BP plc, which took over a massive Lower 48 position in March, is ready to build its oil and gas warehouse in the Permian Basin and beyond, the CFO said Tuesday.
Underlying replacement cost profit, similar to the U.S. net earnings metric, totaled $2.36 billion (70 cents/share), versus $2.59 billion (78 cents) in the year-ago period.
The London-based supermajor still beat Wall Street forecasts on higher production and from “strong” trading results, including from its liquefied natural gas (LNG) investments, CFO Brian Gilvary said during a conference call.
“We wouldn't normally get into a lot of detail,” about the gas trading arm, but he said a portion of the gains in gas trading “came out of a very strong result in North America, which is really positioning on some of the books around the cold weather” during the quarter and around the LNG book, “which was really focused on the European gas,” allowing BP to place some bets on artibtration and on LNG.
“It was across the piece, but I would say the big key chunks of the overperformance in the first quarter were the United States and LNG out of Europe,” Gilvary said. Asked to clarify how strong the gas trading was during the first three months, he said “it’s certainly over $100 million more than we will expect in a typical quarter.”
“I think we see an overcapacity coming through certainly in the second half of this year and probably into 2020 around LNG projects coming onstream,” and “we have seen prices already correct...with prices close to $5/MMBtu in terms of European and Asian pricing right now. I suspect that's going to continue...
“From an LNG trading perspective, anything that creates volatility, that creates opportunity,” he told analysts. “The different pricing bases that we have provide some opportunities for us.”
The CFO, in discussing the macro environment, said “strong LNG supply growth since the end of 2018 coupled with warmer weather caused global gas prices to fall through the quarter, notably in Asian and the European market…”
The United States saw a return to “more normal” gas storage levels, “so Henry Hub gas prices reduced to an average of $3.20/MMBtu compared with $3.70 in the fourth quarter.”
LNG oversupply is forecast by BP to continue through this year, “largely exceeding Asian demand growth with excess volumes being redirected primarily to Europe,” Gilvary said.
Also on the minds of analysts during the question and answer period was integrating Lower 48 assets acquired from BHP last year, which gave the U.S. arm BPX Energy entry into the Permian Basin and more opportunities throughout the country.
Upstream production overall climbed 2% year/year to 2.7 million boe/d, aided by the $10.5 billion acquisition.
“Full control of field operations assumed at the start of March,” Gilvary said of the BPX additions. BPX had 14 drilling rigs operating in the Lower 48 at the end of the first quarter, including three on new acreage acquired in the Permian’s Delaware sub-basin, as well as five in the Eagle Ford Shale. It also had six rigs running at the end of March in the gassy Haynesville Shale.
“We continue to be confident in the delivery of the synergies created by the transaction and are increasingly seeing further upside potential that was not assumed in our base case,” Gilvary said.
BPX production alone totaled 481,000 boe/d in the first quarter, versus 316,000 in the year-ago period and 447,000 in the fourth quarter.
Lower 48 natural gas production totaled 2,134 MMcf/d in 1Q2019, versus 1,586 MMcf/d a year ago and 2,053 MMcf/d in the fourth quarter. Liquids output increased to 113,000 b/d from year-ago volumes of 43,000 b/d and from 93,000 b/d in 4Q2018.
BPX fetched an average realized price of $2.59/Mcf for its U.S. gas in the first quarter, compared with $2.24 in the year-ago quarter and $3.10 in the final three months of 2018.
The total hydrocarbons price received for U.S. oil and gas in the Lower 48 was $20.22/boe, compared with $15.63 a year earlier and $21.85 in 4Q2018.
BP also ramped up three upstream projects in the first three months in the U.S. Gulf of Mexico, Trinidad and Egypt.
“We have now brought 22 upstream major projects online since 2016 and have 30 more to go, as part of our plan to deliver 900,000 boe/d of new major project production by 2021.”
Even with the “volatile pricing environment” early this year, “we have made a good start to the year building on the underlying operational and financial momentum established over the past couple of years. In the upstream, our operated plant reliability remained strong at 96.2%, and we continue to grow our balanced portfolio with three major project startups startups further underpinning our 2021 growth targets.”
“Looking ahead, we expect all demand growth to remain relatively robust and supply growth to be modest,” with disruptions in Venezuela and Iran continuing and ongoing compliance through June by members and allies of the Organization of the Petroleum Exporting Countries.
“These factors are expected to partly offset the increase in U.S. production, which is currently around 12 million b/d,” he said. In North America, increasing offtake capacity from the Permian that matches the production and pipeline export capacity should keep the West Texas Intermediate/Western Canadian Select oil differential “at around the level seen in the first quarter.”
BP remains “confident” in its guidance on returns exceeding 10% by 2021 at a $55/bbl oil price assumption. “In summary, we are entering the third year of our five-year strategy and remain on track to deliver our 2020 target,” he said.
“Things are already starting to ramp up,” and “the assumption on synergies now looks somewhat conservative given what we discovered in terms of the operations all being absorbed within our existing structure.”