All financial figures are in Canadian dollars ($ or C$) and all references to barrels are per barrel of bitumen sales unless otherwise noted
CALGARY, July 30, 2019 /CNW/ - MEG Energy Corp. (TSX:MEG, "MEG") reported its second quarter 2019 operational and financial results.
Highlights include:
- Record free cash flow of $195 million and adjusted funds flow of $227 million ($0.76 per share) in the quarter. For the 6 months ended June 30, 2019 MEG generated free cash flow of $293 million;
- Bitumen production volumes of 97,288 barrels per day (bbls/d) at a steam-oil-ratio (SOR) of 2.16;
- Average AWB blend sales price net of transportation and storage costs at Edmonton of US$47.77 beat the posted AWB index price for the quarter, notwithstanding 41% Enbridge mainline apportionment, highlighting the value of MEG's North American marketing strategy;
- Total cash capital investment of $32 million in the quarter as part of the $200 million 2019 capital program. Previously announced $75 million discretionary capital will not be sanctioned in 2019;
- Net operating costs of $4.66 per barrel, supported by non-energy operating costs of $4.53 per barrel and strong power sales which had the impact of offsetting 93% of per barrel energy operating costs resulting in a net energy operating expense of $0.13 per barrel; and
- Subsequent to the quarter, MEG repaid the outstanding 1st lien term loan balance of approximately $285 million and amended and restated its existing credit facilities to have new 5-year terms and total available credit of $1.3 billion. MEG remains committed to debt reduction going forward and will continue to direct available free cash flow to debt repayment. Cash cost savings of approximately $42 million per year are expected from the combination of the reduction in credit fees under the new credit facilities, the 1st lien debt repayment and the disposal or sale of non-core assets announced in the quarter.
"Record free cash flow of $195 million generated during the second quarter demonstrates MEG's ability to generate substantial value in a volatile market with our low-cost structure and our strategic access to high-valued markets," says Derek Evans, President and Chief Executive Officer. "Third-party curtailment credits purchased in the second quarter allowed us to opportunistically increase production to levels near our current productive capacity of 100,000 bbls/d and enhance funds flow in a favourable pricing environment despite on-going government mandated production curtailments. Year to date, we have generated $378 million of adjusted funds flow, almost double our full year 2019 capital investment plan of $200 million with debt reduction remaining a top priority for free cash flow. Based on current strip pricing, we expect our total net debt to EBITDA to be approximately 3.0x by the end of 2019".
Bitumen production averaged 97,288 bbls/d in the second quarter of 2019, a 36% increase over the same period in 2018 which was impacted by a large-scale turnaround. Second quarter 2019 production was 12% higher than first quarter 2019 production levels as purchased third-party curtailment credits allowed MEG to produce at higher levels than otherwise allowed under the Alberta Government's mandated production curtailment which came into effect January 1, 2019. Bitumen production exceeded bitumen sales by 2,168 bbls/d during the second quarter due to a combination of increased production, higher June apportionment levels and the timing of sales over quarter end.
Second quarter 2019 per barrel non-energy operating costs of $4.53 and net operating costs of $4.66 reflects higher bitumen sales volumes compared to second quarter 2018 per barrel non-energy and net operating costs of $5.47 and $5.64 respectively. Energy operating costs of $1.78 per barrel in the second quarter of 2019 were largely offset by strong power revenues of $1.65 per barrel, compared to energy operating costs and power revenues of $1.79 and $1.62 per barrel respectively for the same period in 2018.
General and administrative ("G&A") expense of $1.81 per barrel of production in the second quarter of 2019 represents a 20% decrease from first quarter 2019, due to increased production levels quarter over quarter and the impact of changes to staffing levels. The Corporation expects G&A expense in the range of $1.95 - $2.05 per barrel in 2019.
Blend Sales Pricing and North American Market Access
MEG realized strong pricing in the second quarter of 2019 with AWB blend sales price averaging US$51.72 per barrel compared to US$44.40 per barrel in the first quarter of 2019 as a result of an improvement in both the WTI benchmark price and the WTI:AWB differential quarter over quarter. WTI:AWB differentials at Edmonton narrowed to US$12.32 from US$14.50 per barrel and in the Gulf Coast narrowed to a premium of US$1.64 from a discount of US$0.89 per barrel in first quarter of 2019. MEG sold 34% (29% via Flanagan and 5% via rail) of its sales volumes to the USGC market in the second quarter of 2019 compared to 31% (25% via Flanagan and 6% via rail) in the first quarter of 2019.
Transportation and storage costs averaged US$5.60 per barrel of AWB blend sales in the second quarter of 2019 compared to US$5.75 per barrel of AWB blend sales for first quarter of 2019 and US$4.41 per barrel of AWB blend sales in second quarter of 2018. The increase on a per barrel basis quarter over quarter is primarily the result of incremental costs associated with increased volumes transported by rail as no volumes were shipped by rail in the second quarter of 2018.
Excluding transportation and storage costs upstream of the Edmonton index sales point, MEG's net AWB blend sales price at Edmonton averaged US$47.77 per barrel in the second quarter of 2019 compared to the posted AWB index price at Edmonton of US$47.50. Notwithstanding that Enbridge mainline apportionment averaged 41% in the quarter, MEG was able to capture slightly better than Edmonton index pricing on its barrels given its marketing and storage assets provide the ability to both move barrels toward higher value markets as well as provide flexibility to avoid the price-constrained post-apportionment market at Edmonton. MEG's average pricing against the AWB index price at Edmonton should improve further once MEG's Flanagan pipeline capacity doubles to 100,000 bbls/d of AWB blend in mid-2020.
Despite 41% average Enbridge mainline apportionment in the quarter, MEG was required to sell less than 6% of its blend sales into the price-constrained post-apportionment market at Edmonton in the second quarter of 2019. These post-apportionment sales typically receive a significant discount to the AWB index price at Edmonton. The discounted pricing being received by industry in the price-constrained post-apportionment market highlights the strategic value of MEG's North American marketing strategy.
MEG increased its AWB blend sales by rail from 18,649 bbls/d in the first quarter of 2019 to 23,443 bbls/d in the second quarter of 2019, 28% of which were delivered to the USGC with the remainder sold FOB Edmonton. MEG continues to use rail as a mechanism to clear barrels due to continued high Enbridge mainline apportionment, thereby reducing exposure to the post apportionment market at Edmonton.
Adjusted Funds Flow and Net Earnings
During the second quarter of 2019, MEG's bitumen realization averaged $62.23 per barrel, compared to $50.21 per barrel in the first quarter of 2019 and $47.33 per barrel in the second quarter of 2018 and was positively impacted by stronger WTI benchmark pricing, narrowing of the WTI:AWB differential and improved condensate benchmark pricing.
MEG's cash operating netback averaged $37.88 per barrel in the second quarter of 2019, compared to $29.80 per barrel in first quarter of 2019 and $18.66 per barrel in second quarter of 2018. The strong netbacks in the second quarter of 2019 compared to the first quarter of 2019 were primarily the result of the stronger realized blend sales price.
Adjusted funds flow was impacted by the same primary factors as cash operating netback, resulting in realized adjusted funds flow of $227 million in the second quarter of 2019, compared to $151 million in the first quarter of 2019 and $18 million in the second quarter of 2018.
The Corporation recognized a net loss of $64 million in the second quarter of 2019 compared to a net loss of $179 million during the second quarter of 2018. MEG's combined unrealized gain on commodity risk management contracts and foreign exchange of $154 million in the quarter was more than offset by a one-time after-tax non-cash charge against earnings of $228 million, in the form of accelerated depreciation and exploration expense, to recognize the uncertainty of future benefits associated with certain non-core assets. These non-core assets relate to equipment, materials, engineering costs, a partial upgrading technology and land lease and evaluation costs that will not contribute to the Corporation's development plan or cash flow in the foreseeable future. This one-time non-cash charge, which does not impact adjusted funds flow, is the result of management's cost structure review, and is in keeping with MEG's focus on free cash flow generation. The disposal or sale of these non-core assets is expected to reduce the Corporation's go-forward cash costs by approximately $10 million per year. The net loss recognized in the second quarter of 2018 was affected by a $62 million unrealized foreign exchange loss and an unrealized loss on commodity risk management contracts of $61 million.
Capital Investment
Total cash capital investment in the second quarter of 2019 totaled $32 million relative to MEG's 2019 base capital budget of $200 million. Capital investment in the period was primarily directed towards non-discretionary capital to sustain and maintain current production capacity level and investment to complete work already underway on the Phase 2B Brownfield expansion.
Debt Repayment and New 5-Year Revolving Credit Facility
Subsequent to the second quarter, MEG repaid, with a portion of available year-to-date free cash flow, its outstanding 1st lien term loan of US$219 million (approximately C$285 million). MEG expects to continue to repay outstanding indebtedness as free cash flow becomes available. Annualized 2019 interest savings resulting from the repayment of the term loan is expected to be approximately $18 million.
Concurrent with the term loan repayment, MEG has amended and restated its revolving credit facility (the "Revolving Credit Facility") and its letters of credit facility guaranteed by Export Development Canada (the "EDC Facility") and extended the maturity date of each facility by 2.75 years to July 30, 2024. The maturity dates of the Revolving Credit Facility and the EDC Facility include a feature that will cause the maturity dates to spring back to 91 days prior to the maturity date of certain material debt of MEG if such debt has not been repaid or refinanced prior to such date.
Consistent with MEG's business plan of capital discipline and free cash flow generation, it has proactively reduced the total credit available under the two facilities to $1.3 billion, comprised of $800 million under the Revolving Credit Facility and $500 million under the EDC Facility. The reduction of the total commitment amount is expected to reduce go-forward credit fees by approximately $14 million per year.
The combined annual cash savings of these two transactions together with the anticipated savings from disposal or sale of non-core assets described above are expected to reduce annual cash costs by approximately $42 million, significantly adding to the free cash flow generation of the business.
The Revolving Credit Facility contains no financial maintenance covenant unless MEG is drawn under the Revolving Credit Facility in excess of 50%. If drawn in excess of 50%, or $400 million, under the Revolving Credit Facility MEG is required to maintain a 1st Lien Net Debt to LTM EBITDA ratio of 3.50 or less. The financial covenant, if triggered, is tested quarterly. Following the repayment of the outstanding term loan MEG has no 1st lien debt outstanding and to date MEG has never drawn funds under its revolving credit facility.
"The results of this amendment and extension reflect the strength of MEG's business plan and asset base and was timed to take advantage of a strong syndicated bank market. MEG has been successful in either maintaining or enhancing the flexibility embedded in the existing credit facility to support MEG's go-forward business plan of debt reduction and balance sheet strength, capital discipline and free cash flow generation. The new 5-year Revolving Credit Facility, which at closing remains undrawn, is more than sufficient to meet our foreseeable liquidity needs," said Eric Toews, Chief Financial Officer.
BMO Capital Markets and RBC Capital Markets acted as joint lead arrangers and joint bookrunners with respect to the Revolving Credit Facility.
Outlook
MEG reiterates its 2019 capital investment plan of $200 million and confirms that the previously announced 2019 discretionary capital budget of $75 million will not be sanctioned in 2019 given provincially mandated production curtailment, current lack of clarity on market egress and on-going prioritization of debt repayment. The 2019 capital budget is primarily designed to sustain production capability at 100,000 bbls/d while completing the in-progress expansion of the oil treating capacity at the Corporation's central processing facility to approximately 120,000 bbls/d. While MEG has the ability to average 100,000 bbls/d of production, the current 2019 production guidance of 90,000 to 92,000 bbls/d reflects year to date production and the expected continued impact of the Alberta government's mandated production curtailment. Subject to financial and operational considerations, MEG will continue to opportunistically purchase production credits from other upstream producers who choose to sell a portion of their mandated production allocation.
Conference Call
A conference call will be held to review MEG's second quarter 2019 operating and financial results at 7:30 a.m. Mountain Time (9:30 a.m. Eastern Time) on Wednesday, July 31st, 2019. To participate, please dial the North American toll-free number 1-888-390-0546, or the international call number 1-587-880-2171.
A recording of the call will be available by 12 noon Mountain Time (2 p.m. Eastern Time) on the same day at www.megenergy.com/investors/presentations-and-events.
Operational and Financial Highlights
|
|
|
|
|
|
Six months ended
June 30
|
2019
|
2018
|
2017
|
|
($ millions, except as indicated)
|
2019
|
2018
|
Q2
|
Q1
|
Q4
|
Q3
|
Q2
|
Q1
|
Q4
|
Q3
|
|
Bitumen production - bbls/d
|
92,228
|
82,205
|
97,288
|
87,113
|
87,582
|
98,751
|
71,325
|
93,207
|
90,228
|
83,008
|
|
|
|
|
|
|
|
|
|
|
|
|
Steam-oil ratio
|
2.18
|
2.19
|
2.16
|
2.20
|
2.22
|
2.17
|
2.22
|
2.17
|
2.22
|
2.34
|
|
|
|
|
|
|
|
|
|
|
|
|
Bitumen sales - bbls/d
|
92,486
|
82,966
|
95,120
|
89,822
|
88,283
|
93,856
|
74,418
|
91,608
|
94,541
|
76,813
|
|
|
|
|
|
|
|
|
|
|
|
|
Bitumen realization - $/bbl
|
56.42
|
40.81
|
62.23
|
50.21
|
15.31
|
49.63
|
47.33
|
35.46
|
48.01
|
39.93
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating costs - $/bbl(1)
|
5.39
|
5.82
|
4.66
|
6.17
|
4.55
|
4.34
|
5.64
|
5.98
|
5.86
|
6.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-energy operating costs - $/bbl
|
4.86
|
4.96
|
4.53
|
5.22
|
4.25
|
4.38
|
5.47
|
4.55
|
4.53
|
4.57
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash operating netback - $/bbl(2)
|
33.98
|
19.57
|
37.88
|
29.80
|
7.14
|
24.01
|
18.66
|
20.31
|
33.54
|
26.88
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted funds flow(3)
|
378
|
102
|
227
|
151
|
(38)
|
116
|
18
|
83
|
192
|
83
|
|
Per share, diluted(3)
|
1.26
|
0.34
|
0.76
|
0.50
|
(0.13)
|
0.39
|
0.06
|
0.28
|
0.65
|
0.28
|
|
Revenue(4)
|
1,980
|
1,410
|
1,062
|
919
|
520
|
803
|
689
|
721
|
755
|
576
|
|
Net earnings (loss)
|
(111)
|
(38)
|
(64)
|
(48)
|
(199)
|
118
|
(179)
|
141
|
(24)
|
84
|
|
Per share, basic
|
(0.37)
|
(0.13)
|
(0.21)
|
(0.16)
|
(0.67)
|
0.40
|
(0.61)
|
0.48
|
(0.08)
|
0.29
|
|
Per share, diluted
|
(0.37)
|
(0.13)
|
(0.21)
|
(0.16)
|
(0.67)
|
0.39
|
(0.61)
|
0.47
|
(0.08)
|
0.28
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash capital investment
|
85
|
330
|
32
|
53
|
144
|
145
|
183
|
148
|
163
|
103
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
399
|
564
|
399
|
154
|
318
|
373
|
564
|
675
|
464
|
398
|
|
Long-term debt - C$
|
3,582
|
3,607
|
3,582
|
3,660
|
3,740
|
3,544
|
3,607
|
3,543
|
4,668
|
4,636
|
|
Long-term debt - US$
|
2,737
|
2,745
|
2,737
|
2,740
|
2,741
|
2,742
|
2,745
|
2,746
|
3,729
|
3,706
|
|
|
|
(1)
|
Net operating costs include energy and non-energy operating costs, reduced by power revenue.
|
|
(2)
|
Cash operating netback is a non-GAAP measure and is calculated by deducting the related diluent expense, transportation and storage, third-party curtailment credits, net operating costs, royalties and realized commodity risk management gains (losses) from petroleum revenue, net of purchased product, on a per barrel of bitumen sales volume basis.
|
|
(3)
|
Adjusted funds flow and the related per share amounts are non-GAAP measures and do not have standardized meanings prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Adjusted funds flow is reconciled to net cash provided by (used in) operating activities and is discussed further under the heading "NON-GAAP MEASURES" 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 MD&A. The comparative prior period amounts have been revised 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 cash flow, cash operating netback, free cash flow and total net debt to twelve months earnings before interest, tax, depreciation and amortization ("Total Net Debt to LTM EBITDA") 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, Adjusted Funds Flow and Free Cash 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, 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.
Free cash flow is presented to assist management and investors in analyzing performance by the Corporation as a measure of financial liquidity and the capacity of the business to repay debt. Free cash flow is calculated as adjusted funds flow less total cash capital investment.
|
|
|
|
Three months ended June 30
|
Six months ended June 30
|
|
($000)
|
2019
|
2018
|
2019
|
2018
|
|
Net cash provided by (used in) operating activities
|
301,941
|
65,243
|
232,212
|
183,269
|
|
Net change in non-cash operating working capital items
|
(75,044)
|
(51,836)
|
145,243
|
(59,972)
|
|
Funds flow from (used in) operations
|
226,897
|
13,407
|
377,455
|
123,297
|
|
Adjustments:
|
|
|
|
|
|
Realized gain on foreign exchange derivatives(1)
|
-
|
-
|
-
|
(35,362)
|
|
Payments on onerous contracts
|
-
|
4,236
|
-
|
10,244
|
|
Decommissioning expenditures
|
65
|
750
|
441
|
3,371
|
|
Adjusted funds flow
|
226,962
|
18,393
|
377,896
|
101,550
|
|
Total cash capital investment
|
(31,859)
|
(182,567)
|
(85,152)
|
(330,306)
|
|
Free cash flow
|
195,103
|
(164,174)
|
292,744
|
(228,756)
|
|
(1)
|
A gain related to the settlement of forward currency contracts to manage the foreign exchange risk on Canadian dollar denominated proceeds related to the sale of assets designated for U.S. dollar denominated long-term debt repayment.
|
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 and storage, third-party curtailment credits, 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 and storage, third-party curtailment credits, 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.
Total Net Debt to Last Twelve Months Earnings Before Interest, Tax, Depreciation and Amortization (Total Net Debt to LTM EBITDA)
Total Net Debt to LTM EBITDA is a non-GAAP measure used to monitor the Corporation's capital structure and financial position. Total 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 Total Net Debt to LTM EBITDA is used to measure the Corporation's financial strength.
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, target production, non-energy operating costs, Total Net Debt to EBITDA, annual cash cost savings as a result of debt repayment and refinancing and disposal or sale of non-core assets, 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; extent and timelines of the Alberta Government's mandatory production curtailment program, 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 2019 First Quarter Report to Shareholders, including unaudited 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 thermal oil development and production in the southern Athabasca 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:
Investor Relations
T 403.767.6206
E invest@megenergy.com
Media Relations
T 403.767.1485
E media@megenergy.com
SOURCE MEG Energy Corp.
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