Reading the Energy Book

With volatility in crude oil, natural gas prices dipping below $2 per thousand cubic feet earlier this year, and European financial turmoil prompting the sale of a major French bank's energy book, you might imagine that commercial bankers in energy are tightening their seat belts for the ride ahead. Well, not exactly. Energy loans have, in many cases, grown with the industry's liquids-oriented resource plays. Visibility for loan demand is reasonably good, and what speed bumps may lie ahead aren't serious enough to threaten suspensions.

Mark Fuqua, senior vice president of energy lending for Comerica Bank in Dallas, says recent strength in commercial lending activity reflects the industry "spending so much money, thanks to the higher oil prices and improvements in technology through fracing and horizontal drilling with the emergence of oil and liquids-rich shale plays." Shale plays have "changed the landscape," agrees Mickey Coats, executive vice president, energy lending, at Bank of Oklahoma in Tulsa. With much higher well and lease-acquisition costs than previously, it's "a big boy's game."

Mark Fuqua, senior vice president of energy lending for Comerica Bank in Dallas, says that oil and gas “is one of the few industries around the world right now that is really thriving.”

Fuqua says that oil and gas "is one of the few industries around the world right now that is really thriving." Financial woes overseas have resulted in "some transition from international players that maybe aren't as aggressive or have withdrawn. But you have other domestic and international players that have stepped up and filled the void."

Notable in February was Wells Fargo's purchase of BNP Paribas' North American energy lending business, involving $9.5 billion of loan commitment ($3.9 billion in loans outstanding), as the French bank sought to shed assets in order to strengthen its Tier 1 capital ratio.

Favorable industry conditions are evident in the year-over-year growth in some banks' energy books. Comerica had average loans outstanding in its energy portfolio of $2.5 billion as of June 30, 2012, representing "substantial" loan growth from a year earlier. Bank of Oklahoma points to energy loans outstanding of $2.2 billion, up $500 million from a year ago. Bank of the West, based in San Francisco, has seen growth in energy lending in the "range of 20%," says senior vice president, Todd Berry-man. And BB&T Capital Markets, which expanded into the Texas market in 2009 from its North Carolina base, has seen loans outstanding grow to $601 million from some $400 million at year-end 2011, according to senior vice president Jeff Forbis.

Fuqua describes energy as "a huge economic engine right now for the country," and in terms of sustainability, suggests the sector "feels like it has good fundamental strength under it. It feels like it is longer term, not just driven by short-term factors."

Berryman predicts there is likely a five-year favorable trend for energy, with smaller energy companies facing fewer obstacles in obtaining loans than in the past. While Forbis acknowledges he has seen some slowing in the pace of transactions in the current year, it is in the context of 2011 having been an "incredibly active year," and he thinks pent-up demand may make 2013 another active year.

Banks are gradually increasing their price decks for gas.

But what about the ongoing struggle with low natural gas prices? A whiff of caution is suggested by the rules applied by the Securities and Exchange Commission to public companies in the form of quarterly ceiling tests for those E&Ps using full-cost accounting. Further impairment charges are looming in the second half of this year, as the net book value of assets are compared to the cash flow PV-10 of proved properties—but using significantly lowered natural gas prices in estimating reserves. (These impairment charges are noncash in nature.) Significantly, while noncash, such impairments foreshadow the exposure of gas-levered E&Ps to potential year-end reserve writedowns, with a particular focus on proved undeveloped properties (PUDs).

For public companies, year-end pricing used in determining reserves is calculated based on an arithmetic mean of Henry Hub pricing, taking first-day-of-month pricing for each of the prior 12 months. For the first nine months of 2012, the average has been less than $2.70 per Mcf; as a result, even in the event of a significant recovery in pricing in the final three months, the average price at year-end stands to be far below last year's $4.15.

Shale plays have “changed the landscape,” says Mickey Coats, executive vice president, energy lending, at Bank of Oklahoma in Tulsa.

So how do the banks view these signals as they look at likely year-end reserves and possible adjustments in upcoming borrowing base redeterminations?

On the ceiling test issue, says Coats, "that's a balance-sheet item, and if they write down values of reserves on their balance sheets, that really doesn't affect me as far as what I am going to lend them. It doesn't really affect their cash flow. I am a cash-flow lender. I want to know what the current cash flow is and what we project it to be." The bank lends a maximum 10% of underlying value on PUDs.

On potential reserve writedowns, says Fuqua, "if it is strictly price-related, and we feel that the quality of the nonproducing reserves are still really good, then we don't worry too much about the losses that might be taken under GAAP (Generally Accepted Accounting Principles). But if the lower price deck basically wipes out their PUDs on our own forecast, then we are not going to be able to lend them as much money. We are probably more focused on what it does to our engineering values than on writedowns that they may take on their financial statements."

Banks are holding the line on their forecasts for oil.

Hedges rolling off have put pressure on some gas-levered companies. "But," notes Fuqua, "it has been amazing to me to see how many of the companies have adjusted by re-orienting their drilling away from dry gas to oil or liquids-rich gas. I keep thinking I'll get reserve reports that will be way down, but they tend to be either up or stable because of the oil or liquids-rich drilling that they have been doing."

In essence, energy lenders are their own masters, able to use commodity price decks of their making and not infrequently employing inhouse reserve engineers. Bank of Oklahoma develops an internal price deck which it changes monthly, and has in-house engineers in all seven of its offices. The company has a 100-year history as an energy lender and, given its location and surrounding reservoirs, has historically had a loan portfolio tilted to gas. As elsewhere, clients have tried to be nimble in migrating to oil and liquids-rich plays, "but not everyone has," says Coats. "And unless they have long-term hedges, they're really stuck."

With upcoming borrowing base redeterminations in mind, Coats recalls how "last year, you heard a lot of noise about: 'Oh, gosh, it's an all-gas customer, the banks are going to pull the trigger on them and there's going to be a lot of asset sales.' But it never really materialized and, frankly, I don't know that it will at this fall redetermination. If you have any oil at all, you're probably O.K." The bank, like others, has a handful of smaller deals that are mainly dry gas. "But I don't see any of them requiring us to foreclose and sell the assets. And, obviously, that is the last thing we want to do, anyway."

Most of Bank of Oklahoma's growth this year has come from participating in some of the larger credits led by bigger agent banks. In addition, it will run single-bank deals, typically in the $5- to $10-million range. An exception is a much larger deal, approaching $500 million, for which the bank served as agent bank in connection with the acquisition by Unit Corp. of $600 million of properties in the Midcontinent from Noble Energy.

Like Bank of Oklahoma, BB&T (established 1872) came with a long history when it expanded into Texas in 2009. Forbis, who joined in early 2011, says the firm's strategy as a participant bank is to take $25- to $100 million in a number of the larger syndicated transactions. Some early bank borrowing resets have already taken place, he says, and "for the most part, unless there has been some really robust drilling in a liquids play, we're just seeing status quo on borrowing bases where we are reaffirming at the current level." The bank lends a maximum 10% of underlying value on PUDs.

A couple of cases have seen decreases, however, reflecting lower price decks "and the inability of our clients to hedge that away." Forbis says that almost all its borrowers hedge out 80% and 50% to 60% of years 1 and 2 production, respectively, often adding further positions during the year.

"These guys try to insulate themselves from our price decks by virtue of their hedging." Adjustments to borrowing bases are such that "you rarely get a big step function," he notes.

"You're able to incrementally ratchet credit to the proper level given the underlying collateral value." In addition, there's some "inertia in the price decks. Just because prices have fallen doesn't mean you're going to chase those prices down. You are going to moderate them."

Bank of the West has a loan portfolio split roughly 50:50 between E&P/midstream and service/transportation. Berryman sees a trend of increasing competition among the largest energy lenders, while smaller banks are likely to have greater capacity to resume energy lending now that many of their real estate travails are behind them. Berryman doesn't anticipate any borrowing base reductions, in part because of lowered commodity price decks in late 2011. In addition, E&Ps have learned how to use credit more sparingly and, when they do, are more likely to time flush production such that it hits a robust commodity market.

Bank of the West, based in San Francisco, has seen growth in energy lending in the “range of 20%,” says senior vice president Todd Berryman.

When can we expect a robust commodity market, at least for natural gas? The answers vary. And the question drives at the heart of the reserve question, focusing on how PUDs are treated at year-end, and how much, if any, economic value they should be accorded.

Forbis says he is long-term bullish on gas, but offers plenty of short-term caution.

"I really think it is three to five years before we see any return to prices north of $4 that are sustained over a long period of time. Once prices start to inch back up, people are going to go out and start drilling in the Haynesville again and start turning on all these other gas wells. That means all those gas-fired projects are going to need to come on line to provide sustained demand for what can be a boatload of gas that is sitting dormant." Bottom line: "Don't be overoptimistic on gas prices, because they are going to be soft for a while."

Of course, softness in gas markets—if that is what unfolds—doesn't augur for gas PUDs remaining unscathed, especially if gas prices drop further. Forbis recaps: "Let's look at gas reserves that are expensive to produce. If you throw in lower gas prices, certain reserves will just drop out of the report altogether, because whatever price you are using doesn't warrant the drilling and development of those reserves.

"The Haynesville is a great example," he says. "If I tell you that you've got to use $2.25 per Mcf to value those reserves, few areas in the Haynesville are going to be economic at $2.25. And, as a result, those PUDs will just evaporate."

In a downside case, as above, how have E&Ps managed through the gas morass? Fuqua notes that at the same time that borrowing bases may potentially be impacted by a reduction in value and the number of gas PUDs, current production is being impacted by a combination of the rolloff of higher priced hedges and lower prices applied to current volumes. "So they're getting hit on both sides," he says. "Generally speaking, managements don't like the situation, but they know what to do and they do it." Methods involve cutting costs, tightening up capex, improving liquidity through noncore asset sales, possible joint ventures, etc.

BB&T Capital Markets has seen loans outstanding grow to $601 million from some $400 million at yearend 2011, according to senior vice president Jeff Forbis.

Conversely, gas bulls may see brighter days ahead. If so, is there appetite in the market for more than just proved producing properties on the gas side? "For many public E&P companies," says Fuqua, "there is such an aversion to gas that even if they saw a sweet gas deal, they might not be inclined to do it, because the market doesn't want them to own gas." Concurs Forbis: "Those guys are on a quarterly treadmill, they have to show how they are improving their company every 90 days, and the way they are doing it is telling investors they are moving to liquids or crude."

Private-equity players, however, may take the longer view. "You probably see more private investors willing to be a little bit contrarian and willing to pay for gas reserve optionality," says Fuqua. "But they are going to be pretty careful, they are only going to do that where the quality of the PUDs is really good, and where there probably is some ongoing cash flow associated with it. Are they going to pay more for gas production that has a lot of upside with PUDs at a higher gas price than they would for one that is fully developed? Yeah, I think they will. But it's not nearly as much as they were paying two or three years ago."

From an industry perspective, lower bank price decks for gas have been on the horizon for some time, allowing E&Ps time to anticipate tightening liquidity and to look at alternatives, such as assets sales, raising junior capital, etc. "I think a lot of the vultures are hoping that the banks are just going to clamp down and start foreclosing, and we would have a bunch of properties they can buy cheaply," says Fuqua. "But I have been very impressed by how quickly management teams have transitioned and done the things they need to do throughout this incredibly volatile period."