Denver-based Ovintiv Inc., whose broad oil and natural gas portfolio runs across the Permian and Anadarko basins and the Montney formation in Canada, is shelving some onshore work in the Eagle Ford, Bakken, Uinta and Duvernay formations, but it’s keeping a sharp eye on the direction of natural gas prices to determine when to boost activity.
The market is undergoing “something none of us could have predicted,” CEO Doug Suttles told analysts during a quarterly conference call last Friday. “While we prepare for a black swan event in our risk management process, we never thought we had to prepare for a whole flock of it.
“Fortunately, we have the flexibility to rapidly adapt to changing market conditions without incurring fees or penalties. We are adjusting our activities in real-time to ensure that we get optimal outcomes today as well as position us for 2021 and beyond.”
A “dynamic shut-in strategy has been developed and is based on variable costs/margins and price factors,” and wells with higher variable costs are being deferred to await higher pricing. “Today, we have about 65,000 boe/d shut-in, of which about 35,000 b/d is oil and condensate,” said COO Greg Givens, who joined Suttles and the executive team to discuss plans going forward.
The wells that are not pumping are “a combination of shutting in wells and deferring production in recently completed wells,” Givens said. “We expect this number could rise in June.”
Ovintiv’s multi-basin portfolio during down times in the market “is an advantage here as we manage curtailments in real time, recognizing not only benchmark prices but regional differentials and differences in the product mix,” the COO said. “It is a highly integrated approach between our operating and marketing teams.
“We are simply electing to store our oil in the reservoirs. We do not expect any detrimental impacts when we turn these wells to production, and that’s something we can do very rapidly once pricing conditions improve.”
There is a “much larger percentage” of wells shut-in within the Uinta, Bakken and Eagle Ford, Suttles said. Wells recently drilled and completed (D&C) are producing at “very restricted rates.
It’s difficult to put a precise number on how many wells are shut-in because differentials “played a very big role in this conversation and also the product mix plays a very big role…”
Ovintiv’s portfolio includes wells that produce 80% oil in some locations, while in other regions, it’s 15-20%. “What actually matters” is what wet gas and natural gas liquids (NGL) are doing, Suttles said.
Shut-in wells are “not just oil-price dependent. It will also depend on what gas and NGLs are doing,” the CEO told analysts.
Particular attention is being paid to natural gas prices to determine “at what point would the wells we target shift, based on product pricing…Clearly, there are a number of people who are getting more bullish on natural gas prices. Of course, what that does in a play like the Anadarko or the Montney, it just makes them more attractive because we would still get the liquids production, but would get an even better price for the natural gas.”
How pricing goes “could make a difference on capital allocation at the margin. We’re studying that today because…as you move particularly in the Montney into some of the different type curve areas, you actually get higher rate wells. You get a lot more gas, and you may not be giving up much on the condensate side…At the margin, it could make a difference.”
For the “next several months, we expect that oil prices will be weak and volatile,” even though there are encouraging signs as producers reduce capital and shut-in production, Suttles said.
“The Covid-19 driven demand loss is too great to quickly overcome, but it is encouraging to begin to see the green shoots of returning demand.”
[Want to see more earnings? See the full list of NGI’s 1Q2020 earnings season coverage.]
As the crisis unfolded in early March, Ovintiv reduced cash costs by $100 million, but it now has doubled those cuts, which should hold into 2021 and beyond. In addition, well costs are expected to be more than 20% lower than in 2019.
Second quarter capital expenditures (capex) were reduced by 60%, and the North America rig count was slashed to seven from 23. Fracture spreads are now at zero from eight, all “without incurring penalties or termination fees,” Suttles said. As it builds out its drilled but uncompleted, or DUC, well count, Ovintiv still expects to exit 2020 “with about 30 DUCs, which would be what we would normally be doing year/year.”
First quarter natural gas production was more than 1.5 Bcf/d, with crude and condensate production of 215,000 b/d, up around 4% year/year and 7,000 b/d above guidance.
Even with the shut-ins, the 2020 exit rate for crude and condensate is forecast to average 200,000 b/d. “We might have a very, very small gas decline in there, but there isn’t a huge difference in that scenario between boes and crude and condensate,” Suttles said.
Total capex for 2020 is set at $1.8-1.9 billion. Management is banking on improving West Texas Intermediate (WTI) oil and New York Mercantile Exchange (Nymex) natural gas prices into next year.
“In 2021, with a total capital investment scenario of approximately $1.5 billion, we are confident that we could deliver free cash flow at $35/bbl WTI and $2.75/MMBtu Nymex natural gas while holding crude and condensate flat at 200,000 b/d,” said Suttles.
During the first three months of this year, Ovintiv delivered higher than budgeted production at 571,300 boe/d, 3% above guidance, while costs declined to $12.17/boe. Capex was $790 million, under budget and consistent with plans to frontload spending for the year.
However, second quarter activity levels have been reduced by 60% to $250-350 million to ensure continued financial strength.
Within the next few days, Ovintiv’s rig count will have been cut by two-thirds from the start of the year, to eight from 33, with three rigs running in the Permian, and two each in the Anadarko and Montney. All completions have been deferred through June. With no long-term oilfield services commitments, the independent is “prepared to further adjust its investment and activity levels based on market conditions.”
Executive Vice President Brendan McCracken, who oversees Corporate Development and External Relations, said Ovintiv is incorporating optimization techniques, particularly in the Permian, where most of the capex is directed. Well costs in the play have been cut to $700/lateral foot, and they are forecast to decrease to slightly above $600 going forward.
Ovintiv in the Permian is using simulated fracturing completions, aka Simul-Fracs, which allow two wells to be fractured at the same time using a single spread, Givens said. More than two-thirds of the wells turned in line (TIL) in the first quarter were completed using the technology, with an 18% decrease in the fracture cycle time compared with 2019.
Permian production increased 20% year/year and averaged 109,600 boe/d. Average D&C and tie-in costs were 7% below the 2019 average. During the quarter, 37 net wells were TIL.
Anadarko output climbed 11% year/year to 161,000 boe/d, with 27 net TILs. Well costs were significantly lowered, with 13 recent wells D&C’d for under $5 million/well, or 40% below costs before 2019. Ovintiv is now estimating go-forward D&C costs at $5 million/well.
First quarter liquids output from the Montney climbed 8% year/year to 52,500 b/d, with total production averaging 204,700 boe/d, weighted to natural gas. There were 28 net TILs in the quarter.
“The Montney produces nearly 60% of the company’s natural gas volumes and has a significant inventory of dry gas opportunities,” management noted. “The asset has the pipeline capacity, processing infrastructure and transportation contracts required to react quickly if gas prices continue to strengthen relative to oil and condensate.”
On the financial side, Ovintiv is in much stronger shape than some of its Lower 48 peers, CFO Corey Code told analysts. Two credit facilities, one in Canada and one in the United States, have total capacity of $4 billion. The facilities were renewed in January and are not subject to changes through mid-2024. “As we can attest from past cycles in energy, there is no greater asset than liquidity,” Code said. “It is the oxygen that provides the staying power to the business and will get us safely to the other side…We do not have a borrowing base or annual redetermination process that is underway today,” nor leverage covenants, “which in today’s period of low prices could make reductions in activity levels and supply curtailments very difficult.”
Net profits were $421 million ($1.62/share), compared with year-ago losses of $245 million (minus $1.00). Ovintiv recorded a one-time impairment of $277 million in the latest quarter, but hedging gains contributed $904 million to the bottom line, versus a $427 million loss in 1Q2019.
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