Extreme winter weather during the first three months of this year helped BP plc grab the upside in domestic natural gas prices, which offset lower returns elsewhere in the group.
BP has been far and away the top physical gas trader in North America since 2002, following the demise of Enron Corp., et al. For 4Q2013, BP reported 23.40 Bcf/d in physical gas sales, a 4% decline year/year, but the No. 2 marketer, Shell Energy North America, traded less than half that amount at 11.80 Bcf/d (see Daily GPI, March 14). BP doesn’t break out trading operation revenue, and it hasn’t yet issued its physical gas volumes for 1Q2014.
“What I would say in terms of the first quarter, it was certainly one of the strongest quarters we’ve seen in over three years, as you would expect with the run-up in gas prices in the United States,” said CFO Brian Gilvary during a conference call Tuesday to discuss quarterly results. The trading arm posted levels similar to those achieved in the year-ago period. Polar weather swept the United States in late 2013 and into March, spiking domestic physical gas prices (see Daily GPI, Jan. 28).
In the Lower 48 business, an additional $300 million year/year was captured on physical gas gains.
“There’s no question we were able to capture the upside in the gas prices for the first quarter, and in terms of cash flow for that quarter as well,” Gilvary told analysts. The gains came despite BP writing off $521 million in the quarter on its Utica Shale acreage in Ohio. “We’ve been able to capture the U.S. side, notwithstanding of course the Utica write offs that fit in the Lower 48 box.”
BP’s writedown in the Lower 48 play follows a $2 billion write off last year by Royal Dutch Shell plc, and another $631 million charge earlier this year on domestic properties (see Daily GPI, March 13). The BP charges followed a decision in March to create a separate business for Lower 48 oil and gas activities (see Daily GPI, March 4). More information on the spinoff/separation is expected by midyear, said the CFO.
However, whatever changes are made to U.S. oil and gas production activities won’t impact the prosperous physical trading arm, Gilvary told analysts.
“From BP’s perspective, the reason why we’re there in the first place is because we have big major flows of oil and gas, and therefore the first role in our trading business is to make sure they get balanced and ensure our refineries get the best price for crude inputs and upstream gets the best price. That’s the primacy of why we have that. Of course, it does, from time to time, take on positions, entrepreneurial positions, that allow us to be able to benefit in the marketplace through positions that we have.”
The first quarter’s results were strong, he said, but “I think if you look at the volatility of the earnings over the last two or three years, a lot of that has been driven by the volatility of the absolute [gas] price itself.”
Unlike financial institutions, “we don’t trade outright flat price,” said Gilvary. “We tend to trade a commodity versus another commodity because we have a point of view on that. I think what you’ve seen is a lot of change in the space itself in terms of people entering and exiting the market. We’ve seen a number of new entrants, which is good for liquidity reasons. But I think at the end of the day, it’s been a strong quarter, both in the oil and the gas piece. Convert the first quarter to last year, and that was also a strong quarter” for the trading arm. “So the delta…isn’t that large this quarter versus the last year because we’re also having a good set of results from the trading business.”
Gas trading “is something that we will continue to invest in going forward. In terms of linking back to our asset positions, we can also, of course, sort of replicate those through leasing our own storage…in both oil and gas. So it doesn’t absolutely rely on the asset base in place.”
As far as where the trading arm ranks in terms of the return on capital, Gilvary said it depended “on the nature of the business and how long you’ve been in the business, the continuity of that business…portfolio changes,” which play to BP’s strength.
“We look to ensure that the returns that we get in the business are accretive to the group. So if you look at where the group is,” given the “risk-adjusted return typically in this space, you’d be wanting that to be significantly higher than the average earnings for the group on a risk-weighted basis.”
BP also continues to produce domestic natural gas and is exploring acreage that others have of late ignored because the company has plenty of infrastructure to back up its positions.
“Part of the question has to do with scale of operations in the various areas,” as to where BP deploys dry gas rigs, said CEO Bob Dudley. “Certainly, with scale like we have in San Juan, it produces high rates of production but it’s pretty dry gas. I think that obviously, the first thing we’re interested in is our liquids because that’s where most of the value is.” Gas-rich production areas “like Wamsutter, where we get a reasonable amount of liquids as well, 40% liquids, we’ve got three rigs running there. We don’t have that many [dry gas] rigs running in North America.
“We’ve got three in Wamsutter; we’ve got two running in the Haynesville, which is only about 20% liquids. But, we’ve got to restructure that business to get the cost and then let the business itself look through the Wamsutter, the San Juan, the Anadarko, Woodford, etc.” The restructuring with the new E&P entity would determine which direction Lower 48 business goes.
“We have delivered a solid start to the year, which puts us firmly on course to deliver our 2014 goal of delivering $30-31 billion of operating cash flow,” said Dudley.
“It’s a little premature at this point” to detail the projections for the Lower 48 business “because it was only a month ago that we announced it,” Gilvary said. However, the upstream team led by Lamar McKay is revolving “around what the new governance model looks like, all of the various internal announcements, what that means in terms of sizing the organization…”
BP as of last year had sold about $38 billion of assets to help defray the costs of the Macondo well blowout in April 2010. It is planning to sell another $10 billion of assets through 2015. All of the sales punched net profits, evident in the quarterly results. Production in 1Q2014 dropped 8.5% year/year to 2.13 million boe/d. Second quarter production also is expected to be lower.
“We are continuing to simplify,” Dudley said. However, exploration and production spending in 2014 should fall 1% from 2013 on efficiencies.
BP reported replacement cost (RC) profits of $3.48 billion in 1Q2014 versus $16.6 billion in the year-ago period. However, 1Q2013 results included $12.5 billion in profits from the sale of a stake in Russia’s TNK-BP.
Excluding the TNK-BP sale, quarterly earnings fell 23% to $3.23 billion (17.5 cents/share) from $4.22 billion (22 cents); they were 15% higher than in 4Q2013. Revenues slipped to $91.71 billion from $94.11 billion. RC profit strips out inventory gains/losses, similar to net profits in the United States. Operating cash flow was more than double that of a year ago at $8.2 billion from $4.0 billion.
Compared with the year-ago first quarter, BP’s result reflected higher costs, mostly noncash, in the upstream business, a weaker refining environment and lower production because of asset sales. Although it had lower costs and a big trading contribution, results were partly offset by a reduction in BP’s share of earnings from OAO Rosneft because of recent weakness in Russia’s ruble, and the absence of one-off benefits to BP’s share of Rosneft net income in 4Q2013.
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