Fall-season, borrowing-base determinations are ahead, and many lenders and E&P operators expect these to be tougher than this past spring, should sub-$60 WTI persist.

Law firm Haynes and Boone LLP surveyed 88 financial institutions, private-equity firms and producers in April. Among them, 63% expected borrowing bases to be decreased this past determination season and that the average decrease would be 25%. Only 19% of borrowers would be cleared to skip the spring meeting, they expected. Further, they predicted borrowing bases would be cut another 31% in the fall.

Mark Thompson, US Bank senior vice president and manager of its energy-industries division, has seen oil price downturns beginning in 1980. “I count at least eight major ones—ones noticeable enough for producers to make adjustments and for us to make adjustments,” he said.

The Denver-based bank participated in some 150 facilities five years ago; today, primarily as a result of producer consolidation, it participates in 125. Commitments total $5.4 billion with about $2.2 billion outstanding among them.

Overall, E&Ps have had a fairly smooth ride through the spring redetermination season.

“We tend to focus more in the higher-credit-quality deals and tend to avoid weaker credit structures—too much leverage, second-tier management teams operating in second-tier areas, that kind of thing. So we feel our client base is pretty solid,” Thompson said.

Many are well-hedged this year, and nine have raised cash through equity offerings, “which is remarkable when you think that they are issuing equity at a time when their stock price is near recent lows. They feel they need to assure the survivability of their business, regardless of where oil and gas prices go.”

Mike Lister, managing director and head of energy corporate banking for J.P. Morgan, counted $11.7 billion of equity issuances by E&Ps this year through early April in his presentation to Hart Energy’s Energy Capital Conference attendees. High-yield offerings totaled $6 billion. His expectation for the fall was for borrowing bases to face more pressure. Lenders will be focused on the following, he added: asset coverage, 12-month liquidity, covenant compliance and leverage, the client’s access to equity and unsecured-debt markets, and its ability to sell assets.

Could more money flowing to E&Ps prolong the cycle? Thompson said, “I think that is a very valid concern. We could very well be looking at a situation similar to what we saw with natural gas prices, beginning in 2012. They have not recovered robustly.”

Like natural gas, the limit to how much U.S. oil can be produced now from shale plays is not yet defined. “The only thing governing how much output we generate is oil and gas prices themselves.”

He wasn’t optimistic about WTI improving to $100 again. “It is a fairly big gamble to be counting on that.” Some E&Ps were too deep in the hole at $59 at April-end and might not exist at year-end, he said.

Those that may make it to the other side of this downturn are those questioning assumptions that WTI will rebound quickly, he said. These include the E&Ps that have “taken the painful step of going to the equity markets to de-lever.”

Mark Thompson, US Bank senior vice president and manager of its energyindustries division, expects the fall season will include a good look at how producers’ reserves add up after cutting their capex.

A continued low oil price, high leverage and few hedges “continue to compound. Liquidity is the name of the game,” said Tim Brendel, Houston-based senior vice president and oil and gas segment leader for Associated Bank.

Like Lister, Thompson expected the fall season will include a good look at how producers’ reserves add up after cutting their capex. Lister estimated global E&P spending has been cut 28% this year to $104 billion.

Also, Thompson noted, 2015 hedges will be rolling off. “The value they are getting for their 2015 hedges will, for the most part, be gone; and they’re not very well hedged into 2016. So these would suggest that the fall season is going to be harsher on those companies than this spring season.”

Lister reported that a J.P. Morgan survey indicated large-cap producers had, on average, 3% of their 2016 production hedged and none in 2017; among mid-caps, 24% and 2%; and, among small caps, 29% and 7%.

Regulators

During the 2008-2009 downturn, energy companies were pleasantly surprised by lenders’ ability to work through the cycle. Thompson said part of this was because bank regulators were more focused on the financial crisis—primarily, mortgage lending. Now, they’re focused on energy lending.

“They may have something to worry about with some of the smaller banks who have a relatively high percentage of their portfolios centered in the oil and gas industry and, more significantly, with the oilfield service business, which is really going to suffer, relative to producers.”

Tim Brendel, Houston-based senior vice president and oil and gas segment leader for Associated Bank, was at Union Bank of California during the 2008-2009 cycle. Bank regulators are not dealing with an overall financial recession this time, he said. “Back in 2008-2009, they had bigger fish to fry; we’ve noticed a bit more of a spotlight on the oil and gas industry during this cycle.”

The Wisconsin-based bank, which opened its oil- and gas-lending office in January 2011, has some $28 billion in assets and some 50 E&P clients with about $1.1 billion committed. Its portfolio consists of loans of $25- to $35 million for starters and it can take that, at times, to $50 million. Most of its clients were doing well, he said in April. “There are a few we’re paying more attention to and helping them help themselves.”

Those that are looking a bit under water primarily are highly levered and less hedged. A continued low oil price, high leverage and few hedges “continue to compound. Liquidity is the name of the game.”

Moody’s Investors Service vice president and senior analyst Amol Joshi noted in a report that Energy XXI Ltd. issued $1.45 billion of second-lien notes to pay part of its first-lien bank debt and have more cash on hand. “In severely stressed situations, companies can also attempt distressed-debt exchanges,” Joshi added, “to correct unsustainable capital structures or alleviate liquidity pressures and try to survive ….” But it is at a great expense to existing bondholders. “We consider a distressed-debt exchange to be a default.”

Brendel said, “We have the ability to be patient with our clients if we’re seeing a good plan in place to fix their issues.”

At some point, a bank may exhaust all it can properly do. “You hit the key word: ‘properly.’ Obviously, we’re a regulated bank, so we’re certainly being prudent in making sure our shareholders are protected. But we’ve been around long enough to know we don’t operate oil and gas properties well; oil and gas operators operate them well.”

Proactive conversations with clients have helped, “so they can go out and find any additional liquidity they need.”

Asset sales

Asset sales are likely should the low oil price persist. “We’re hearing that acquisition teams are getting busier. The fall borrowing-base season could create more potential assets on the market,” Brendel said.

Sanchez Energy Corp. sold nonoperated, PDP wells to its Sanchez Production Partners LP for $83 million in cash and $2 million worth of SPP units. Simmons & Co. International Inc. analyst Brian Gamble reported, “The deal is a creative way to finance Sanchez Energy’s operations and bring value forward from existing producing assets, allowing further development of other properties.”

The deal explained why Sanchez had not sold equity while other producers had been, he added. “This financing avenue enables some semblance of capital infusion without the dilutive effects to current shareholders.”

Even a major, Chevron Corp., is raising money via divestment. It sold its 50% interest in Australia-based downstream operator Caltex Australia Ltd. for $3.5 billion. Simmons analyst Jane Trotsenke reported, “As we have reported, asset sales are increasingly being viewed as a structural element of the funding mix across our major-oils coverage universe, necessary to help bridge shortfalls between operating cash flow, capital spending and dividend obligations.”

She expected Chevron’s cash flow to be $24 billion short of its 2015 capex and dividends.

Brendel said potential buyers may include those who’ve issued equity so far this year. “The strong will survive and will, ultimately, be the consolidators. That’s the beauty of the business we’re in. These cycles create opportunity. Those with liquidity will have the wherewithal to get in at a lower cost basis in areas like the Permian Basin or Eagle Ford than a year ago.

“They’re licking their chops for those opportunities.”

BreitBurn Energy Partners LP sold $350 million of perpetual convertible preferred units to EIG Global Energy Partners and $650 million of senior secured notes to EIG and others. The cash will fund acquisitions, reported Hal Washburn, BreitBurn CEO. He added, “Through our 27-year history, we have emerged from each, prior downturn a much stronger company and we expect to continue this track record.” The net proceeds of $938 million reduced its bank draw to $1.24 billion; its base was revised to $1.8 billion.

Brendel said Associated Bank’s deck is actually closer to strip these days than last year. “Some of that is a function of, when oil is $100 a barrel, there is much more downside risk than after it’s fallen off 50%.”

This is the first downcycle in Associated Bank’s energy-lending office. Brendel said it is an opportunity to earn long-term franchise value. “We didn’t get in this business just to get out of it in the first cycle. We see this as not the time to pack up our tent. This is when you can earn an energy-savvy reputation and credibility in the market.”

Spring was worse?

Having come up in the oil fields of East Texas, Steve Kennedy has seen five decades of oil price cycles. His grandfather had one of the 24 wells on what was deemed “the world’s richest acre” in the era preceding Texas well-spacing rules. Like then, U.S. production that exceeds demand has returned.

“Fortunately, the oversupply is 1.5% to 2%,” said Kennedy, Amegy Bank executive vice president and manager of its upstream and midstream office. “It’s a much smaller problem than at times in the past.”

He conceded that the possibility exists but does the math. “We’re starting with about a 2% oversupply. It’s not a big number to work down. We also do not have a lot of excess production around the world that can be brought on to make the situation worse.”

Spare capacity is some 3 million barrels a day. At times in the past, 10- to 12 million were on standby. Also, “we were only consuming 60 million barrels a day then; today, we consume 92 million a day. And we have less than 3 million barrels of standby.”

Steve Kennedy, Amegy Bank executive vice president and manager of its upstream and midstream office, said that hedges, “while meaningful, are a small part of the equation when you look at the value of the company’s reserve base.”

Economic disaster could prolong a low oil price, but none is looming. Meanwhile, demand continues to grow. “That’s why I’m optimistic this is not going to be a multi-year cycle,” he said. Lifting the Iranian oil sanctions, however, would be one event that “could cause this to last much longer.”

He didn’t expect the fall season to be painful. “I understand people who are saying that hedges will roll off and that will tend to affect some value but, in many cases, the hedge may only affect a small portion of the value.” Kennedy and his colleagues look at the company’s years of production—at times, more than 20 years. The hedges, “while meaningful, are a small part of the equation when you look at the value of the company’s reserve base.” In the spring, the value of companies’ reserves declined tremendously; hedges rolling off are small in comparison.

Amegy’s clients have responded aggressively, he added. “They’ve done it to a degree we didn’t expect—rig counts dropping, capex being cut back to levels that would send a signal to the market that supply is going to correct in the U.S. as quickly as anyone could envision. They haven’t wasted any time.”

The bank has about 260 energy clients with some $4.9 billion of commitments to these; among them, about 40% are E&Ps. Its loans or participations range from $25- to $75 million. It may hold 100% of loans of $10- to $25 million; if more, “we would bring in other banks.”

Its midstream portfolio is strong; its oilfield service clients are suffering more than producers, though. “Many of these companies have a decrease in business and are also suffering from having to decrease their prices. In some cases, we’ve seen their EBITDA drop between 25% and 60%. They will take the longest to recover.”

Alabama-headquartered Regions Bank had $3.3 billion in energy loans outstanding, including $1.2 billion in oilfield services, $1.1 billion in E&P and the balance in midstream as of the end of the first quarter. It reported this spring, “Approximately 80% of the OFS portfolio was reviewed during the quarter, with 25% of the credits reviewed having had risk-rating downgrades since year-end, and the loan-loss reserve level reflects this action.”

It has more than 200 energy and natural-resources accounts under active coverage; about 65 are E&Ps. Most of its book is syndicated. Its OFS clients are “fighting to live another day,” said Brian Tate, Regions executive managing director and head of its energy and natural-resources group. “They are price-takers in times like this. But, even there, I have been impressed. For our E&P clients, it’s been a very smooth redetermination process thus far. For starters, we only bank the strongest and most were flush with cash going into the downturn.”

J.P. Morgan estimates banks were working with a lower deck to Nymex WTI on a percentage basis in January than in December. Also, no matter the Nymex price, banks have consistently worked with a sub-$90 deck.

Could take longer

Tate began his energy-banking career with Chase in 1991 in its global energy group. From there, he joined First Union Securities, which became Wachovia and then Wells Fargo. He joined Regions in 2014 and is based in Charlotte, North Carolina.

The bank’s clients are exclusively those with management teams that have worked through many price cycles, he said. Fortunately, he added, equity and public-debt markets have been open to upstream operators. “In the past, banks were the capital providers that stepped in during a crisis but, with regulatory reform, that’s kept the banks sidelined on this go.”

Different this time as well is that it is the first downturn in the era of U.S. tight oil production. “It will be interesting to see how the shale industry navigates through all this, but the capital markets are very liquid,” Tate said.

Among Regions’ E&P clients, their borrowing bases have been reduced some 20%; availability is averaging 40%. Tate suspected this is only the third inning of this cycle. “Downcycles in oil tend to be self-correcting in 18 months or so. I’m hopeful, but it could take much longer.

“Our clients have to plan for the worst and hope for the best.” Several are layering in hedges, even at sub-$60 WTI. “They prefer hedges at a higher price point, of course,” Tate said, “but they’re looking at mitigating their downside exposure.” Most are more than 50% hedged this year; the amount declines to some 25% in 2016.

Leading into mid-2014, producers were looking at a backwardated WTI market. For example, the January 2016 contract for WTI at Cushing was trading at about $82 in January 2014, while the prompt-month contract was $94. This past April, January 2016 WTI was trading at about $63 in contango of the prompt-month contract of $59.

Tate’s outlook for upstream consolidation is that there will be some, and should the cycle extend beyond 18 months, there may be a great deal. “The bid/ask is still too wide right now, and part of that is due to hedges that existed. But there is a lot of chatter about it, looking into 2016 and the spring season, when hedges are rolling off very dramatically.”

Brian Tate, Regions Bank executive managing director and head of its energy and naturalresources group, said the bank’s E&P clients have had a “very smooth redetermination process thus far.”

Fitch Ratings was grading E&P companies’ debt in late April on $50 WTI this year, $60 next year and $75 in 2017, it reported. Fitch senior director Mark Sadeghian added, “Liquidity is going to be a defining metric for E&P firms this quarter. While most investment-grade names will be fine on that front, MLP-type asset sales could provide supplemental liquidity until prices come up. However, high-yield E&Ps, especially B-rated names, are probably grateful there is more than one way to ‘10.’

“Those companies will need to utilize a bigger set of tools, including equity raises or additional secured financing to get through the price dip. In the meantime, our eyes will be on capex—not only for companies with reduced free cash flow, but also for its impact on production and strategic positioning.”

US Bank’s Thompson said, “We’re in an unusual environment as banks because we’re using a fairly steep contango price curve. We have a disconnect between valuations and what is really going on with this year’s low oil prices. Our collateral values are staying fairly firm and not creating any concern for us.”

Instead, concern is with weak cash flows “and what the implied cash-flow leverages are going to be for some of these companies. A company operating at 3x cash flow leverage last summer may be 9x levered now.”

Selling nonstrategic properties is a traditional option. “It’s still a seller’s market, even in this low-price environment.” Others may sign JVs, while cutting administrative and operating expenses. Some are suspending drilling entirely.

One of US Bank’s clients told Thompson that he didn’t have any leasehold that could generate the kind of return at $50 a barrel that paying off debt could generate. “In other words, he is better off taking the little free cash flow he has and paying down debt than drilling his best prospects and producing his flush production into a low-oil-price environment.”

Other clients are successfully renegotiating their oilfield service contracts to keep up some level of drilling activity. “Some companies I’ve talked to are in Round Three of these renegotiations,” he said.

Some will have to take more dramatic action to de-lever, including selling some strategic properties. Some may have to merge with a stronger company. “We’re seeing some of this. We may see more of this later this year if low prices persist,” he concluded.