Category: Energy

Stop Me If You’ve Heard This Before: Houston-based Power Traders Blow Up Another Region’s Power Market

“Bloomberg – On June 5, GreenHat received an invoice from PJM for $1.2 million to cover losses. It didn’t pay. On June 21, PJM declared GreenHat in default. Losses have continued to mount, according to PJM. The portfolio has more hedges that will probably keep losing money for three years…”

I love these types of stories. Pull out a big Wall Street pot and mix in equal parts of leverage, some win at all cost trading and an esoteric financial instrument. Kick in a dash of regulatory incompetence and you’ve got yourself one delightful tale about how someone inevitably blew up their book and caused some turmoil in the broader market.

We see these messes pop up every so often and they usually play out the same way: (i) someone has a “brilliant” trade that almost always includes derivatives or a structured product; (ii) they get caught flat-footed as the market turns against them; (iii) they try and trade their way out; (iv) other market participants catch wind of their troubles; and (v) the book blows up and regulators step in. The only thing that really changes is the asset class. Well gather round, folks: today we’re talking about power markets.

I’m not sure if the general population understands how wholesale power markets even work, so I suppose a quick intro couldn’t hurt. As a result of deregulation in the 90s and early 00s, two distinct market structures developed: (i) traditional, regulated markets in which a single utility company is responsible for generating and transmitting power to both wholesale and retail end users and (ii) RTO/ISO markets where private companies own the generation plants and transmission lines of a particular region. The generation companies participate in auctions, run by the RTO/ISO, for the ability to sell wholesale power into the market based on the energy efficiency of their plants. Once they win the auction, they’ll pay transmission companies a toll to use the grid to deliver the power. In layman’s terms, power generation companies say:

“Hey – we can provide xx megawatts of power at this price because we have a brand new, natural gas powered plant. The other guy who burns coal can’t come close to our price so we should win the bid.” 

And that’s exactly what happens. The company with the new, more efficient plant is awarded the contract and is now obligated to provide a fixed amount of power into the system, in the future, at a certain price – done and done. In a vacuum the system works perfectly – but the world doesn’t operate in a vacuum. Sometimes power demand is higher than normal (like during a heatwave) so the system becomes congested, leading to higher tolls for the power plants and eroding their profits in the process. Well here in America we like profits, so the RTO/ISO markets decided to develop a financial product to hedge against fluctuations in the tolls, which is where our friends at GreenHat Energy come in.

I don’t want to get into all the nuance of what happened with these guys but here’s the skinny. The two traders, Andrew Kittell and John Bartholomew, took a look at historical congestion trends in the PJM market (the largest RTO/ISO in the country) and decided not only would that historical pattern continue to play out, it would be exacerbated into the future. They then went out and amassed a huge portfolio of hedges that would payout were their thesis to come to fruition (mind you these guys weren’t hedging exposure, they amassed a naked, speculative portfolio of power derivatives). The problem for these two rocket scientists was that they didn’t factor grid equipment upgrades / repairs into their congestion models. The aforementioned upgrades reduced congestion rates materially over the last few years, slowly eroding the value of their portfolio until 2018 when the floodgates opened.

According to RTO Insider, the derivative portfolio represented a hedge on 890 million MWh of generation – an absolutely massive financial liability for a fund of their size. The value of the portfolio continued to deteriorate and is now facing estimated losses of $145M… and counting. It doesn’t even matter for GreenHat, either – they’re already in default and thus the losses will be absorbed by PJM and it’s participants (including retail customers). So how were these two guys able to use so much leverage to put together, and subsequently blow up, a portfolio and pass the losses on to everyone else? Put quite simply the problem was poor market structure and lax regulatory oversight.

There were two key weaknesses in the way PJM ran the market that brought GreenHat where it is today. The first is that market participants don’t pay for the contracts in full until settlement which is normally a few years out. GreenHat was able to operate on 100% margin and, as long as their trade was profitable at settlement, never had to worry about paying out on losses (kids, hubris is a terrible risk management strategy). Now is the point where you should be asking yourself about collateral requirements:

“Well, sure – they didn’t need to pay out on the contracts yet, but of course they had to post collateral as the portfolio fluctuated in value. Right?”

Wrong, actually! The collateral requirements are determined on a portfolio-level basis, not a position-level one. This past April, PJM changed it’s credit policy for market participants which would have resulted in a $60M collateral call for the GreenHat portfolio. However, market participants were given thirteen months to comply with the changes and rework their trading strategies. GreenHat used this window to amass enough new, profitable positions on 100% margin to negate the $60M collateral call coming down the pipe for their losing positions. Lipstick, meet pig. The window dressing worked for a bit until those positions moved against them as well, sewing the seeds of GreenHat’s demise and sending PJM and FERC scrambling to stop the bleeding. Regulators and market participants are currently kicking around different ideas on how to best equitably absorb at least $145M in losses.

I’m not exactly sure these guys are two of the most prudent fiduciaries out there. However, while I wouldn’t sign up to be a LP in their next venture, I have to point out that they operated within the framework that PJM and FERC had laid out for them. This will obviously force PJM and the rest of the RTO/ISO markets to restructure their credit policies going forward, hopefully they can figure one out that works this time.

Shoot First, Ask Questions Later: Upstream Edition (Update)

“Reuters – WTI Midland spread traded as weak as a $15 per barrel discount to crude futures on Thursday morning.”

“Reuters – Next-day natural gas prices for Thursday at the Waha hub in the Permian basin tumbled 60 percent to their lowest on record due to pipeline constraints limiting the amount of gas that can move out of the region.”

First things first: the blog has been eerily quiet for the last two and a half months. Yeah well, I was a little busy with work and enjoying my summer – sue me. I don’t think I missed any big stories other than Elon Musk trying his best to destroy TSLA’s stock price or every bitcoin speculator piling their money into weed stocks – but in any event the blogging engines are fired up and as a first order of business I’d like to touch on something very dear to me: energy markets.

I wrote a blog in late June discussing the lack of midstream assets / capacity in the Permian and what impact that would have on regional WTI and nat gas spreads. You’ll recall that Scott Sheffield, CEO of Pioneer, predicted that WTI Midland would trade at a discount of $25/bbl within the next quarter. Well here we are three months later and the discount is ~$15/bbl – not quite $25 but still a sizable Midland / Cushing spread. On top of that, Permian natural gas is trading at an all time low of $0.66/mmBtu compared to Henry Hub product which currently sits at $2.98/mmBtu. This is bad news for Permian producers. The worse news, though? It’s about to get worse as refineries enter maintenance season this fall / winter. As refineries shut in for scheduled maintenance, the demand for crude will drop in lockstep. With even less demand for crude in the markets, Permian producers will be forced to reduce prices even further, eroding already delicate cash flow profiles.

It’s likely that some producers will have to shut in production and move rigs away to save cash for the spring and summer months. You may even see some consolidation among smaller independents and private equity drillcos – although many of these players may be too indebted to make a transaction like that pass muster with their boards / investment committees in this environment. Whatever does happen, it will be interesting to see how it plays out. One thing’s for certain: the E&P space is no stranger to booms and busts, good times and bad. The industry always makes it through, it’s just a matter of what players are left to fight in the next round.

Shoot First, Ask Questions Later: Upstream Edition

“Bloomberg – The biggest U.S. shale region will have to shut wells within four months because there aren’t enough pipelines to get the oil to customers…”

This is a story that has been making the rounds over the last few days, but for the energy-initiated, there is no surprise here. I actually touched on this topic back toward the end of March in a post titled “Here’s the Thing About Energy Markets…”, in which I spoke on the negative impact that the MLP model would eventually have on Permian asset prices. The idea was that MLPs were forced to shed debt and assets after the oil rout, using most of their FCF to do so, which prevented any meaningful infrastructure development going forward. This all happened in concert with private equity capital piling into prime, Permian acreage at fire sale prices. I posited that while acreage value and production were reaching all time highs, there would inevitably be logistical constraints around moving product to refineries, which would force producers to begin discounting their product to ensure it was sold downstream.

So where do we stand, just three months later? Here’s Bloomberg:

“We will reach capacity in the next 3 to 4 months,” Scott Sheffield, the chairman of Pioneer Natural Resources Co. said in an interview at an OPEC conference in Vienna. “Some companies will have to shut in production, some companies will move rigs away, and some companies will be able to continue growing because they have firm transportation.”

While nothing Sheffield said is overly concerning regarding how producers will manage capacity constraints, it is a notable admission from the CEO of a company who announced a plan to divest all non-Permian assets and invest heavily in West Texas, that not all is well in America’s super basin. They say necessity is the mother of all invention, and wouldn’t you know it upstream production is no different:

“The problem has grown so bad that oil companies have been forced to load crude on to trucks and drive it hundreds of miles to pipelines in other parts of the state.”

Truthfully, shipping crude via rail and truck isn’t that unorthodox. In fact, this was a primary method of transport when the Bakken exploded in popularity, as North Dakota was never really known for its logistical prowess. What is unorthodox is that the most prolific play in American history has resorted to such an elementary solution because nobody was a prudent enough thinker to understand the correlation between production increases and infrastructure.

The issue now becomes what the impacts of capacity constraints are on price and how that will impact the broader oil markets. Scott Sheffield thinks that “…West Texas Intermediate crude at Midland in the Permian is likely to trade at a $25-a-barrel discount to price at the industry’s hub in Cushing, Oklahoma.” – great news for arb guys. While I haven’t done the work on a specific discount price, Mr. Sheffield is likely correct directionally. However, that’s a relatively micro-economic answer from my perspective, as I think there is potential for more disruption than tighter cash flows.

Depending on how long the constraints persist, less and less Permian product making its way downstream will be bullish for the overall oil and distillate markets (crack spread traders, rejoice), but bearish for Permian acreage. While I wouldn’t be concerned by the market’s ability to weather logistical problems and the pricing issues that come with them, I would be concerned about how any cash flow disruptions would impact heavily indebted private equity acreage assets. Should lower Permian prices be around for the long haul, the problem for PE firms (and their investment committees) becomes twofold: the first being that their cash flow profile is deteriorating, impacting their ability to service debt. The second is that the lower prices and inability to sell product into the market is killing their acreage value. The first indication that funds are looking for the exits could result in a mea culpa moment for everyone that plowed into Permian acreage in 2016, forcing a fire sale across the basin as nobody wants to be left holding the bag.

I don’t think this is a terribly likely scenario, but coming from a guy that worked in energy private equity from 2014-2017, I wouldn’t write it off, either. We’ll see what happens going forward, at the very least it’ll be interesting.

 

Here’s the Thing About Energy Markets…

“Bloomberg – A pipeline shortage that’s leaving gas trapped in West Texas’ Permian Basin means prices for the fuel there are the lowest of any major U.S. hub, wresting that distinction from Appalachia’s Marcellus Shale. Prices for Permian gas, produced alongside oil in the play, have tumbled 32 percent from a year ago, while output rose to a record. And the pipeline crunch is also pummeling the region’s oil market.”

Energy production has always been a highly capital-intensive business. The dirty little secret of the U.S. shale boom is that fracing (not fracking, that’s how they can tell who the Yankees are) is not cheap, no matter what it costs to fill your car up at the pump. The costs of equipment, surveying, labor, licensing, water, sand and waste handling will run into the millions before a single well even comes online. So what did the industry do to juice their returns and ease the burden on their end consumers? Everyone, say it with me now: they levered up! It’s no coincidence the U.S. shale boom coincided with the post-crisis era of cheap money. The ability to voraciously borrow money from investors looking for anything resembling a decent yield fueled the fracing boom, as well as its eventual demise.

I spent a few years in Houston at an energy-focused PE shop, so this is a topic that’s near and dear to my heart. The U.S. energy markets have been in disarray since the end of Q2 2014. Throughout the shale boom, the strategy for oil companies was to lever up or issue equity to fund acreage development, then turn around and sell the company or specific assets to a strategic buyer to pay down debt and cash out their investors. The playbook was similar for infrastructure sponsors, except they used the capital raised to fund new pipeline assets that they would drop down into MLP subsidiaries that would be brought public. They’d use the IPO proceeds, and any dividend payments from MLP shares they retained, to fund even more pipeline construction. It was financialization at its finest. Oil companies would then pay fixed rates on long-term contracts to the MLPs in order to have their crude or gas shipped around the country to refineries. This was all well and good until 2014, when the energy complex collapsed in on itself under the weight of debt and over-production.

This brings us to today (and to this Bloomberg piece). The MLP model still hasn’t recovered and I’m not positive it ever will. The big retail pitch for owning MLPs in a portfolio was that it was yield-generating energy exposure without the commodity risk (which was true, until it wasn’t). While the MLPs didn’t have direct commodity price exposure, they had indirect capital markets exposure, and that would be their death knell. Once oil producers started defaulting on their debt due to tanking commodity prices, the MLPs were shut out of debt and equity markets as well – a little guilt by association. Without access to fresh capital, the infrastructure sponsors were unable to fund new pipeline construction and sell the assets into their publicly-traded MLP subsidiaries. Now, with massive debt loads and capex commitments to unfinished pipeline projects, the infrastructure sponsors went into survival mode: cutting dividend payments, selling assets and operating strictly out of cash flow. That last part is important – operating out of cash flow meant using huge chunks of FCF to service debt instead of building pipelines, which is why the Permian is in the odd position of having inaccessible, near-worthless gas assets. That oil and gas isn’t worth shit without the infrastructure needed to sell it into markets, no matter how prolific your acreage is.

What a conundrum. All this PE capital flooded into the Permian in 2016 looking for bargain basement acreage deals – and they got them. Now that the PE firms are all there drilling, there is too much production coming online and too little pipeline to ship the stuff. This is ironic because oil and gas acreage assets are valued by what’s in the ground, not by what comes out and makes it to market. The new problem that will (inevitably) come to the forefront is that PE firms never pay for these assets with 100% equity capital, rather they almost always issue debt or take on a revolver and collateralize it with the asset alongside some equity to fuel the drilling capex. That leads me to wonder, if pipelines aren’t built quickly enough for these PE-sponsored DrillCos to ship and sell product, will funds run into cash flow issues and be forced to start liquidating at a loss or, even worse, engage their lenders for a little restructuring? Should either of those scenarios play out, it would have a ripple effect on acreage prices throughout the Lower 48, likely kicking off a deja vu of late 2014. Round and round we go.