(Reuters) - Huge writedowns on natural gas fields point to cuts to come in oil and gas producers’ reserves from untapped fields at the end of this year, which will constrain their ability to borrow and may herald more asset sales.
Bank loans are a lifeline for the many smaller U.S. exploration and production (E&P) companies that rely on debt to cover their drilling costs.
Several indebted producers, under pressure from low gas prices, took writedowns on the value of gas still underground because prices are down by a third from last year.
Ultra Petroleum Corp UPL.N took a writedown of $1.1 billion, or equivalent to a third of its stock market valuation, while Quicksilver Resources Inc KWK.N took an impairment just shy of $1 billion.
A $429 million writedown for Exco Resources Inc XCO.N was accompanied by the Dallas company cutting 140 of its 1,092 workers plus about 160 contractors.
“In any industry, you never want to see this, but you have to recognize that the world has changed for domestic natural gas pricing,” said Eric Gordon of Brown Advisory in Baltimore, which manages $29 billion, with about one-eighth of that in energy.
Most E&P companies tend to outspend their cash flows even when they post profits, buying new fields and investing in new wells to increase output, a key metric for stock market investors.
To fund all that, they rely on debt or new equity issuances, but both of those can be difficult to access when reserves drop.
Still, analysts warn against tarring all E&Ps with the same brush. Exco, Quicksilver and Ultra are more dependent on debt than competitors. Ultra has a debt-to-equity ratio of 4.33, Exco is at 2.39 and Quicksilver’s is 1.58, putting them far above the 0.55 average for the 133 U.S. E&Ps tracked by Thomson Reuters StarMine.
The U.S. Securities and Exchange Commission has E&Ps assess their properties at the end of each year to determine if the resources are economically and technically feasible to extract.
The industry lobbied successfully to change the SEC rule so that, starting in 2009, they could use the average 12-month price to determine whether reserves were economically viable, instead of the end-of-year price that had been required.
The switch could come back to haunt them this year. Natural gas prices tumbled to a decade-low price of near $1.80 per million British thermal units in April before rebounding above $3 last month. Yet as of the end of June, the benchmark price was 35 percent below where it was a year before.
“Most investors have glossed over impairments, but to me they’re a signal about where we’re going with reserves,” said Brian Lively, analyst at Houston-based investment bank Tudor, Pickering and Holt. “These stocks are going to trade more on their resource potential and reserves than on their book value.”
Lively said the extent to which companies must write down proved undeveloped reserves will eventually translate into reduced revolving bank loans, making it harder for them to fund any cash shortfalls.
Exco CEO Doug Miller said on a conference call this month that the job cuts came as it reduced its active drilling rigs to about eight or nine currently from more than 30 a year ago.
But he said Exco had $500 million in liquidity as well as assets it could sell, a move that was likely being considered by several companies in the sector. “It wouldn’t surprise me if you didn’t see $20 billion to $30 billion of transactions the second half of the year,” he said on the call.
Analyst Andrew Coleman at Raymond James pointed out that E&P companies had been adapting fairly well to the era of cheap gas, with no major bankruptcies or truly distressed sales so far.
“We haven’t seen many companies really push the envelope,” he said. “Effectively, their credit card is unused.”
Still, ATP Oil and Gas Corp ATPG.O, a small E&P company, warned it would file its quarterly report late, and Bloomberg reported on August 10 it had arranged debt financing ahead of a possible bankruptcy filing.
Coleman said investors appeared to be sniffing around natural gas stocks now that gas prices were moving higher.
“There’s a little bit of a tailwind - maybe it’s a cross wind right now - but we’ve seen a little bit of interest in the gas names,” he said. “As long as the commodity forward curve is somewhat right, people will look beyond the impairments.”
The average of the first 12 months of gas futures contracts on the New York Mercantile Exchange, or “strip”, has risen steadily over the past two months to more than $3.20.
Coleman said Southwestern looked one of the safest bets for anyone wanting to bet on this nascent natural gas recovery.
Southwestern’s relative financial health even prompted its chief executive, Steve Mueller, to joke at EnerCom’s annual Oil & Gas Conference on Wednesday: “I’m probably going to be one of the few companies today to talk about gas.”
Most E&P executives, on the other hand, have spent the past year playing up their efforts to produce more liquids instead.
Gordon at Brown Advisory, which holds 2.6 million shares of Southwestern, said its prudent spending had set it up well for a recovery in natural gas prices, whereas some of its rivals might even be forced to issue equity to appease their banks.
Coleman went on to single out QEP, with a similar asset base to Southwestern as well as “midstream” gas transportation and storage assets that provide it with a steady stream of fee income to counterbalance the weaker earnings from production.
Reporting By Matt Daily in New York and Braden Reddall in San Francisco; Editing by Patricia Kranz and Matthew Lewis