With a plethora of global natural gas and oil opportunities from which to pick and choose, BP plc wants to build volumes, but the priority still continues to be value, CEO Murray Auchincloss said Tuesday.
Speaking with the executive team from London, Auchincloss laid out the objectives during a wide ranging quarterly discussion with analysts.
The integrated major, the top natural gas trader in North America, also is one of the leading gas producers in the Haynesville Shale. Don’t look for gas activity to rise in the near term, though. BP has cut its Haynesville rig count to one from three a year ago.
“I'm focused on cash flow and returns, and production will be an outcome of that,” Auchincloss said. “But I'm really, really focused on growing cash flow. If I just wanted to grow volumes, I could plow all the money in the world into the Haynesville, and I could grow volumes like crazy.
“But that's not the right thing to do for shareholders. It’s to create cash flow and returns.”
BP for several years has been working to overhaul its “international oil company” label to rebrand as an “international energy company,” Auchincloss noted. That’s still the plan.
Still, expanding the LNG trading arm remains an imperative for the long term as consumption rises. According to Auchincloss, BP is chasing a liquefied natural gas target to deliver 25 million metric tons/year (mmty) by 2025, reaching 30 mmty by 2030. BP’s LNG output was 23 mmty in 2023.
LNG ‘Optionality’
BP historically has more spot exposure than some of its peers to LNG, which is monetized through trading. Prices of late have not been too accommodating.
In the Gas and Low Carbon segment, which includes LNG trading, BP’s natural gas production was basically flat in 2Q2024 at 4.65 Bcf/d from 4.64 Bcf/d a year ago. BP fetched a realized global gas price of $5.47/MMBtu from a year-ago average price of $5.53.
Within the Oil and Operations arm, gas production averaged 2.3 Bcf/d versus year-ago output of 2.1 Bcf/d. Average realized prices were $2.02 from a year-ago price of $3.23.
With more LNG supply scheduled to come onstream in the next year, particularly along the Gulf Coast, executives were asked whether BP was looking for more “brand-linked, long-term contracts.” How does BP split the exposure between spot and long-term prices?
Executive Vice President Carol Howle, who oversees Trading & Shipping, handled the question.
“We do buy on Henry Hub and Brent basis, and we do also sell on Henry Hub and Brent basis,” Howle said. “The way that we look at our portfolio is the first thing that we want to do is lock in the intrinsic margin. Then, because we've built a lot of optionality into our portfolio over time, what we then look to do is trade and optimize around those flows, rewire cargoes into the optimal markets and highest pricing centers.”
As an example, around 50% of BP’s gas supply is “open for Asia and Atlantic cross buys and optimization, and we expect that to grow to around two-thirds in 2025,” Howle said. “We also use tools continuously, on a daily basis, to actually look at those rewiring opportunities. And they take price feeds in…
“Should we be flexing volumes? Should we be redirecting supply into a particular market because of a price change or or an arbitrage movement? We're constantly looking at that portfolio in order to maximize the value for BP in terms of volume,” the trading chief explained.
BP marketed around 23 mmty of LNG last year, up 20% versus 2022, Howle noted. “On top of that, we had 10 mmty of what we would call short-term and spot contracts. But for us, the short term is like a three- to five-year period, so it's not all spot.”
In terms of the contract split, BP last year had 23 long-term and 10 short-to-medium term contracts. In April, BP clinched an 11-year, 9.8 mmty long-term contract with Korea Gas Corp., a strategic partner, Howle noted. That contract was in addition to a 20-year contract already in place.
“We are looking at long-term contracts,” Howle said. “We also look at short-term market opportunities.”
From a “Trading and Shipping perspective overall, we've been consistent in our delivery,” Howle said. “We have delivered…an uplift of around 4% to the group's return on average capital employed over the past four years. That's through a number of cycles, a number of environments, and roughly, we would say it's probably 50-50, oil, gas.
“We've also got a history on the gas side of actually purchasing counter cyclical. So a lot of the long-term contracts that we've entered into on the supply side have been done at low points in the market, so they are high value contracts.”
The plan is to “continue to invest” in the trading platform to maintain and build competitiveness, Howle said. “That does mean…access to infrastructure, to downstream markets. And I mean this both on the oil and gas side…As an example, we were the leaders of going into LNG downstream in China” with the Guangdong joint venture (JV).
Several LNG-related projects are in the queue, including Greater Tortue offshore Senegal and Mauritania.
“We’re making good progress” on Tortue, Auchincloss said. “We would look to introduce first gas into the system to start all the pressure testing, etc., over the next three or four months…”
BP’s Cypre and Mento gas projects in Trinidad and Tobago also are advancing. Ramp up is set for 2025.
[In the Eye of the Storm: North American LNG project developers continue to grapple with the Biden administration's pause on non-FTA permits. Has the pause given impetus to other projects? How are Mexico LNG projects advancing? Tune in to hear from LNG industry analyst Sergio Chapa in the latest episode of NGI's Hub & Flow.]
“We’ve also sanctioned the Coconut gas project,” Auchincloss said. “We have been awarded rights, together with the National Gas Company of Trinidad and Tobago, to develop the Cocuina gas field, allowing us to progress the development of the cross-border Manakin-Cocuina field.”
Pending regulatory approval, BP plans to also snag a 10% stake in the LNG project planned by state-owned Abu Dhabi National Oil Co. (Adnoc) in Al Ruwais Industrial City. The project’s total LNG production capacity is proposed to be 9.6 mmty. Earlier this year, BP and Adnoc also agreed to form a JV in Egypt to develop gas assets.
Rising RNG Consumption
The London-based major continues to build out its alternative energy options, in part to take advantage of growth in the use of renewable natural gas (RNG) or biogas. BP is the largest RNG producer in the United States through the Archaea business unit.
Archaea has started up four plants, including the largest to date outside of Kansas City.
There is solid growth in the use of “biogas to decarbonize,” CFO Kate Thomson said. “We're also confident on the supply side. We brought online four plants in the first quarter of the year. So that's roughly around 4 million MMBtus of high margin RNG.”
Two RNG projects now are undergoing commissioning, with start up in the next few days. Another two RNG facilities are scheduled to be in-service in August, Thomson said.
“So we're making progress in bringing those parts up online.” A Henry Hub gas price of $3 “is probably a little bit optimistic at the moment. But if it were – and we were looking at placing our RNG into the transport market with winds at $3 – we actually sell that RNG for 10 times more the value of Henry Hub.
“That just gives you a sense of the value in that portfolio.”
Thirty additional biogas plants are scheduled to be online by 2025.
BPX Energy, the Lower 48 arm reported natural gas production averaged 1.53 Bcf/d in the second quarter, versus year-ago volumes of 1.31 Bcf/d. Total hydrocarbons output averaged 440,000 b/d from 358,000 b/d.
For its U.S. onshore gas, BP fetched an average price of $1.24, compared with $1.60 in 2Q2023. Hydrocarbon prices overall averaged $24.36/boe, versus the year-ago price of $22.13.
BP reduced its average Lower 48 rig count during the second quarter to nine from 11 in the year-ago quarter. In addition to the one rig working in the Haynesville, BP had four active rigs on average in both the Eagle Ford Shale and Permian Basin.
Underlying replacement cost profit, similar to U.S. net earnings, was $2.8 billion (16.61/share) in 2Q2024, compared with $2.6 billion ($14.77) a year earlier.
