incur discretionary capital or increase returns to shareholders. Free cash flow is calculated as adjusted funds flow less non-discretionary capital. Non-discretionary capital is required to sustain production capacity at the level achieved in the previous year and meet other corporate obligations. Non-discretionary capital includes sustaining & maintenance, field infrastructure, corporate and other capital (as those terms are used in the Corporation's MD&A).

Forward-Looking Information

Certain statements contained in this news release may constitute forward-looking statements within the meaning of applicable Canadian securities laws. These statements relate to future events or MEG's future performance. All statements other than statements of historical fact may be forward-looking statements. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe", "plan", "intend", "target", "potential" and similar expressions are intended to identify forward-looking statements. Forward-looking statements are often, but not always, identified by such words. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. In particular, and without limiting the foregoing, this press release contains forward looking statements with respect to our forecast base capital budget, allocation and funding, expected 2019 funds flow, free cash flow, adjusted funds flow, anticipated debt to EBITDA multiples, target production, non-energy operating costs, focus and strategy, market access and diversification plans.

Forward-looking information contained in this press release is based on management's expectations and assumptions regarding, among other things: future crude oil, bitumen blend, natural gas, electricity, condensate and other diluent prices, foreign exchange rates and interest rates; the recoverability of MEG's reserves and contingent resources; MEG's ability to produce and market production of bitumen blend successfully to customers; future growth, results of operations and production levels; future capital and other expenditures; revenues, expenses and cash flow; operating costs; reliability; anticipated reductions in operating costs as a result of optimization and scalability of certain operations; anticipated sources of funding for operations and capital investments; plans for and results of drilling activity; the regulatory framework governing royalties, land use, taxes and environmental matters, including the timing and level of government apportionment easing, in which MEG conducts and will conduct its business; 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 access to markets and transportation infrastructure; the availability of capacity on the electricity transmission grid; the uncertainty of reserve and resource estimates; the uncertainty of 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 and curtailment of production; 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 turnarounds, and of 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 news release is expressly qualified in its entirety by the foregoing cautionary statements. Unless otherwise stated, the forward-looking information included in this news release is made as of the date of this news release and MEG assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law.

This news release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about MEG's prospective results of operations including, without limitation, cash flow and various components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on FOFI. MEG's actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI, or if any of them do so, what benefits MEG will derive therefrom. MEG has included the FOFI in order to provide readers with a more complete perspective on MEG's future operations and such information may not be appropriate for other purposes. MEG disclaims any intention or obligation to update or revise any FOFI statements, whether as a result of new information, future events or otherwise, except as required by law. A full version of MEG's 2018 Full Year Report to Shareholders, including audited financial statements, is available at www.megenergy.com/investors and at www.sedar.com.

About MEG

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 & Media

John Rogers
VP, Investor Relations and External Communications
T 403-770-5335
E john.rogers@megenergy.com

Helen Kelly
Director, Investor Relations and External Communications
T 403-767-6206
E helen.kelly@megenergy.com

SOURCE MEG Energy Corp.