Global natural gas markets are likely to remain tight through the winter, with oil prices continuing to climb as well, BP plc executives predicted on Tuesday.

Henry Hub Prices

CEO Bernard Looney was joined in a conference call by CFO Murray Auchincloss to discuss the London-based integrated energy major’s third quarter results and the near-term outlook. 

“It was a great quarter for production, a great quarter for realizations…a strong quarter for gas trading as well,” Auchincloss told investors. BP, the reigning largest natural gas trader in North America, continues to see its earnings “enhanced” by 2-3% a year because of its trading unit.  

“Henry Hub averaged $4.30, up from $2.90 in the second quarter as capital discipline continued to limit U.S. gas production growth and Hurricane Ida led to production curtailments,” the CFO said.

International gas prices, which were up in the quarter by around 5% sequentially, reflect the tight liquefied natural gas (LNG) market, Auchincloss said. The pressure is coming from “strong Asian demand growth, LNG supply outages, depleted European gas storage and uncertainty of Russian pipeline imports

“We expect gas markets will remain tight during the period of peak winter demand.”

Surging oil prices also reflect the “strong rebound in demand,” as pandemic measures ease. 

“As we look ahead to the end of the year, we expect oil prices to be supported by continued inventory drawdown, with the potential for additional demand from gas-to-oil switching,” Auchincloss said. 

No Kvetching By Shareholders

While ExxonMobil and Royal Dutch Shell plc are being pressured by investors to revamp their portfolios, Looney said there’s been scant rebellion among BP shareholders. He credited the company’s early move into alternative energy, where it has a plethora of partnerships and projects underway to cut emissions. 

“We’re investing in the transition with discipline, step-by-step,” Looney said. “Shareholders increasingly like what we’re doing, so we’re encouraged.”
BP rebranded itself from oil and gas major to become an integrated energy company last year, “because we believe deeply in the premise of…not only helping the world transition, but importantly to create value from that transition.”

The reason is twofold, Looney said.

“No. 1, we need cash flow to invest into the transition, and our existing businesses generate enormous cash flow….Adjusting for working capital, we had close to $8 billion of operating cash in this quarter.”
Meanwhile, some pure-play renewables companies are “struggling to fund their growth. That’s not a problem that an integrated energy company will have, and it’s not a problem that we have.”

The second reason centers around BP’s abilities, said Looney.

“What other company can take natural gas, build a power station, capture the carbon, take it offshore, store it underground? What other company can take and build offshore wind, build a hydrogen facility on the back of it, take that electricity and put it into the largest charging network in Britain?” 

BP concurrently clinched a deal with Germany’s Daimler AG to explore the potential for hydrogen trucking infrastructure in the UK, and it signed an agreement in Aberdeen, Scotland, to look at hydrogen for public transport. 

“And at the same time, we have a trading business that can help customers hedge and plan and have predictable and reliable sources of energy,” Looney said. “So, as the energy transition becomes clearly more complex, I think in people’s minds, I think the role for a company like BP becomes clearer and clearer by the day.”

How Much Oil And Gas Is BP Producing?

BP during the quarter hit its six-year program target for major project execution, on average around 15% under budget. This year alone BP has  brought online 900,000 boe/d.

Six major projects have ramped to date this year, including two in the third quarter: Matapal, offshore Trinidad and Tobago, and Thunder Horse South Expansion Phase 2 in the Gulf of Mexico (GOM).

Upstream production rose by 4% sequentially. Natural gas production increased year/year to 4.52 Bcf/d from 4.34 Bcf/d. Liquids output climbed to 109 million b/d from 92 million b/d. Total hydrocarbon production was 889 million boe/d, versus 841 million boe/d in 3Q2020. 

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BP fetched an average realized natural gas price of $5.26/Mcf in 3Q2021, compared with $2.99 in the year-ago period. For its liquids output, realized prices averaged $66.39/bbl from $37.77 in 3Q2020. 

The BPX Energy unit, which comprises the Lower 48 business, saw its output fall overall year/year. There were six rigs on average working across the onshore, with two rigs each running in the Permian Basin, Haynesville and Eagle Ford shales. Only one rig was up in 3Q2020.

Production in the Lower 48 decreased year/year in 3Q2021 to 322,000 boe/d from 365,000 boe/d. Natural gas production declined to 1.12 Bcf/d from 1.28 Bcf/d, while liquids output fell to 130,000 b/d from 144,000 b/d. 

BPX realized gas prices averaged $3.53/Mcf in the latest period, versus $1.28 in 3Q2020. Liquids prices averaged $52.25/bbl from $25.74. 

While output was down, the Lower 48 business is “core” to the portfolio, Auchincloss said, “from reducing emissions, reducing flaring, reducing methane and driving profitability.” The reduced U.S. production followed a “lack of investment” in the Lower 48 as BP reduced overall spending.

In the Permian, the focus going forward is “building out the infrastructure to make sure that there is no flaring or methane going into the atmosphere,” he said. “As we go into the next leg of drilling in the Permian, we think that’s extremely important for not only the environment but also for profitability.”

Mismatch In LNG Contracting

Under International Financial Reporting Standards (IFRS), similar to U.S. GAAP, aka generally accepted accounting standards, third quarter losses were $2.5 billion, versus a year-ago loss of $450 million. 

Adjusting for fair value of accounting effects of $6.1 billion, primarily from increases in forward natural gas prices, BP’s underlying replacement cost profit in 3Q2021 was $3.3 billion ($16.48/share), compared with $86 million (42 cents) in 3Q2020.

“Under IFRS, reported earnings include the mark-to-market of hedges used to risk manage LNG contracts, but not the physical LNG contracts themselves,” Auchincloss noted. 

“This mismatch at the end of the third quarter is expected to unwind if prices decline and as cargoes are delivered. The underlying result removes this mismatch, consistent with how BP risk manages its LNG portfolio.”

Even against the “backdrop of higher commodity prices, we remain focused on capital discipline and our third and fourth priorities for capital expenditure remain unchanged,” said the CFO. “We continue to expect to spend around $13 billion in 2021.”

Taking into account the “cumulative level of and outlook for surplus cash flow,” the board  “remains committed to using 60% of 2021 surplus cash flow for share buybacks and plans to allocate the remaining 40% to continue strengthening the balance sheet.”

In the final three months of 2021, BP’s upstream production is expected to be higher sequentially. The increased output reflects “major project ramp ups, mainly in gas regions, recovery from seasonal maintenance activity and continuing impacts from Hurricane Ida on our nonoperated production in the GOM…Within this, we expect production from both oil production and operations, and gas and low carbon to be higher.”