MEG Energy announces second quarter 2020 free cash flow of $69 million, exiting the quarter with credit facility undrawn and $120 million of cash on hand

CALGARY, AB – MEG Energy Corp. (TSX: MEG), (“MEG” or the “Corporation”) reported  its second quarter 2020 operational and financial results.

MEG continues to proactively respond to the safety and financial challenges associated with the COVID-19 pandemic and remains committed to ensuring the health and safety of all of its personnel and the safe and reliable operation of the Christina Lake facility.

“The second quarter was characterized by extreme negative movements in commodity prices coupled with unprecedented uncertainty regarding near-term crude oil supply and demand balances due to COVID-19” said Derek Evans, President and Chief Executive Officer. “Our team continued to react quickly during the quarter to protect MEG’s financial liquidity by voluntarily curtailing production, making additional cuts to our capital budget and further reducing G&A and non-energy operating expenses, all of which when supplemented by our strong hedge position allowed MEG to exit the quarter with an undrawn revolver and $120 million of cash on hand.”

MEG remains well positioned from a financial liquidity perspective, benefiting not only from its significant 2020 hedge book and the term and structure of its outstanding indebtedness and credit facility, but also from the low decline and low cost structure of its high-quality Christina Lake asset.

Second quarter financial and operating highlights include:

• Free cash flow of $69 million driven by adjusted funds flow of $89 million ($0.29 per share) and disciplined capital spending of $20 million;
• $120 million of cash on hand at quarter end benefiting from a $215 million realized gain on commodity risk management in the quarter. MEG’s $800 million modified covenant-lite revolver remains undrawn;
• Bitumen production volumes of 75,687 barrels per day (bbls/d) at a steam-oil ratio (SOR) of 2.3, while undertaking planned turnaround activities;
• Net operating costs of $6.14 per barrel, including non-energy operating costs of $4.09 per barrel and strong power sales which had the impact of offsetting 32% of per barrel energy operating costs, resulting in a net energy operating cost of $2.05 per barrel;
• On May 4, 2020, as a result of the negative and uncertain commodity price environment at that time, MEG reduced full year 2020 capital investment by an additional $50 million to $150 million, or 40% below original guidance of $250 million. Approximately 75% of the aggregate $100 million capital reduction in the year was associated with future bitumen production. MEG also reduced non-energy operating cost and general and administrative (“G&A”) expense guidance by $20 million and $10 million, respectively; and
• During the quarter, a decision was made to roll back salaries across the company, with an emphasis on Board, executive and senior leader compensation. Effective June 1, 2020, base cash compensation for Board members was reduced by 25%. The President and Chief Executive Officer had his annual base salary reduced by 25%, the Chief Operating Officer and Chief Financial Officer each took a 15% annual base salary reduction, vice presidents received a 12% annual base salary rollback and all other employees received a 7.5% annual base salary rollback. In addition, the value of target 2020 long-term incentive awards issued to employees and directors on April 1, 2020 was reduced by 20%.

Blend Sales Pricing and North American Market Access

MEG realized an average AWB blend sales price of US$15.12 per barrel during the three months ended June 30, 2020 compared to US$27.12 per barrel in the first quarter of 2020. The reduction in average AWB blend sales price quarter over quarter was primarily a result of the average WTI price decreasing by US$18.32 per barrel, partially offset by the average WTI:AWB differential at Edmonton narrowing by US$9.34 per barrel.  MEG sold 35% (all via pipe) of its sales volumes to the US Gulf Coast (“USGC”) in the second quarter of 2020 compared to 23% (21% via pipe and 2% via rail) in the first quarter of 2020. The increase in sales to the USGC in the second quarter is a result of lower apportionment on the Enbridge mainline of 13% compared with 50% apportionment in the first quarter of 2020.

Transportation and storage costs averaged US$5.92 per barrel of AWB blend sales in the second quarter of 2020 compared to US$4.39 per barrel of AWB blend sales in the first quarter of 2020. The increase in transportation and storage costs is primarily due to the fixed costs associated with contracted capacity allocated to 29% lower AWB blend sales volumes quarter over quarter, partially offset by the elimination of rail costs to the USGC.  MEG’s AWB blend sales by rail was 4,391 bbls/d (all FOB Edmonton) in the second quarter of 2020 compared to 30,152 bbls/d (27,867 bbls/d FOB Edmonton) in the first quarter of 2020.  The reduction in barrels sold via rail quarter over quarter was a result of rail cost mitigation efforts undertaken by the Corporation in the second quarter given the relative economics of rail transportation compared to pipeline transportation costs.

Excluding transportation and storage costs upstream of the Edmonton index sales point, MEG’s net AWB blend sales price at Edmonton averaged US$11.28 per barrel during the three months ended June 30, 2020 compared to the posted AWB index price at Edmonton of US$14.41 per barrel, largely as a result of having sales exposure to the weaker priced months of April and May (approximately 110,000 bbls/d of AWB blend sales), with reduced volumes sold in the stronger priced month of June (approximately 84,000 bbls/d of AWB blend sales) due to the major planned turnaround initiated at the beginning of June.

Operational Performance

Bitumen production averaged 75,687 bbls/d in the second quarter of 2020, compared to 91,557 bbls/d in the first quarter of 2020. Bitumen production in the second quarter was impacted primarily by major planned turnaround activities at the Corporation’s Phase 1 & 2 facilities which began at the beginning of June, impacting production by approximately 10,000 bpd in the quarter, and voluntary price-related production curtailments in the April and May timeframe. Net operating costs in the second quarter of 2020 averaged $6.14 per barrel, an 11% increase compared to the first quarter of 2020, directly impacted by lower surplus power sales revenue from MEG’s cogeneration facilities. Non-energy operating costs averaged $4.09 per barrel in the second quarter of 2020 compared to $4.57 per barrel in the first quarter of 2020. Net energy operating costs averaged $2.05 per barrel in the second quarter of 2020 compared to $0.94 in the first quarter of 2020.

G&A expense was $9 million, or $1.29 per barrel of production, in the second quarter of 2020 compared to $16 million, or $1.96 per barrel of production, in the first quarter of 2020. The decrease in aggregate G&A quarter over quarter was primarily a result of the temporary Canadian Emergency Wage Subsidy, salary rollbacks and reductions in staff and consulting costs.

Adjusted Funds Flow and Net Loss

MEG’s bitumen realization averaged $10.18 per barrel in the second quarter of 2020 compared to $19.45 per barrel in the first quarter of 2020. The reduction in average bitumen realization quarter over quarter was driven by the lower WTI price and lower sales volumes, partially offset by a narrower WTI:AWB differential which resulted in a higher recovery of the cost of diluent through blend sales, decreasing the Corporation’s per barrel cost of diluent.

Offsetting the decline in bitumen realization was a realized commodity risk management gain of $215 million in the quarter increasing MEG’s bitumen realization by $21.65 per barrel quarter over quarter. The realized commodity risk management gain contributed to the increase in the Corporation’s cash operating netback of $25.84 per barrel in the second quarter of 2020 compared to $16.83 per barrel in the first quarter of 2020. The increased cash operating netback drove the increase in the Corporation’s adjusted funds flow from $78 million in the first quarter of 2020 to $89 million in the second quarter of 2020.

The Corporation recognized a net loss of $80 million in the second quarter of 2020 compared to a net loss of $284 million in the first quarter of 2020. Non-cash items in the second quarter of 2020 include an unrealized gain on foreign exchange of $114 million, and an unrealized loss on commodity risk management of $267 million. Comparatively, in the first quarter of 2020, non-cash items consisted of an unrealized foreign exchange loss of $267 million, an exploration expense of $366 million associated with certain non-core growth properties and an inventory impairment charge of $29 million, partially offset by a $429 million unrealized gain on commodity risk management contracts.

Capital Expenditures

MEG reacted quickly to the extremely negative oil price environment experienced in the second quarter of 2020, protecting the Corporation’s financial liquidity partially by reducing capital expenditures to $20 million in the quarter compared to $54 million in the first quarter of 2020. Of the $20 million, $10 million was directed towards sustaining and maintenance activities with the remaining $10 million related to the planned turnaround at the Christina Lake Phase 1 and 2 facilities which was initiated at the beginning of June.  The expanded scope and duration of the planned turnaround, which was committed to in early May, is expected to be executed at reduced costs by relying on internal resources and will eliminate the need for a turnaround in 2021.

COVID-19 Global Pandemic

The Corporation is continuously monitoring and responding to the ongoing evolving COVID-19 situation. The Corporation’s business activities have been declared an essential service by the Alberta Government and the Corporation remains committed to the health and safety of all personnel and to the safety and continuity of operations. The health and safety measures implemented by the Corporation’s COVID-19 task force during the first quarter of 2020 currently remain in place. The vast majority of office staff are still working remotely, however, beginning in June the Corporation lifted certain restrictions which allowed more location essential personnel at the Christina Lake site to facilitate MEG’s planned turnaround activity while still maintaining COVID-19 related screening, procedures and protocols to ensure continued safe and reliable operations.

Outlook

On May 4, the Corporation suspended full year 2020 production guidance due to the global crude oil price environment at that time, which was experiencing multi-decade lows coupled with extreme levels of volatility driven by the unprecedented demand shock due to COVID-19.

Since that time, crude oil price levels and volatility have stabilized to a level that allows the Corporation to re-instate full year production guidance which is now targeted at 78,000 – 80,000 bbls/d.  Compared to the original guidance of 94,000 – 97,000 bbls/d announced November 21, 2019, approximately half of the difference is due to the impact of the scheduled 70-day major turnaround at the Christina Lake Phase 1 and 2 facilities announced May 4, 2020.  The remainder of the difference results from a combination of previously disclosed weather-related production impacts in the first quarter of 2020, voluntary price-related production curtailments in the second quarter of 2020 and the impact of reduced well capital throughout 2020, which made up approximately 75% of the combined $100 million reduction in capital spending announced on March 10 and May 4 of 2020.

Guidance for non-energy operating costs, G&A expense and capital expenditures remain unchanged from the revised guidance announced May 4, 2020.

Financial Liquidity

Notwithstanding multi-decade low crude oil prices, MEG generated $92 million of free cash flow in the first half of year, and exited the second quarter with its credit facility undrawn and $120 million of cash on hand.

The Corporation’s earliest long-term debt maturity is approximately four years out, represented by US$600 million of senior unsecured notes due March 2024. None of the Corporation’s outstanding long-term debt contain financial maintenance covenants. Additionally, MEG’s modified covenant-lite $800 million revolving credit facility has no financial maintenance covenant unless drawn in excess of $400 million. If drawn in excess of $400 million, MEG is required to maintain a quarterly first lien net leverage ratio (first lien net debt to last twelve-month EBITDA) of 3.5 or less. Under MEG’s credit facility, first lien net debt is calculated as debt under the credit facility plus other debt that is secured on a pari passu basis with the credit facility, less cash on hand.

2H 2020 Commodity Hedges

For the second half of 2020, to date MEG has entered into benchmark WTI fixed price hedges for approximately 70% of forecast second half bitumen production at an average price of approximately US$46 per barrel. The table below reflects all of MEG’s current 2020 financial and physical hedge positions.

Conference Call

A conference call will be held to review MEG’s second quarter 2020 operating and financial results at 6:30 a.m. Mountain Time (8:30 a.m. Eastern Time) on Tuesday, July 28^th, 2020. 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		2020		2019				2018
($millions, except as indicated)	2020	2019	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Bitumen production – bbls/d	83,622	92,228	75,687	91,557	94,566	93,278	97,288	87,113	87,582	98,751
Steam-oil ratio	2.31	2.18	2.32	2.31	2.27	2.26	2.16	2.20	2.22	2.17
Bitumen sales – bbls/d	83,806	92,486	70,397	97,214	94,347	94,992	95,120	89,822	88,283	93,856
Bitumen realization – $/bbl	15.56	56.42	10.18	19.45	46.86	53.37	62.23	50.21	15.31	49.63
Net operating costs – $/bbl(1)	5.78	5.39	6.14	5.51	5.87	4.30	4.66	6.17	4.55	4.34
Non-energy operating costs – $/bbl	4.37	4.86	4.09	4.57	4.49	4.22	4.53	5.22	4.25	4.38
Cash operating netback – $/bbl(2)	20.62	33.98	25.84	16.83	28.33	32.44	37.88	29.80	7.14	24.01
Adjusted funds flow(3)	166	378	89	78	157	192	227	151	(37)	116
Per share, diluted	0.55	1.26	0.29	0.26	0.51	0.63	0.76	0.50	(0.13)	0.39
Revenue	972	1,980	307	665	992	958	1,062	919	520	803
Net earnings (loss)	(364)	(111)	(80)	(284)	26	24	(64)	(48)	(199)	118
Per share, diluted	(1.21)	(0.37)	(0.26)	(0.95)	0.09	0.08	(0.21)	(0.16)	(0.67)	0.39
Capital expenditures	74	85	20	54	72	40	32	53	144	139
Cash and cash equivalents	120	399	120	62	206	154	399	154	318	373
Long-term debt – C$	3,096	3,582	3,096	3,212	3,123	3,257	3,582	3,660	3,740	3,544
Long-term debt – US$	2,274	2,737	2,274	2,275	2,409	2,459	2,737	2,740	2,741	2,742

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.

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.