Upstream Contagion

The confluence of events could scarcely be more challenging: a cartel collapse triggering a 70% dive in crude prices, a crushing slide in energy high-yield bonds and, more recently, credit rating agencies’ downgrade of issuers that had long held investment-grade status. The result: The downturn contagion is creeping into wider sections of the industry.

As oil and gas producers seek financial stability, their stated goal often is “free-cash-flow neutrality.” Typically, this entails cutting capex to steeply lower cash-flow levels, with asset divestitures to help balance the equation. But divestitures may only add to pressures arising from the redetermination season at commercial banks. Bankers say cuts in borrowing bases may be the catalyst for more borrowers to capitulate and shed noncore and even core assets.

Selling assets in a downturn is a normal course of business, of course. But is this downturn “normal”? And if there are signs of contagion, where are they appearing?

One indicator that it may be more serious is the strain on the normally synergistic relationship between the upstream and midstream sectors. At prices slightly more than $30/bbl and $2/Mcf, almost no plays offer economic returns for drillers. And such has been the depth of the collapse in commodity prices that the more levered upstream producers are suffering intense financial stress, posing risks for midstream operators under pressure to renegotiate contracts.

Williams Partners LP is a notable example. The midstream partnership has substantial exposure to Chesapeake Energy Corp., whose financial travails prompted the E&P to release an early February statement saying it “currently has no plans to pursue bankruptcy.” The release came after bankruptcy rumors led to about a 50% drop in Chesapeake’s intra-day stock price. The stock closed at $2.04/share on Feb. 8, down 33% from the prior-day close of $3.06/share. Williams Partners’ stock closed at $14.39/share, down 18.9% on the day.

A review by Michael Blum, senior analyst with Wells Fargo Securities, estimated that Williams Partners’ exposure to Chesapeake in lost EBITDA is between $200 million and $600 million, reflecting a “high case” and a “worst case” scenario, respectively. The latter case assumed that Chesapeake would go bankrupt and exit its minimum volume commitments (MVCs), and that some above-market gathering contracts would be re-set at market-based rates. The high case assumed that Williams Partners would be able to “exert its leverage in a bankruptcy scenario to maintain counterparty contracts.”

Already, some smaller, less well-capitalized upstream companies like Quicksilver Resources Inc. are in bankruptcy proceedings. Quicksilver’s midstream provider was a subsidiary of Houston-based Crestwood Equity Partners. The U.S. assets of Fort Worth, Texas-based Quicksilver were purchased out of a bankruptcy auction for $245 million by BlueStone Natural Resources II, a private equity firm backed by Natural Gas Partners.

In its successful bid for Quicksilver’s assets in the Barnett Shale, BlueStone conditioned its offer on the rejection of certain midstream contracts with Crestwood Midstream Partners. While it is possible that the bidder and Crestwood will settle, or agree to amend and assume a modified version of the contracts, the actions of BlueStone “have made it clear it is not interested in buying into a contract dispute,” according to one legal source.

In commentary accompanying its fourth-quarter earnings release, Crestwood noted that BlueStone had until March 31, 2016, to complete the transaction. “Crestwood remains encouraged by this next step in Quicksilver’s bankruptcy process, and we are involved in constructive dialogue with BlueStone on its plan for future development of the assets,” the company said.

Industry speculation is that contract talks might focus on replacing a high fee, associated with a declining production profile for the natural gas assets, with a lower fee but flatter volumes over an extended contract period with BlueStone.

How serious is the risk of gathering contracts coming under pressure to be renegotiated?

Ethan Bellamy, senior research analyst at Robert W. Baird & Co., has been consistently cautious, forecasting more E&P bankruptcies amid “chronic commodity weakness.” However, while issuing nine downgrades on MLPs under his coverage, he has a more tempered view of midstream companies than some other observers with more dire predictions.

“Customer viability is a material risk for MLPs under the current price scenario,” said Bellamy. “We’ve been flirting with commodity prices that come close to levels where you start to worry about midstream volumes. We expect energy contagion to spread as long as oil slumps, and we discount the willingness of the Saudis to cut just when they are on the verge of destroying competitive productive capacity to preserve their own long-term market share.”

That said, talk of MLPs’ risk of bankruptcy is likely overstated, unless commodity prices fall below E&Ps’ cash costs and, critically, their lifting costs, he said. The Baird research team estimated average lifting costs for E&Ps under its coverage at $12.58/bbl, with total cash costs (including cash taxes, interest expense and G&A costs, etc.) closer to $25/bbl.

“Overall, I think there’s probably limited ‘going concern’ risk in the midstream sector,” said Bellamy. “Gathering system bankruptcies would depend on only the most draconian price scenario, by which I mean below lifting costs and total cash costs for a meaningful amount of time, forcing shut-ins.

“Rather than bankruptcies, what you’re likely to see in midstream are distribution reductions, cash flow being steered to fix balance sheets for some transitional period and strategic alternatives in which midstream players try to sell themselves,” he said.

The outlook is far from bright. There is commodity price uncertainty, the rising cost of capital in the midstream sector and the reluctance of buyers to put new money to work until they see a bottom in commodity and asset markets.

“There’s an enormous amount of uncertainty generated by the volatility in commodity prices,” he said. “Every day that commodity prices remain at low levels, assets are worth less, because you’re locking in more and more natural declines and less and less capital spending to prop up volumes,” he said. “Money is going to get more valuable, and assets will become less valuable, because there are going to be more and more assets for sale. Cash is king.”

The longer low prices continue, the more drama there will be surrounding going concern risk, he said. “Buyers of assets will tend to be patient and demanding. People will sit back and wait for things to get as bad as they’re going to get rather than buy too early, and potentially miss the bottom. In some cases, they’ll buy out of bankruptcy rather than buy too early.”

Contract threats

Several analysts, including Bellamy, said that the likelihood of midstream contracts being upheld in instances of bankruptcy would depend in large part on the court’s ruling as to whether a firm providing gathering and processing operations is a “critical vendor.” As yet, it is not clear that such a ruling will prevail. A ruling of critical vendor status would lower the risk of midstream contracts being abrogated; without that status, midstream players would be just one of many ancillary suppliers with a claim.

Williams’ management team made “a good case suggesting its gathering assets should be considered a ‘critical service’ with regard to Chesapeake’s ability to monetize its hydrocarbons,” said Darren Horowitz, energy analyst covering midstream MLPs at Raymond James. However, “while the commentary implied that Williams Partners is a critical vendor, and rates are unlikely to be renegotiated materially lower, we think the ultimate result could be a bit more punitive,” he said.

It is difficult to predict how midstream contracts will be interpreted in bankruptcy proceedings. Horowitz said the ultimate impact to Chesapeake, the second largest U.S. natural gas producer, was “essentially unknowable, based on limited public information, situation-by-situation specifics and the seemingly unpredictable nature of court rulings and negotiations.” As for one type of contract, MVCs made by E&Ps, “it is becoming increasingly likely that MVCs may not be honored in bankruptcy—midstream service providers will likely receive only ‘adjusted-to-market rates’ on flowing volumes,” he commented.

Bellamy expects to see “the complete range of outcomes in these situations, from contracts that remain untouched to contracts that go to zero.” For investors, the difficulty in assessing counterparty risk, due to limited disclosure of specifics as to customers and contracts, complicates matters, with the exception of FERC-regulated assets. “There are many possible outcomes here,” he said. “It’s a risk that cash flows go down in bankruptcy, and you’d be naive to think otherwise.”

Sunil Sibal, senior analyst covering MLPs and infrastructure for Seaport Global Securities LLC, said that, per his understanding, bankruptcy proceedings generally allow contracts only to be rejected or accepted “in whole.” Thus, where there may be multiple contracts with various midstream counterparties, more onerous contracts may be rejected in their entirety in an effort to repair the financial status of an entity in bankruptcy, but that entity may not “cherry pick” which portions of a particular contract it wants to accept.

This means, for example, that a producer who has overcommitted to takeaway relative to what it now needs cannot tell a midstream player it wants to honor only part of the contract, based on a pro rata lower level of volumes now desired, according to Sibal. “To some extent, this provides some protection to midstream companies and gives them a negotiating chip when the two parties come to the table to renegotiate terms for a new rate and capacity commitment.”

The main factor typically is whether the infrastructure is in a basin where the economics still work.

“Even though an upstream customer may be filing for bankruptcy, he’ll still probably be incentivized to produce in his most economic areas, so it’s not as if the production is going to get shut down the next day,” Sibal said.

“He’ll still need to get volumes to market, and then it comes down to how much the infrastructure is overbuilt. If it’s in an area where it’s significantly overbuilt, then the E&P likely has more pricing power over the midstream firm. The E&P company can say, ‘I’ll reject this contract in full. I’ll go with the other midstream guy, who has unused capacity and can give me a cheaper price.’”

Alternatively, if the upstream economics still work, the assets may simply move into the hands of a more solvent producer, who will still need infrastructure.

The potential arbitrage between the higher valuation accorded to midstream assets and the lower valuation given to E&P assets “has shrunk by almost half,” said Sunil Sibal, senior analyst covering MLPs and infrastructure with Seaport Global Securities.

Contract requirements between upstream and midstream players haven’t remained static as the downturn has worsened.

Some midstream firms with “above-market” contract fees have cut fees in exchange for a longer-term contract with an E&P. If the lower fee creates enough latitude to allow drilling at recent low commodity prices, the tradeoff for the midstream firm is that the E&P can afford a contract of great duration, at least preserving the net present value of the midstream contract, said Sibal.

In the southwest Marcellus, there has been another sort of give and take. E&Ps have shut down activity in one area, for example, due to the economics’ high sensitivity to NGL pricing. But if drilling starts up in another area, such as the dry gas Utica Shale, and no midstream partner has yet been nominated, the E&P could offer a contract there to the midstream firm to offset the steep decline in business in the Marcellus, according to Sibal.

Sibal likened the midstream sector to real estate: “It’s about location, location, location,” and whether the drilling economics still work at current low commodity prices.

Liquidity and funding options

As the economics have become squeezed in even the best plays, liquidity and sources of long-term funding have become increasingly important.

The options have shrunk for both upstream and midstream players seeking to divest assets to bolster liquidity. The usual path, where E&Ps shed midstream assets to capture an arbitrage in valuations between the sectors, has narrowed, according to Sibal. Historically, the midstream MLP sector traded at about a six multiple premium to the E&P sector, based on enterprise value-to-EBITDA (using forward EV-to-EBITDA estimates), but “now that arbitrage has shrunk by roughly half,” he said. This reflects a comparison of midstream versus E&P multiples of 11.7x versus 5.6x, or a six turn premium historically, which has now compressed to 10.3x versus 8.0x, or less than a three turn premium (see graphic).

This has reduced incentives for E&Ps to raise money by spinning off their gathering and processing assets, often to MLPs (see “Monetizing Midstream,” November 2015 issue). Further, funding of such deals by MLPs may no longer be feasible: As of early March, MLP issuance was virtually nonexistent, although there were several instances of private equity funding.

Bellamy doubts that markets will see much MLP equity issuance until the latter part of this year or early 2017. Private equity will help fill the void.

“There’s hardly any retail interest to finance transactions, and that’s unlikely to change until oil prices and the high-yield sector stabilize,” he said. “But the midstream firms are telling us there are plenty of private equity companies that want to co-invest, or do joint ventures and who can offer capital to invest in good assets. The money is there, it’s just that it’s more expensive and from fewer players.”

Convertible preferred instruments are re-emerging as, in Bellamy’s words, the “go-to weapon.” With MLPs trading at elevated yields, making issuance of MLP public equity “inaccessible or so onerous as to be impractical, you can issue a convertible preferred at a much lower cash burn rate, via the lower dividend yield, and you can worry about the dilution of the conversion feature later on, when the downturn is over,” he said. “They make the most sense for both parties.”

In fourth-quarter 2015, Kinder Morgan Inc. raised $1.6 billion in a mandatory convertible preferred issue that offered a 9.75% dividend yield and a conversion premium of 17.5%. Early this year, Plains All American Pipeline LP similarly raised $1.6 billion by way of an 8% perpetual Series A convertible preferred offering. The preferred carried an 8% dividend and won praise for its message—“one and done”—intended to signal that there would be no further need to access capital markets in 2016 and most of 2017. The issue was placed primarily with private equity sponsors.

Other issuers have followed suit. Hess Corp. issued an 8% Series A mandatory convertible preferred stock, raising about $485 million. Targa Resources Corp. raised $500 million via a 9.5% Series A preferred issue that was placed with Stonepeak Infrastructure Partners. In addition, Stonepeak received two tranches of warrants convertible into Targa stock at different strike prices.

Rice Energy Inc. completed a $375 million equity investment by EIG Global Energy Partners into Rice Midstream Holdings (RMH) in exchange for $375 million of Series B units in RMH and common units representing an 8.25% limited partnership interest in Rice Midstream GP Holdings LP. The preferred has an 8% distribution rate with an option to pay-in-kind for the first two years.

In Bellamy’s view, there has been a fundamental change in the outlook for many midstream players.

“The days of MLPs with ridiculous growth multiples are gone,” he said. “There are solutions out there. MLPs need to team up with private equity firms. There are people out there with balance sheet liquidity and the ability to spend money. Hope is not a plan. If your strategy is to wait for the Saudis to bail you out, I think you need to re-examine your strategy.”

The prospects for consolidation remain indistinct. “I don’t see a clear-cut path for large consolidation transactions in the near term,” said Sibal. “Everyone’s balance sheets have been so stretched that it’s going to be difficult for a company to come in and say, ‘I’ll be the big consolidator here and choose all the marginal players.’

“Ultimately, the industry has to go through some consolidation,” he continued. “However, acquirers will have to be able to articulate a very good reason why they are buying what they’re buying. The market has very little tolerance for deals that are not well thought-out.”

The extent of the downturn will also play a role, said Bellamy.

“The longer this lasts, the more pain there will be for even the larger, more respectable companies, making decision-making in this environment very tough,” said Bellamy. “And when you can’t see to the horizon, hold on to your cash.”