MEG Energy announces Q3 free cash flow of $152 million, record low net operating costs and $481 million year-to-date debt repayment

2019-10-30

TSX - Toronto Stock Exchange · Canada

Canada NewsWire

CALGARY, Oct. 30, 2019

All financial figures are in Canadian dollars ($ or C$) and all references to barrels are per barrel of bitumen sales unless otherwise noted

CALGARY, Oct. 30, 2019 /CNW/ - MEG Energy Corp. (TSX:MEG, "MEG") reported its third quarter 2019 operational and financial results.

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Highlights include:

Adjusted funds flow of $192 million($0.63per share) and $152 millionfree cash flow in the quarter. For the nine months ended September 30, 2019, MEG has generated free cash flow of $443 million;

Bitumen production volumes of 93,278 barrels per day (bbls/d) at a steam-oil-ratio (SOR) of 2.26;

Record low net operating costs of $4.30per barrel, supported by low non-energy operating costs of $4.22per barrel and strong power sales which had the impact of offsetting 95% of per barrel energy operating costs resulting in a net energy operating expense of $0.08per barrel;

Average AWB blend sales price net of transportation and storage costs at Edmontonof US$41.60which was in-line with the posted AWB index price for the quarter, notwithstanding 44% Enbridge mainline apportionment, highlighting the value of MEG's North American marketing strategy;

Total capital expenditures of $40 million, primarily consisting of sustaining and maintenance capital; and

Year-to-date repayment of $481 millionof outstanding long-term debt, including $88 millionsubsequent to the quarter. Management remains committed to applying all free cash flow after sustaining capital to further debt reduction.

"In the first nine months of the year, MEG has generated $569 millionof adjusted funds flow which is almost triple our full year 2019 capital investment plan of $200 million" says Derek Evans, President and Chief Executive Officer. "We remain focused on driving efficiencies in our business from an operational and cost perspective and will continue to direct all available free cash flow to debt repayment."

Bitumen production averaged 93,278 bbls/d in the third quarter of 2019, a 6% decrease over the same period in 2018 due to the impact of the Alberta Government's mandated production curtailment program which came into effect January 1, 2019. Third quarter 2019 production was 4% lower than second quarter 2019 production levels as fewer third-party curtailment credits were available for purchase. Bitumen sales exceeded bitumen production by 1,714 bbls/d during the third quarter of 2019 due primarily to the timing of sales over quarter end.

Notwithstanding the 6% decrease in production level year over year, third quarter 2019 per barrel non-energy operating costs of $4.22and per barrel net operating costs of $4.30were better than third quarter 2018 per barrel non-energy and net operating costs of $4.38and $4.34, respectively, due primarily to higher bitumen sales volumes. The Corporation now expects non-energy operating expenses in the range of $4.75- $5.00per barrel in 2019. Energy operating costs of $1.51per barrel in the third quarter of 2019 were largely offset by strong power revenues of $1.43per barrel, compared to energy operating costs and power revenues of $1.50and $1.54per barrel respectively for the same period in 2018.

General and administrative ("G&A") expense of $1.66per barrel of production in the third quarter of 2019 represents an 8% decrease from second quarter 2019, due primarily to the timing of expenses. The Corporation continues to expect G&A expense in the range of $1.95- $2.05per barrel in 2019.

Blend Sales Pricing and North American Market Access

MEG realized a third quarter 2019 average AWB blend sales price of US$45.63per barrel compared to US$51.72per barrel in the second quarter of 2019. The change in average AWB blend sales price quarter over quarter is primarily due to a US$3.37per barrel reduction in the benchmark WTI index combined with WTI:AWB differentials at Edmontonwidening to US$14.52per barrel from US$12.32per barrel and at the U.S. Gulf Coast ("USGC") widening to a discount of US$2.50from a premium of US$1.64per barrel. MEG sold 33% (26% via pipeline and 7% via rail) of its sales volumes to the USGC market in the third quarter of 2019 compared to 34% (29% via pipeline and 5% via rail) in the second quarter of 2019.

Transportation and storage costs averaged US$5.74per barrel of AWB blend sales in the third quarter of 2019 compared to US$5.60per barrel of AWB blend sales for second quarter of 2019 and US$5.00per barrel of AWB blend sales in third quarter of 2018.

Excluding transportation and storage costs upstream of the Edmontonindex sales point, MEG's net AWB blend sales price at Edmontonaveraged US$41.60per barrel in the third quarter of 2019 compared to the posted AWB index price at Edmontonof US$41.93. Notwithstanding that Enbridge mainline apportionment averaged 44%, MEG was able to capture pricing in-line with the Edmontonindex on its barrels as a result of its marketing and storage assets ability to 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 Edmontonshould improve further once MEG's contracted capacity on the Flanagan and Seaway pipeline system doubles to 100,000 bbls/d of AWB blend in mid-2020.

Despite 44% average Enbridge mainline apportionment in the quarter, MEG was required to sell less than 5% of its blend sales into the price constrained post-apportionment market at Edmontonin the third quarter of 2019. These post-apportionment sales typically receive a significant discount to the AWB index price at Edmonton. Avoiding the discounted pricing received by industry in the price constrained post-apportionment market highlights the strategic value of MEG's North American marketing strategy.

MEG's AWB blend sales by rail in the third quarter were 19,560 bbls/d compared to 23,443 bbls/d in the second quarter of 2019. 47% of sales by rail in the third quarter of 2019 were delivered to the USGC compared to 28% in the second quarter of 2019, with the remainder sold at Edmonton. Subject to market conditions at the time, MEG anticipates being in a position to fully utilize its 30,000 bbls/d of rail capacity at the Bruderheimrail terminal in 2020 once the results of the Alberta Petroleum Marketing Commission's crude by rail asset divestiture process are announced. MEG understands that the completion of the process is anticipated to be some time in 2019.

Adjusted Funds Flow and Net Earnings

During the third quarter of 2019, MEG's bitumen realization averaged $53.37per barrel, compared to $62.23per barrel in the second quarter of 2019 and $49.63per barrel in the third quarter of 2018 and was impacted by the same primary factors as average AWB blend sales price.

MEG's cash operating netback averaged $32.44per barrel in the third quarter of 2019, compared to $37.88per barrel in second quarter of 2019 and $24.01per barrel in third quarter of 2018. The cash operating netback in the third quarter of 2019 compared to the second quarter of 2019 reflects a lower realized bitumen sales price partially offset by lower hedging losses.

Adjusted funds flow was impacted by the same primary factors as cash operating netback, resulting in adjusted funds flow of $192 millionin the third quarter of 2019, compared to $227 millionin the second quarter of 2019 and $116 millionin the third quarter of 2018.

The Corporation recognized net earnings of $24 millionin the third quarter of 2019 compared to a net loss of $64 millionin the second quarter of 2019 and net earnings of $118 millionduring the third quarter of 2018. The decrease during the third quarter of 2019 compared to the same period of 2018 is due to an unrealized foreign exchange loss and a lower unrealized gain on commodity risk management partially offset by a higher cash operating netback.

Capital Expenditures

Capital expenditures in the third quarter of 2019 totaled $40 millionwith the majority of expenditures directed toward sustaining and maintenance capital.

In the first nine months of 2019 capital expenditures totaled $126 millionrelative to MEG's 2019 capital budget of $200 millionwhich was set during the implementation of the Alberta Government's mandated production curtailment program in January 2019. Over the course of 2019 MEG has been successful in finding capital cost savings and undertaking minor scope changes that will allow the Corporation to deliver its original $200 millionbudget for approximately $170 million. As a result, based on expected operational benefits, including plant integrity and turn-around management, MEG has shifted into 2019 approximately $30 millionof expected 2020 capital expenditures to accelerate the completion of the Corporation's in-progress brownfield project at the Phase 2Bcentral processing facility which includes incremental steam generation, water handling and oil treating capacity. This project, which was initiated in 2018, is expected to be completed in the first half of 2020.

Debt Repayment

Up to October 30thMEG has repaid $481 millionof outstanding long-term debt in 2019, including $385 millionduring the third quarter of 2019 and $88 millionsubsequent to the quarter. Annualized interest savings from these repurchases are expected to be approximately $30 million. These annualized interest savings, when combined with the annualized $14 millionof credit fee savings associated with the amendment of MEG's revolving credit facility announced July 30, 2019brings aggregate credit-related cash cost savings contribution to annual free cash flow to approximately $44 million.

Management remains committed to its stated strategy of continuing to direct all available free cash flow, after funding sustaining capital, toward debt reduction.

Outlook

MEG is revising its 2019 full year production guidance from 90,000 - 92,000 bbls/d to 92,000 - 93,000 bbls/d to reflect year to date production results and the continued impact of the Alberta Government's mandated production curtailment. MEG is also revising its 2019 full year non-energy operating cost guidance from $4.75- $5.25per barrel to $4.75- $5.00per barrel.

Conference Call

A conference call will be held to review MEG's third quarter 2019 operating and financial results at 6:30 a.m. Mountain Time(8:30 a.m. Eastern Time) on Thursday, October 31st, 2019. To participate, please dial the North American toll-free number 1-888-390-0546, or the international call number 1-416-764-8688.

A recording of the call will be available by 12 noon Mountain Time(2 p.m. Eastern Time) on the same day atwww.megenergy.com/investors/presentations-and-events.

Operational and Financial Highlights

| | | | | | | | | | | | | | Nine months ended September 30 | 2019 | 2018 | 2017 | | | | | | | | ($ millions, except as indicated) | 2019 | 2018 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | | Bitumen production - bbls/d | 92,582 | 87,781 | 93,278 | 97,288 | 87,113 | 87,582 | 98,751 | 71,325 | 93,207 | 90,228 | | | | | | | | | | | | | | Steam-oil ratio | 2.21 | 2.19 | 2.26 | 2.16 | 2.20 | 2.22 | 2.17 | 2.22 | 2.17 | 2.22 | | | | | | | | | | | | | | Bitumen sales - bbls/d | 93,330 | 86,636 | 94,992 | 95,120 | 89,822 | 88,283 | 93,856 | 74,418 | 91,608 | 94,541 | | | | | | | | | | | | | | Bitumen realization - $/bbl | 55.38 | 44.03 | 53.37 | 62.23 | 50.21 | 15.31 | 49.63 | 47.33 | 35.46 | 48.01 | | | | | | | | | | | | | | Net operating costs - $/bbl(1) | 5.01 | 5.28 | 4.30 | 4.66 | 6.17 | 4.55 | 4.34 | 5.64 | 5.98 | 5.86 | | | | | | | | | | | | | | Non-energy operating costs - $/bbl | 4.64 | 4.75 | 4.22 | 4.53 | 5.22 | 4.25 | 4.38 | 5.47 | 4.55 | 4.53 | | | | | | | | | | | | | | Cash operating netback - $/bbl(2) | 33.47 | 21.19 | 32.44 | 37.88 | 29.80 | 7.14 | 24.01 | 18.66 | 20.31 | 33.54 | | | | | | | | | | | | | | Adjusted funds flow(3) | 569 | 217 | 192 | 227 | 151 | (38) | 116 | 18 | 83 | 192 | | Per share, diluted(3) | 1.90 | 0.73 | 0.63 | 0.76 | 0.50 | (0.13) | 0.39 | 0.06 | 0.28 | 0.65 | | Revenue(4) | 2,938 | 2,213 | 958 | 1,062 | 919 | 520 | 803 | 689 | 721 | 755 | | Net earnings (loss) | (87) | 80 | 24 | (64) | (48) | (199) | 118 | (179) | 141 | (24) | | Per share, diluted | (0.29) | 0.27 | 0.08 | (0.21) | (0.16) | (0.67) | 0.39 | (0.61) | 0.47 | (0.08) | | | | | | | | | | | | | | Capital expenditures | 126 | 478 | 40 | 32 | 53 | 144 | 139 | 191 | 148 | 163 | | | | | | | | | | | | | | Cash and cash equivalents | 154 | 373 | 154 | 399 | 154 | 318 | 373 | 564 | 675 | 464 | | Long-term debt - C$ | 3,257 | 3,544 | 3,257 | 3,582 | 3,660 | 3,740 | 3,544 | 3,607 | 3,543 | 4,668 | | Long-term debt - US$ | 2,459 | 2,742 | 2,459 | 2,737 | 2,740 | 2,741 | 2,742 | 2,745 | 2,746 | 3,729 |

| | | | (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 cost of diluent, blend purchases, transportation and storage, third-party curtailment credits, operating expenses, royalties and realized commodity risk management gains (losses) from blend sales and power revenue, on a per barrel of bitumen sales volume basis | | (3) | Refer to Note 20 of the interim consolidated financial statements for further detail | | (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 free cash flow and cash operating netback 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.

Free Cash Flow

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 capital expenditures.

| | | | | | | | Three months ended September 30 | Nine months ended September 30 | | | | ($000) | 2019 | 2018 | 2019 | 2018 | | Net cash provided by (used in) operating activities | 174 | 3 | 406 | 186 | | Net change in non-cash operating working capital items | 17 | 108 | 162 | 48 | | Funds flow from (used in) operations | 191 | 111 | 568 | 234 | | Adjustments: | | | | | | Realized gain on foreign exchange derivatives(1) | - | - | - | (35) | | Payments on onerous contracts | - | 4 | - | 14 | | Decommissioning expenditures | 1 | 1 | 1 | 4 | | Adjusted funds flow | 192 | 116 | 569 | 217 | | Capital expenditures | (40) | (139) | (126) | (478) | | Free cash flow | 152 | (23) | 443 | (261) |

| | | | (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 |

Cash Operating Netback

Cash operating netback 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 expenditures. The Corporation's cash operating netback is calculated by deducting the related cost of diluent, blend purchases, transportation and storage, third-party curtailment credits, operating expenses, royalties and realized commodity risk management gains or losses from blend sales and power revenue. The per barrel calculation of cash operating netback is based on bitumen sales volume.

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 including the extent of non-discretionary sustaining capital expenditures, allocation and funding, expected 2019 funds flow, free cash flow and amount of debt repayment, adjusted funds flow, target production, non-energy operating costs, 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 and federal and provincial climate change policies, 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 acquisitions and/or dispositions of assets.