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MEG Energy raises full-year production guidance from improved H1 performance


Expects 2021 output at 91,000-93,000 b/d

Christina Lake facility seen at full capacity in 2022

Will not hedge WTI benchmark prices in 2022

Canadian oil sands producer MEG Energy has revised its full-year 2021 average production guidance, based on improved production performance in the first half of the year, its top executive said July 23.

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The company now expects 2021 production to average to 91,000 b/d-93,000 b/d, up from 86,000 b/d-90,000 b/d earlier in the year, CEO Derek Evans said during a second-quarter earnings conference call.

"We benefited from both the strength in the global oil market dynamic as well as the structural invented heavy oil differentials," Evans said. "We remain very constructive that these changes will persevere and that the headwinds we've battled over the last six years with respect to egress and weakness in oil prices will abate and become tailwinds that will continue to drive significant free cash flow from our low decline, low-cost asset base."

On the operational front, the work needed to bring the company's Christina Lake facility back up to full capacity next year continues. Proceeds of $44 million received from the Q2 sale of non-core industrial lands near Edmonton, Alberta, plus more than $150 million of cash generated in first-half 2021, will provide most of funding needed to fully utilize the 100,000 b/d of oil processing capacity at Christina Lake's central plant, Evans said.

Funding reduced for Christina Lake

That work will require $125 million of funds, a lower amount than the $150 million that MEG previously estimated. The lower sum is the result of field-wide production outperformances from increased steam utilization, improved field reliability and ongoing well optimization and recompletion work. In turn, these are responsible for the increased 2021 average output guidance.

Asked if the 100,000 b/d of capacity could be tweaked a little higher, given the producer has already debottlenecked its operation to achieve higher production to date at the facility, Evans said it all depends whether the company can get full utilization of all the steam being created from the field.

Another factor in reaping higher production would be assuring the field can operate "as close to 100% reliability and availability as possibly we can," he said.

"Then there's a significant component to our production outperformance that we've seen year to date, which really is continued work on the downhole or subsurface side of the business where we're seeing significant improvements and some exciting technological innovation," he added.

MEG averaged 91,803 b/d of bitumen production in Q2, up about 1% from Q21 2021. Volumes have been fairly steady this year, up from a quarterly low of 71,500 b/d low in Q3 2020 during the coronavirus pandemic.

Higher AWB, bitumen prices

MEG realized an average AWB blend sales price of US $56.41/b in Q2 2021, compared to US $48.39/b in Q1. The increase stems from an $8.23/b increase in the average WTI price.

In addition, the company's bitumen realization averaged $60.09/ b in Q2 2021, versus $52.34/b in Q1 2021. The jump in realization was due higher WTI prices quarter over quarter.

Also in Q2, MEG sold 45% of its sales volumes into the US Gulf Coast market, which offers premium prices, compared to 38% in Q1 2021.

Looking forward, the company's Chief Financial Officer Eric Lloyd Toews said MEG's "current intention" is not to hedge 2022 benchmark WTI prices, given differentials for WCS versus WTI in the $13/b-$14/b range next year. That is also the recent range.

For August 2021, "we saw a 54% apportionment on the [Enbridge] mainline ... as far as we know, a record apportionment," Toews said.

Interestingly, inventories in Western Canada declined in May from 38 million barrels to 35 million barrels, while rail is running less than 100,000 b/d, he said. And the post-apportionment market in August is roughly minus $2/b off the index, "which is at the low end of the historical range of our pricing."

Pricing in Edmonton versus the US Gulf Coast is still within pipeline economics, he added.

"As we move through this year, we start to see differentials for the back end of this year at about $13.50/b-$14/b," said Toews. "Then as we go into next year with Line 3 coming on in Q4, which is our expectation ... we should see differentials tighten against what we're seeing for the back end of this year -- maybe gap up a little, $1 or $1.25 on the back of that. So net-net, we still see differentials in 2022 in that sort of $13/b to $14/b range."