CALGARY, AB – MEG Energy Corp. (TSX: MEG) (“MEG” or the “Corporation”) reported its second quarter of 2021 operational and financial results.
MEG continues to proactively respond to the safety 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 another strong operational quarter for MEG, giving us the confidence to increase our full year 2021 production guidance and begin the work to bring our Christina Lake facility back up to full operational utilization and re-initiate debt reduction” said Derek Evans, President and Chief Executive Officer. “Today we announced the redemption of approximately $125 million of debt and are committed to applying all free cash flow generated in the second half of 2021 to debt reduction.”
Second quarter financial and operating highlights include:
- Adjusted funds flow of $166 million ($0.53 per share), impacted by a realized commodity price risk management loss in the quarter of $87 million ($0.28 per share);
- Quarterly production volumes of 91,803 barrels per day (bbls/d) at a steam–oil ratio (SOR) of 2.39. Based on strong operational performance, annual average production guidance has been upwardly revised from 88,000 – 90,000 bbls/d to 91,000 – 93,000 bbls/d;
- Net operating costs of $5.54 per barrel, including non–energy operating costs of $3.84 per barrel. Power revenue offset energy operating costs by 60%, resulting in a net impact of $1.70 per barrel;
- Sale of non-core industrial lands near Edmonton for cash proceeds of approximately $44 million;
- Total capital investment of $70 million in the quarter was directed to sustaining and maintenance capital, resulting in $96 million of free cash flow in the quarter and $153 million of free cash flow in the first half of 2021;
- In June 2021 MEG along with four other oil sands operators who collectively represent 90% of Canada’s oil sands production formed the Oil Sands Pathway to Net Zero Alliance to work collectively with the federal and Alberta governments to achieve net zero GHG emissions from oil sands operations by 2050; and
- Subsequent to the quarter, MEG issued a notice to redeem US$100 million (approximately C$125 million) of MEG’s 6.50% senior secured second lien notes due January 2025.
Blend Sales Pricing
MEG realized an average AWB blend sales price of US$56.41 per barrel during the second quarter of 2021 compared to US$48.39 per barrel in the first quarter of 2021. The increase in average AWB blend sales price quarter over quarter was primarily a result of the average WTI price increasing by US$8.23 per barrel. MEG sold 45% of its sales volumes at the premium-priced U.S. Gulf Coast (“USGC”) in the second quarter of 2021 compared to 38% in the first quarter of 2021.
As sales volumes were consistent quarter over quarter, transportation and storage costs were also consistent averaging US$6.17 per barrel of AWB blend sales in the second quarter of 2021 compared to US$6.13 per barrel of AWB blend sales in the first quarter of 2021.
Operational Performance
Bitumen production averaged 91,803 bbls/d in the second quarter of 2021, consistent with average bitumen production of 90,842 bbls/d in the first quarter of 2021.
Non–energy operating costs averaged $3.84 per barrel of bitumen sales in the second quarter of 2021 compared to $4.05 per barrel in the first quarter of 2021 primarily due to a 3% increase in bitumen sales volumes quarter over quarter. Energy operating costs, net of power revenue, averaged $1.70 per barrel in the second quarter of 2021 compared to $1.20 per barrel in the first quarter of 2021. MEG benefited from strong power prices on power sales from its cogeneration facilities whereby power revenue offset energy operating costs by 60% during the second quarter of 2021.
General & administrative expense (“G&A”) was $13 million, or $1.56 per barrel of production, in the second quarter of 2021 compared to $14 million, or $1.77 per barrel of production, in the first quarter of 2021. The difference in per barrel G&A expense was due to higher production in the second quarter of 2021 compared to the first quarter of 2021.
Adjusted Funds Flow and Net Earnings (Loss)
MEG’s bitumen realization averaged $60.09 per barrel in the second quarter of 2021 compared to $52.34 per barrel in the first quarter of 2021. The increase in average bitumen realization was due to the higher WTI price quarter over quarter. Partially offsetting the increase in bitumen realization during the second quarter of 2021, compared to the first quarter of 2021, was a realized commodity price risk management loss of $10.63 per barrel in the second quarter of 2021 compared to $8.80 per barrel in the first quarter of 2021. This reflects stronger WTI settlement prices compared to WTI fixed price contracts in place.
The Corporation’s cash operating netback averaged $31.30 per barrel in the second quarter of 2021 compared to $26.03 per barrel in the first quarter of 2021. The increased cash operating netback drove the increase in the Corporation’s adjusted funds flow from $127 million in the first quarter of 2021 to $166 million in the second quarter of 2021.
The Corporation recognized net earnings of $68 million in the second quarter of 2021 compared to a net loss of $17 million in the first quarter of 2021. This change was primarily the result of increased cash operating netback and a smaller unrealized loss on commodity price risk management.
Capital Expenditures
MEG invested $70 million in the second quarter of 2021 compared to $70 million in the first quarter of 2021, which was primarily directed towards sustaining and maintenance activities during both periods.
COVID-19 Global Pandemic
MEG continues to proactively respond to the safety challenges associated with COVID-19 and remains committed to ensuring that the health and safety of all its personnel and business partners and the safe and reliable operation of the Christina Lake facility remain a top priority. MEG continues to apply screening procedures, including antigen screening and other protocols, ensuring the health and safety of its people.
Non-Core Asset Sale
During the quarter, MEG completed the sale of non-core industrial lands near Edmonton for cash proceeds of approximately $44 million, with proceeds received in July. The lands were purchased in 2013 at a cost of $39 million.
Optimization of Christina Lake Production Capacity
Inclusive of the non-core asset sale, MEG generated approximately $200 million of cash in excess of invested capital in the first half of 2021. Of this amount, the Corporation will direct $75 million to MEG’s 2021 capital investment program.
This $75 million of capital investment represents the majority of the estimated $125 million incremental well capital necessary to allow the Corporation to fully utilize the Christina Lake central plant facility’s oil processing capacity of approximately 100,000 bbls/d, prior to any impact from scheduled maintenance activity or outages.
The estimated $125 million total cost is less than MEG’s previous estimate of $150 million due to year-to-date field-wide production outperformance resulting from increased steam utilization, improved field reliability and completed and ongoing well optimization and recompletion work. This year-to-date outperformance provides the confidence for the Corporation to increase full year 2021 average production guidance from 88,000 – 90,000 bbls/d to 91,000 – 93,000 bbls/d.
MEG expects to invest the estimated $50 million of remaining incremental well capital required to return the Christina Lake facility to full utilization in the first half of 2022. Based on this level of incremental capital investment the Corporation expects to be able to fully utilize the oil processing capacity at its Christina Lake facility in the second half of 2022 post the planned turnaround at MEG’s Phase 2B facility in the second quarter of 2022. The turnaround, which is scheduled for the month of May 2022, is currently expected to impact full year 2022 production by approximately 5,000 bbls/d.
Debt Repayment
MEG announced today that the Corporation has issued a notice to redeem US$100 million (approximately C$125 million) of MEG’s 6.50% senior secured second lien notes due January 2025 at a redemption price of 103.25%, plus accrued and unpaid interest to, but not including, the redemption date. The redemption is expected to be completed on or about August 23, 2021.
Based on the current commodity price environment, MEG anticipates generating approximately $275 million of free cash flow in the second half of 2021, which will be directed to further debt repayment.
Outlook
Based on better than expected production performance in the first half of 2021, MEG is revising its full year 2021 average production to 91,000 – 93,000 bpd.
G&A expense is now targeted to be in the range of $1.65 – $1.75 per barrel and non-energy operating costs are now expected to be in the range of $4.40 – $4.60 per barrel.
Summary of 2021 Guidance |
Revised Guidance |
Revised Guidance |
Original Guidance |
Bitumen production – annual average |
91,000 – 93,000 bbls/d |
88,000 – 90,000 bbls/d |
86,000 – 90,000 bbls/d |
Non-energy operating costs |
$4.40 – $4.60 per bbl |
$4.60 – $5.00 per bbl |
$4.60 – $5.00 per bbl |
G&A expense |
$1.65 – $1.75 per bbl |
$1.70 – $1.80 per bbl |
$1.70 – $1.80 per bbl |
Capital expenditures |
$335 million |
$260 million |
$260 million |
MEG is revising downward its expected sales into the USGC via Flanagan South and Seaway Pipeline systems (“FSP”) from 50% to approximately 40% of total AWB blend sales. This is lower than previous estimates due to continued higher than forecast apportionment on the Enbridge mainline system. As a result, MEG is revising downward its estimate of full year 2021 total transportation costs from a range of US$6.75 to US$7.25 per barrel of AWB blend sales to a range of US$6.00 to US$6.50 per barrel of AWB blend sales.
2021 Commodity Price Risk Management
In the second half of 2020, MEG entered into enhanced WTI fixed price hedges with sold put options for approximately 30% of forecast second half of 2021 bitumen production at an average price of US$46.18 per barrel. MEG has also hedged approximately 15% of its forecast Edmonton WTI:WCS differential exposure for the third quarter of 2021 at an average differential of US$11.05 per barrel. In addition, MEG has hedged approximately 35% of its expected condensate requirements at a landed-at-Edmonton price of 97% of WTI, approximately 30% of expected natural gas requirements at an average price of C$2.61 per GJ and fixed the sales price on approximately 30% of expected power available for sale at an average price of C$62.75 per MWh, each for the second half of 2021. The table below reflects MEG’s outstanding 2021 hedge positions.
Forecast Period |
||||||
Q3 2021 |
Q4 2021 |
|||||
WTI Hedges |
||||||
Enhanced WTI Fixed Price Hedges with Sold Put Options(1) |
||||||
Volume (bbls/d) |
29,000 |
29,000 |
||||
Weighted average fixed WTI price (US$/bbl) / Put option strike price (US$/bbl) |
$ 46.18 / $ 38.79 |
$ 46.18 / $ 38.79 |
||||
WTI:WCS Differential Hedges |
||||||
Volume (bbls/d) |
10,000 |
— |
||||
Weighted average fixed WTI:WCS differential (US$/bbl) |
$ |
(11.05) |
$ |
— |
||
Condensate Hedges |
||||||
Volume(2) (bbls/d) |
14,028 |
14,028 |
||||
Weighted average % of WTI landed in Edmonton (%)(3) |
97 |
% |
97 |
% |
||
Natural Gas Hedges |
||||||
Volume(4) (GJ/d) |
42,500 |
42,500 |
||||
Weighted average fixed AECO price (C$/GJ) |
$ |
2.61 |
$ |
2.61 |
||
Power Hedges |
||||||
Quantity(5) (MW) |
35 |
35 |
||||
Weighted average fixed price (C$/MWh) |
$ |
62.75 |
$ |
62.75 |
(1) |
If in any month the average WTI settlement price is US$38.79 per barrel (the sold put option) or better, MEG will receive US$46.18 per barrel (the fixed price swap) on each barrel hedged in that month. If in any month the average WTI settlement price is less than US$38.79 per barrel, MEG will receive the month average WTI settlement price in that month plus US$7.39 per barrel (the swap spread) on each barrel hedged in that month. |
(2) |
Includes approximately 3,000 bbls/d of physical forward condensate purchases for the second half of 2021 at a fixed discount to WTI. |
(3) |
The average % of WTI landed in Edmonton includes estimated net transportation costs to Edmonton. |
(4) |
Includes 5,000 GJ/d of physical forward natural gas purchases for the second half of 2021 at a fixed AECO price. |
(5) |
Represents physical forward power sales at a fixed power price. |
Conference Call
A conference call will be held to review MEG’s second quarter of 2021 operating and financial results at 6:30 a.m. Mountain Time (8:30 a.m. Eastern Time) on Friday, July 23rd, 2021. To participate, please dial the North American toll-free number 1-888-390-0546, or the international call number 1-416-764-8688.
A recording of the call will be available by 12 noon Mountain Time (2 p.m. Eastern Time) on the same day at www.megenergy.com/investors/presentations-and-events.
Operational and Financial Highlights
Six months ended |
2021 |
2020 |
2019 |
|||||||
($millions, except as indicated) |
2021 |
2020 |
Q2 |
Q1 |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
Q3 |
Bitumen production – bbls/d |
91,326 |
83,622 |
91,803 |
90,842 |
91,030 |
71,516 |
75,687 |
91,557 |
94,566 |
93,278 |
Steam-oil ratio |
2.38 |
2.31 |
2.39 |
2.37 |
2.31 |
2.36 |
2.32 |
2.31 |
2.27 |
2.26 |
Bitumen sales – bbls/d |
88,646 |
83,806 |
89,980 |
87,298 |
95,731 |
67,569 |
70,397 |
97,214 |
94,347 |
94,992 |
Bitumen realization – $/bbl |
56.30 |
15.56 |
60.09 |
52.34 |
38.64 |
39.68 |
10.18 |
19.45 |
46.86 |
53.37 |
Net operating costs – $/bbl(1) |
5.39 |
5.78 |
5.54 |
5.25 |
6.98 |
6.05 |
6.14 |
5.51 |
5.87 |
4.30 |
Non-energy operating costs – $/bbl |
3.94 |
4.37 |
3.84 |
4.05 |
4.70 |
3.96 |
4.09 |
4.57 |
4.49 |
4.22 |
Cash operating netback – $/bbl(2) |
28.73 |
20.62 |
31.30 |
26.03 |
18.66 |
16.58 |
25.84 |
16.83 |
28.33 |
32.44 |
General & administrative expense $/bbl(3) |
1.66 |
1.66 |
1.56 |
1.77 |
1.65 |
1.50 |
1.29 |
1.96 |
2.25 |
1.66 |
Adjusted funds flow(4) |
293 |
164 |
166 |
127 |
84 |
26 |
89 |
76 |
155 |
191 |
Per share, diluted |
0.95 |
0.54 |
0.53 |
0.41 |
0.27 |
0.09 |
0.29 |
0.25 |
0.51 |
0.63 |
Revenue |
1,923 |
972 |
1,009 |
914 |
786 |
533 |
307 |
665 |
992 |
958 |
Net earnings (loss) |
51 |
(364) |
68 |
(17) |
16 |
(9) |
(80) |
(284) |
26 |
24 |
Per share, diluted |
0.17 |
(1.21) |
0.22 |
(0.06) |
0.05 |
(0.03) |
(0.26) |
(0.95) |
0.09 |
0.08 |
Capital expenditures |
140 |
74 |
70 |
70 |
40 |
36 |
20 |
54 |
72 |
40 |
Cash and cash equivalents |
159 |
120 |
159 |
54 |
114 |
49 |
120 |
62 |
206 |
154 |
Long-term debt – C$ |
2,820 |
3,096 |
2,820 |
2,852 |
2,912 |
3,030 |
3,096 |
3,212 |
3,123 |
3,257 |
Long-term debt – US$ |
2,273 |
2,274 |
2,273 |
2,268 |
2,283 |
2,274 |
2,274 |
2,275 |
2,409 |
2,459 |
(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 does not have a standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Refer to the “NON-GAAP MEASURES” section of this Press Release. |
(3) |
General and administrative expense (“G&A”) per barrel is based on bitumen production volumes. |
(4) |
Refer to Note 19 of the June 30, 2021 interim consolidated financial statements for further details. |
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$), which is the Corporation’s functional currency.
Non-GAAP Measures
Certain financial measures in this news release including free cash flow and cash operating netback are non-GAAP measures. These terms are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. These non-GAAP financial measures should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS.
Free Cash Flow
Free cash flow is presented to assist management and investors in analyzing performance by the Corporation as a measure of financial liquidity and the capacity of the business to repay debt. Free cash flow is calculated as adjusted funds flow less capital expenditures.
Three months ended June 30 |
Six months ended June 30 |
|||||||
($millions) |
2021 |
2020 |
2021 |
2020 |
||||
Net cash provided by (used in) operating activities |
$ |
180 |
$ |
117 |
$ |
192 |
$ |
216 |
Net change in non-cash operating working capital items |
(20) |
(48) |
89 |
(78) |
||||
Funds flow from operations |
160 |
69 |
281 |
138 |
||||
Adjustments: |
||||||||
Payments on onerous contracts |
6 |
— |
12 |
— |
||||
Contract cancellation |
— |
20 |
— |
26 |
||||
Adjusted funds flow |
$ |
166 |
$ |
89 |
$ |
293 |
$ |
164 |
Capital expenditures |
(70) |
(20) |
(140) |
(74) |
||||
Free cash flow |
$ |
96 |
$ |
69 |
$ |
153 |
$ |
90 |
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.