High Noon For High Yield

The problem with the downward spiral of oil economics—lower oil prices, leading to lower production and less access to capital—is that no one knows how far and how fast crude oil prices will drop. And likewise, no one knows with certainty how quickly and to what degree oil may rebound.

With high yield having lubricated the economics of oil for the past several years, the dramatic drop in crude has left its mark on many E&Ps, who may now wish they had done more to improve their balance sheets ahead of the downturn. While a few maintained fortresslike balance sheets, others tapped debt markets repeatedly, expecting smooth sailing in the commodity markets and stability in the capital markets.

But access to funding has now changed—dramatically. While E&Ps face what some analysts say should be a “relatively benign” borrowing base redetermination this spring, they will confront a much tougher test—and likely with less help from commodity hedges—in the subsequent redeterminations held at six-month intervals. This assumes no major move higher in crude, of course, during the interim.

Conditions in the high-yield market for energy offer few signs of near-term encouragement in the absence of a crude price recovery. Indeed, there has been at times scant evidence of even a normally functioning market for energy issuers rated BB/Ba or lower. For new issues, investor demand has largely dried up, except for the highest-quality credits in high yield. And for currently traded issues of more levered small and mid-cap E&Ps, it is not unusual to see senior note issues that have traded down to yield 20%, or more, on a yield-to-maturity (YTM) basis.

Instances of even greater financial pain are not hard to find. In January, a senior note issue of Samson Investment Co., a private E&P acquired by a KKR-led consortium, was trading at a YTM of more than 40%, while an issue of Quicksilver Resources Inc. traded at a YTM of more than 50%.

Clearly, there is major distress in the energy component of high yield. But is there light at the end of the tunnel? What happens if the distress lasts much longer—or resolves more quickly—than expected? What are E&Ps’ options as the combined pain from lower crude oil prices and tighter credit conditions builds?

On the positive side, the strong activity in high yield preceding the dramatic downdraft in crude prices, in which many E&Ps were able to access capital at very favorable spreads over U.S. Treasuries, means almost no high-yield issues are coming due this year or next. This has allowed many E&Ps to avoid high—or sometimes any—utilization of their borrowing bases.

“There’s not a lot of near-term maturities in high-yield E&P,” Gary Stromberg, Barclays Capital’s senior energy analyst covering high yield, said. “In the context of a roughly $100 billion high-yield E&P market, there may be $5 billion coming due in the next two years. We have just two maturities in 2015 for under $400 million. A lot of companies cleaned down their borrowing bases in the last two years through high-yield issuance.”

Stromberg see defaults on the horizon on two possible counts, however. One involves breaches of covenants governing revolver agreements with lenders, which Barclays projects are likely to be tripped, assuming WTI prices do not break out above $50 to $60/bbl. The other is if E&Ps find themselves overdrawn on a newly reduced set of borrowing bases.

“We think about 5% of bonds could default in 2015, and that number could top 20% in 2016, assuming WTI oil remains below $60 per barrel,” Stromberg said.

Typically, bank covenants stipulate a debt-to-EBITDA ratio that should not exceed 4.0 to 4.5 times, as well as an EBITDA-to-interest coverage ratio that should not fall below 2.5 times. However, for the roughly 25 E&P high-yield issuers under Barclays’ coverage, Stromberg forecasts debt-to-EBITDA reaching 4.3 times by the end of 2015, based on a $50/bbl WTI oil price. Further, the sector’s debt-to-EBITDA is projected to stay “above 4.0 times” in 2016, as commodity hedges roll off next year and offset the positive impact of a $10/bbl increase in the projected WTI oil price.

As for reduced borrowing bases, Stromberg sees greater risk of E&Ps finding themselves overdrawn on their revolvers following the fall 2015 and spring 2016 borrowing base redeterminations than after this year’s spring redetermination.

“You won’t see a lot of harsh borrowing base moves in the early part of 2015,” he said. “It’s in the fall redetermination period, when some of the hedges roll off, that the banks probably move down again, if oil prices stay low. Then, specifically in the spring of 2016, there’s a lot of worry, because the banks in certain cases give almost full credit to hedging. So, if your hedges roll off over the course of the next year, it’s almost a one-for-one reduction in the borrowing base at a time when the banks may still be moving lower on their price decks.”

While robust hedging programs can play a protective role, the trajectory of crude oil prices remains pivotal.

“So much depends on where oil prices go,” Stromberg said. “If oil prices rebound to $70 or $75 per barrel, I don’t think we’re having this discussion. That $10 to $15 per barrel difference can mean going from economic drilling in an economic model to one that is impaired, given the amount of debt that is on some of these high-yield companies’ balance sheets.”

And while ratings are important, especially in drawing a line between investment grade and high-yield issuers, Stromberg pointed to an E&P with a B3/CCC+ rating, Rice Energy Inc., that could access the debt market because of factors beyond a nominal rating.

“It’s not just the rating; the market is also looking at asset quality and cost structure,” he said. “Rice can finance debt at 7% because the market can appreciate its very low cost position in the Marcellus Shale.”

Market Access

Summing up the turn in market conditions in the latter half of 2014, J.P.Morgan high-yield energy analyst Tarek Hamid estimates that spreads over U.S. Treasuries in the high-yield energy market have widened by about 400 basis points, on average, over spreads prevailing late last August.

That doesn’t necessarily mean that a high-yield deal can get done, however. E&Ps’ access to the market is far from a given.

At the upper end of the high-yield spectrum is a “very good, core BB issue,” which in the secondary market recently traded around a 7.5% yield basis as compared to a 4.75% to 5.0% yield last August, Hamid noted. While this represents somewhat less than an average 400-basis-point widening of spreads, wider spreads are reflected in lower-rated issues. “The lower the rating,” he said, “the worse the issue has traded over the last several months, as risk aversion has gone up.”

High-yield activity in energy is likely to increase during the course of 2015 as E&P management teams come to grips with the realization that the fall borrowing base redetermination is going to pose a “bigger challenge” for E&Ps, especially as hedges roll off, contributing to a “liquidity gap” that will likely be filled by second lien bonds or loans, Hamid said.

The process by which E&Ps conclude they need to access the second lien market typically involves several steps. Ahead of the fall borrowing base redetermination, proved developed producing reserve growth will tend to be very low, if any, and 2015 hedges will no longer be a significant factor. Few E&Ps have much production hedged for 2016, and what hedges have recently been placed will generally carry less value due to lower commodity prices. These factors point to a loss of reserve-based lending capacity, prompting a move to place second lien bonds or loans into E&Ps’ capital structure to meet the greater need for liquidity.

Observers look for a significant institutional appetite for second lien paper as well as a growing market for deeply discounted energy issues in the secondary market. In addition to typical institutional buyers, such as mutual funds, insurance companies and hedge funds, several private-equity sponsors have raised funds focusing on energy. The Blackstone Group, for example, earlier this year closed a $4.5 billion fund, while Apollo Global Management and Riverstone Holdings have both announced “credit opportunity” funds focusing on energy.

“There’s clearly some very interesting values in the credit markets in just buying debt at big discounts to face and getting equity-like returns,” Blackstone’s president, Tony James, observed on the firm’s fourth-quarter conference call.

In terms of existing high-yield bonds trading in the secondary market—frequently at steep discounts—Hamid said the “natural dynamic” has been for lower-rated paper to flow from traditional investors, such as mutual funds and insurance companies, into the more risk-tolerant hands of such investors as hedge funds and private-equity sponsors. As for discounts, he sees the market as bifurcated between paper trading at 60 or 70 cents on the dollar and that trading at 50 cents or less—the latter being paper that will “ultimately require substantial additional capital in 2015-2016.”

The likelihood of a default in 2015 in the high-yield E&P sector will be “very much the exception,” Hamid said. “It’s really 2016 and 2017 when, under the current commodity deck, our universe would run into more problems.”

Recovery Timeline

Having committed to a macro view of energy, Wells Fargo Securities’ senior analyst in high-yield research, James Spicer, gives the sector an overweight rating. The rating applies to full-year 2015 and projects a recovery by year-end, give or take a quarter. Recent record wide spreads in high yield do not conform to his outlook.

“All the ingredients are in place for a price recovery, to some extent, by the end of the year,” Spicer predicted. “As long as you believe the demand is going to be relatively stable, the supply correction is just a matter of time. The market doesn’t necessarily have to wait for the production numbers to show up; the supply response is undeniable.”

Supporting this thesis are several key factors. First is the magnitude of E&Ps’ capex pullbacks, which started with talk of 20% to 30% cuts and grew, in certain cases, to 50%, 60% or 70% cuts. At the same time, companies are high-grading their asset portfolios and pushing back aggressively on service costs. The industry rig count is dropping “precipitously,” as are drilling permits, he noted.

With these types of adjustments, most high-yield E&Ps can operate sustainably down to $60/bbl and, in many cases, at even lower prices, according to Spicer.

“Given improvements in cost structures, you don’t necessarily need to see oil rebound to $80 or $90 per barrel. If oil rebounds to just $60 or $65, a lot of these companies can be just as profitable as they were when oil was in the $70 to $80 per barrel range,” he said.

The oil price assumption used by Spicer for his overweight call on the sector is $65/bbl WTI by year-end 2015, up from $50/bbl at the start of the year. It averages $65/bbl in 2016.

Seeing a correction on the horizon, Spicer describes the energy sector as “ripe with opportunity” given the blowout in spreads in high yield.

With the energy high-yield sector now trading at roughly 1,300 basis points over U.S. Treasuries, as compared to about 530 basis points for high yield as a whole, “spreads in the E&P sector are at their widest level ever,” he said. Historically, the E&P sector has traded at around a 200 basis point premium to the broader high-yield market. “We view the sector as one of the few in high yield with the potential for meaningful price upside in 2015.”

When conditions in high-yield energy deteriorated with the almost 50% drop in crude in the latter half of 2014, the return on the high-yield market as a whole was around 2.5%, according to Spicer. The sector was dragged down by the energy component, which in isolation had a negative return of 7.9%.

With recent market conditions, it wouldn’t be surprising to see a typical BB-rated credit in energy trade at around 80 cents or higher on the dollar, Spicer said, while a B-rated credit might trade at 70 cents or higher and a CCC-rated credit at either side of 50 cents on the dollar.

“To me, that’s indicative of a relatively widespread default scenario,” Spicer said. “With all the steps the E&Ps are taking to preserve liquidity, coupled with our base-case scenario of a price recovery toward the end of the year, I think high yield is overstating the potential default risk of the sector.”

Spicer expects to see “very few” defaults in 2015 apart from cases in which an issuer would also have been at risk in a $90/bbl price environment. For 2016, unless WTI is still below $50/bbl, a list of default candidates would also be relatively short—“certainly much shorter than what would be implied by where spreads are.”

In certain cases, the selloff in lower-rated credits has reflected a “general risk-off trade” in the sector and has been “indiscriminate” in terms of such factors as asset quality and hedging profile, Spicer said. He cites the example of private E&P Chaparral Energy Inc., whose production is 100% hedged in 2015 and about 60% hedged for next year. The company’s 7.625% note, due in 2022, recently traded in the high 50’s cents on the dollar.

“There’s not a lot of commodity risk, and the market is pricing the bond as if the current oil prices are unchanged at these levels for the next three to four years,” he said. “The market is certainly not pricing in any type of recovery.”

Self-Help Options

As self-help strategies for E&Ps still feeling squeezed by a liquidity shortfall, Spicer listed his “top three” items: capex reductions, high-grading of assets and pushing back on oilfield service costs.

Also offering support is a widening investor pool. “The profile of investors looking at the space has really expanded,” he said. “There’s a lot of new capital that’s trying to get up to speed on the space, often nontraditional high-yield investors such as distressed hedge fund investors or private equity that are looking for opportunities.”

Some E&Ps are discussing second lien transactions as a funding source. Typically, these were E&Ps with fairly high utilization of their revolvers going into the downturn that were either burning through cash or anticipating negative borrowing base redeterminations.

“My sense is that we’ll see these come sooner rather than later, because you never want to issue debt when your back is up against the wall,” he said. “The whole objective is to preserve liquidity to get to the other side of the downturn.”

Mark Ammerman, managing director with Scotiabank, heads up energy banking activities in the U.S. and oversees much of the Toronto-based bank’s international operations, including Latin America, Europe and Asia Pacific. Asian investors may represent an additional financing source for E&Ps beyond such channels as issuing second lien paper or selling assets, he said.

“Our Asian investor base is all over us,” Ammerman noted. “Having bought into deals and done all these joint ventures in the Eagle Ford and the Permian at premium prices, they now have this opportunity to further buy into these properties at heavily discounted levels in what they consider a politically risk-free country. This is completely different from all the markets we’ve had in the past. The money is out there; we just don’t have the sellers, because, frankly, they haven’t capitulated yet.”

Scotiabank’s ability to chalk up a record A&D year in 2014 stemmed in part from property divestitures in Africa, the Middle East and the North Sea, with proceeds earmarked for reinvestment in North American unconventional basins, Ammerman said. With oilfield service costs in the U.S. down by 10% to 20%, and using strip prices for oil four years out, the Eagle Ford Shale, for example, still offers investment opportunities with IRRs of about 35% in secondary acreage and 75% in core areas.

Ammerman recounted how an Asian client was targeting a seemingly low IRR of 15% at current commodity prices. “But his thought was that a 15% IRR today is next year’s 30%, and an IRR of 50% the year after that, presuming oil prices go up. They want to come in and spend money today, before the perceived price upside materializes. They aren’t trying to pick the 80% returns in this price environment. Everyone is still making the bet that there is an escalation of price over a couple of years.”

Mezzanine providers are another funding source for E&Ps, with terms typically being around 15% for three years versus seven to 10-year high-yield paper carrying a coupon of 12% to 13%. Clients “are being called daily,” Ammerman said.