The surprise election of Donald J. Trump has added an element of uncertainty in more than one area. News of his win brought a move higher in U.S. Treasury yields and further strengthening of the dollar. Poten-tial infrastructure spending has been a hot topic, and the naming of a new energy secretary has prompted hopes of a lighter regulatory burden on the energy sector.

Aside from politics, uncertainty is also evi-dent in commercial banking circles serving the energy sector. There is some comfort in crude prices having apparently stabilized in a broad $40 to $50 per barrel (bbl) range, but this was ahead of the OPEC meeting in Vienna that took place on Nov. 30. Assuming fundamental factors prevail, the outcome—we now realize—could push the rebalancing of the global oil market along a shorter path.

Even as crude oil prices have rebounded from last spring’s lows, banks have continued to bring down energy loans as a percentage of overall bank loans. Some still have major work to do, with one regional bank reporting its energy book made up as much as 15% of overall loans as of the third quarter. Even so, an analyst said in reviewing the quarter, “We expect more limited credit headwinds going forward.”

Despite benefiting from some tailwinds—a broad recovery in capital markets and a mark-edly deeper market for oil and gas assets than existed nine to 12 months ago—several bank executives were not at ease in commenting pub-licly on conditions. One cited the bank is still in a “defensive posture.” Another said the bank’s energy group was gearing up for 2017, but had booked no new deals in 2016.

This reluctance was in spite of a relatively uneventful borrowing base redetermination season last fall, which left E&Ps’ borrowing bases largely unchanged. Of the 33 redetermi-nations covered, 19 were held constant at spring 2016 levels, according to Seaport Global Secu-rities LLC. Seven were increased and seven decreased. The seven increases, averaging 29%, were for E&Ps mainly in the Permian and Appa-lachian basins.

The more stable environment surrounding the fall redetermination season stood in stark con-trast to the redeterminations last spring, when market conditions were “terrible,” as one bank executive said.

But is this new business restricted to a rela-tively narrow, advantaged few? Or does it augur a broader opening of business to E&Ps operating in a variety of basins?

Banks loosening

One private equity-backed E&P has seen signs that banks “are loosening the purse strings again.”

Elevation Resources LLC, based in Midland, Texas, has expanded its lending group with two new banks and doubled its capacity to $200 mil-lion from $100 million last spring, according to CEO Steve Pruett.

“The banks can now advance more money,” said Pruett, who met with his bank group last November. “I added two regional banks to my group after one of my existing large banks said it could not increase its commitment to us, even though our collateral value had increased.

“Now I have much more capacity among my four banks than before—as much as $200 million, whereas in the spring, with the con-straints at that time, it was only $100 million. And the aforementioned large bank is now back to doing new deals after being shut down for almost a year.”

Pruett recalled some of the difficulties caused by the tightening in bank lending, including the use of a total debt metric in place of the tradi-tional senior secured debt standard, over the period when crude prices sank from more than $100/bbl to under $30/bbl early last year.

“The assumption that, as a private equi-ty-backed company, you could finance your business 50% equity and 50% debt was no lon-ger a safe assumption,” he said.

“The banks changed their price forecasts every month, and they were forced to consider an E&P’s total leverage, not just its senior leverage. We all had our Libor [London Inter-bank Offered Rate] grids increased by 100 to 150 basis points, and we had leverage covenants added to our loan agreements.”

Pruett noted that private equity-backed teams are motivated to use some bank debt—at a cost of about 3% to 5%, as compared to more than 20% for equity—as a way to improve returns on equity. However, they were now more cau-tious in relying on bank debt. Today, a startup E&P is likely to buy a deal with 100% equity, he said, and then layer in debt—plus hedges—as it grows its production and reserves.

A “more nuanced reality”

However, not all E&Ps may have the same options that are available to an E&P operating in a favored basin with quality private equity backing.

A “more nuanced reality” seems to be that commercial banks are “really picking their spots,” according to Todd Dittmann, who leads the Houston energy team for Angelo, Gordon & Co. Banks have been “net reducers” of sec-tor credit, he said, and rare examples of banks “stepping up” to make a loan to the right man-agement team in the right basin are more aptly viewed as “proof that they’re saving their bul-lets for the very best opportunities.”

Dittmann said he sees an opportunity for prudent non-bank lenders to make energy loans to borrowers that offer more patience than commercial banks’ twice-yearly redeter-mination of available funding. In the event of a commodity price recovery, coupled with a “true return” of the banks, the normal course of events would be for E&Ps to refinance more patient capital with commercial bank capital and, in doing so, re-establish the traditional reserve-based lending (RBL) relationship, he noted.

Dittmann estimated that while few banks are dropping out of energy lending entirely, “a large number are pulling back to a level of loan exposure that is a fraction of 2014 levels—with the intent that the lower level would represent an intermediate ceiling for energy loan expo-sure going forward. The result is that many E&Ps now lack access to incremental bank credit at the very time when they are seeking to grow, both by acquisition and the drillbit,” he said.

Dittmann cited recent data from high yield energy research indicating that a uni-verse of public E&Ps has an average ratio of debt-to-2016 EBITDA of 4.3x which exceeds the total leverage test of 3.5x set by the Office of the Comptroller of the Currency (OCC). “For most E&P borrowers, expanding a bank line would only generate more OCC-criticized or classified fundings for the bank group,” he said.

The banks’ adjustments to E&P borrowing bases may “potentially flatten out, but I don’t expect them to expand credit on average,” he added. “The facts that bank underwritings are now far fewer, more costly and less aggressive, and the ‘flex’ provisions are at historically high levels, further suggest that secured credit remains dear for all but the best and biggest borrowers. We’ve recently seen a very well-covered revolver that had little to no bank interest due to the significant amount of junior debt that sits below the first lien claim.”

Caution rules the day

Further, the OCC is just one of several hurdles to a more expansionary

environment, said Dittmann.

Pressure on the banks will continue to be applied both internally and externally by the rating agencies and equity analysts following the banking sector. Analysts at financial ser-vices firms, such as Keefe Bruyette & Woods Inc., “are still keeping a very sharp eye on these banks, particularly the regional banks’ loan exposure as a percent of their total loan book,” he observed.

“I think caution will rule the day,” said Dittmann. “And with oil prices on a knife’s edge, fundamentally there’s a reason for cau-tion from the banks.”

Of various alternatives to bank lending, what does Angelo Gordon offer to bridge the financing gap? And, assuming an E&P is not in a “hot” basin and lacks a high profile PE sponsor, what terms would be available?

“We’re in a period of price discovery as to what level clean, first lien paper prices are when bank financing isn’t available,” said Dittmann. “It’s only beginning to happen. I’d say, for now [as of interview in late Novem-ber], coupons are in mid-to-high single digits, depending on risk, coverage and cash flow.”

Describing the outlook for energy for com-mercial banks as “cautiously optimistic,” Marc Cuenod, executive vice president and division head with Wells Fargo Energy Group, said the energy sector “has historically been and will continue to be a core area” for Wells Fargo and one in which it has done new business and will continue to look at new opportunities.

New business is arising in many cases as seasoned management teams find fresh private equity funding.

“New management teams are being formed all the time,” said Cuenod. “We’ve seen acqui-sition opportunities in which larger, investment grade companies have been selling assets, allowing smaller E&Ps to gain a foothold in an area. The vast majority of the management teams are private equity-backed, and we’ve seen opportunities to finance those acquisi-tions.”

In addition to the track records of the man-agement teams and their private equity spon-sors, Wells Fargo’s focus is increasingly on the quality of the rock being acquired in an acqui-sition, according to Cuenod. “We are doing more technical due diligence on the assets than ever before, in addition to carefully evaluating companies’ operating and development plans,” he said.

In terms of the acquisition and divestiture market, the Permian, Marcellus, Eagle Ford and the Rockies have been areas generating the most interest. “Most of the acquisition financ-ing opportunities have involved natural gas asset packages rather than oil,” according to Cuenod. Somewhat surprising, he added, was that “we have not seen a lot of distressed asset sales due to the downturn.”

As for rules of thumb on leverage, Cuenod saw banks returning to prior practices.

“In the past, a typical reserve-based loan would have a leverage covenant in addition to the borrowing base,” he recalled. “Over time, leverage covenants were negotiated away while the market was surging. Since the downturn, the leverage test has returned as a standard component of a reserve-based loan covenant package.”

Regarding the OCC’s loan review guidelines, “OCC guidance states that the 3.5x leverage test is not a ‘bright line,’ but one of several metrics that should be evaluated. It’s certainly a datapoint that banks carefully consider in their analysis,” said Cuenod. “For new deals involv-ing acquisition financing, opening leverage is typically set in the 2.5x to 3.0x range, and possibly lower depending on circumstances, in order to ensure sufficient liquidity runway.”

Business fundamentals

While Wells Fargo is known for leading many of the largest bank syndicates in the energy sector, it is also willing to consider loans to smaller players that have some equity capital behind them, according to Cuenod. If an E&P has quality assets, a reasonable amount of production to service a loan and is well-capital-ized, the bank will consider advancing smaller loans “with the expectation that the company is going to grow,” he said.

Cuenod emphasized some of the fundamen-tals of the business, making it sound surpris-ingly simple.

“This business really comes down to people with quality assets who are good at producing oil and gas, who can keep their costs down and who take risk off the table by hedging. If you do that, there’s capital available.”

Wil VanLoh, CEO with private equity spon-sor Quantum Energy Partners, identified a few larger banks, including Wells Fargo and J.P. Morgan, which are “very committed to the energy sector” and are “using this time to go on offense when a number of their competitors are on defense.” As a result, “you’re seeing a situation in which the strong banks are able to capture additional market share right now.”

VanLoh characterized commercial banks working in the energy sector recently as having been “much more selective” in their business activity. The ‘haves’—the E&Ps operating in the Permian, Scoop/Stack and Marcellus/Utica—have typically been successful in growing their reserves and attaining materially higher borrowing bases, he said. In addition, capital markets have largely been open for E&Ps in these basins to re-equitize, he noted.

In his experience, most banks have been reluctant to enter into a new facility with com-panies if the debt-to-EBITDA ratio is 2.5x or higher. This has meant relatively more equity is needed to finance an acquisition or drilling program, raising the weighted average cost of capital significantly. In striving to be con-servative and to build in a margin for error, Quantum portfolio companies aim to keep debt-to-EBITDA in a range of 2.0x to 2.25x at closing, according to VanLoh.

Are there instances in which bank lending is more expansive?

In order to accommodate working capital needs, banks may provide for higher debt levels (say, half a turn higher, from 2.25x to 2.75x, or 2.5x to 3.0x), but these levels are typically not drawn at closing, said VanLoh. And higher levels, he indicated, tend to be the exception rather than the rule.

“I think the ‘bright line’ is 3x,” he said. “And anything over 3.0x is radioactive.”

Meanwhile, since the campaign success of president-elect Donald Trump, interest rates have moved higher, with the yield on the 10-year U.S. Treasury rising to more than 2.3% in late November from around 1.6% in late September. Bank stocks have generally rallied along with the move in rates.

For bank financing, however, rates are linked to Libor, where moves higher have been more muted. And the other component—the risk premium over Libor—has increased from about Libor plus 150 to 200 basis points to Libor plus 300 basis points, according to VanLoh. Yet even with Libor inching higher, coupled with a wider premium for risk, rates are “still almost as low as they have ever been historically,” he observed.

Back to lending

If the move in banking stocks reflects improved prospects for the sector, what is it likely discounting?

Based on Trump’s policy statements, the incoming administration is expected to be “more business-friendly,” according to Van-Loh, and “get banks back in the business of lending” within what could be a lighter reg-ulatory framework for lending in general and the energy sector in particular.

“It’s plausible to believe that the new administration will loosen up some of the lending standards and try to get banks lend-ing again,” observed VanLoh. And while the industry is naturally “gun-shy in trying to predict how regulators will act,” he added, the preceding administration’s policies “certainly seemed to be trying not to do any favors to the hydrocarbon portion of the energy sector.”

Regions Bank is the largest bank headquar-tered in the Gulf states, according to Brian Tate, who heads the Energy and Natural Resources Group at Regions. Currently, the bank has fewer than 3% of its loan portfolio in energy, a level that is down “modestly.” The majority of the bank’s energy book consists of about 40 E&P companies and somewhat less than 40 oilfield services clients.

“There’s no doubt about it, energy has been a challenge for the banking industry, but the concentration risk management program that we have in place at Regions has reduced the impact,” said Tate. “Within energy, we are deliberate in balancing and diversifying risk across sub-sectors (upstream, midstream, downstream, oilfield services, etc.) within our well-understood risk acceptance criteria.”

Regions has been involved in energy lend-ing for more than 40 years, noted Tate. With an experienced team across client coverage, credit and petroleum engineering, it comprises over 40 professionals, with senior bankers averaging more than 25 years of industry experience.

In the E&P space, “the deals we have done recently have been OCC-compliant, with healthy pricing and half the risk compared to the pre-commodity downturn structure, generating an attractive risk/return balance,” he said.

First Tennessee Bank is a “true middle-mar-ket bank” that made a very timely entry into the energy sector, according to managing director John Lane. With the energy group beginning operations in the latter part of 2014, “our timing, not by design, marked a great entry point,” recalled Lane, an industry vet-eran who formerly led Whitney Bank’s energy team for six years.

With the downdraft in crude prices, 2015 was “very muted” in terms of deal flow, mak-ing for a very quiet year that focused more on midstream opportunities than E&P, recalled Lane. Growth has occurred mainly since early 2016, with First Tennessee participating in “the quality deal flow from the Permian start-ing in the spring of last year,” he said as it built an initial book of business.

“The bank sees this as an excellent oppor-tunity to move into the energy space,” com-mented Lane.

First Tennessee typically makes loan com-mitments in the range of $10 million to $25 million. Lane prefers to participate in syndi-cates that are less than $500 million. With two members of the team having a combined 70 years of industry experience, he wants First Tennessee to be “on the radar,” he said. “And we want to have a vote on the facility. We want to be visible and meaningful to the bor-rower’s senior management.”

In 2016, First Tennessee has been “judi-cious” in its credit selection, said Lane, and its energy book accounts for less than 1% of the bank’s $20-billion loan portfolio. “We’re not a bank to put $50 million into a syndicate yet. But we’ll move into that comfort level as we have a longer track record in energy.”

First Tennessee is “still in the mode of building a book of business. But we don’t feel a tremendous amount of pressure right now to become a certain size,” said Lane. “When the opportunity is the right fit, we move forward. There aren’t many regional banks that can look at energy from our standpoint. We’re lucky from that viewpoint; we don’t have a big portfolio that we’re having to ser-vice right now.”

First Tennessee clearly has an appetite for new business, but quality remains a top crite-rion, according to Lane.

“We’re being very picky about who we bank,” he said. “We’re making loans to com-panies that we’re very comfortable with, who have a long track record and good prospects for growth.”

Comments