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In yesterday’s daily write up (sign up for Mobius’ Daily Market Update) we briefly mentioned the importance/value in understanding intricacies in the U.S. power stack in order to assess what is on deck for the natural gas market as we approach peak cooling season. In today’s Friday Focus we will take a slightly deeper dive, and at the same time want to impress upon any reader that this piece will simply be another step up the ladder, and not meant to be an apex/conclusion drawing body of work.

The first step in better understanding how the U.S. natural gas market is set move through peak summer, in respect to consumption of natural gas in the power sector, is to carve up the U.S. into geographic regions in manner which both captures natural gas intensity in the power stack, as well as a modicum homogeneity in terms of market pricing. While discussions on gas-to-coal or coal-to-gas switching often center on the change in Henry Hub (NYMEX) pricing the reality is a decision on which units get dispatched is based on regional gas and electricity pricing. 

For the sake of this introductory primer on the U.S. power stack we will define individual regions as follows: Northeast = all states north of Virginia and East of Ohio, Southeast = all states South of and including Virginia and East of Louisiana, Midwest = all states between the Dakotas and Ohio and north of Oklahoma, South Central = TX, OK, LA, and AR, West = all other states not previously categorized. Clearly this requires some imagination as a visual will not be provided, and ideally our readers are geographically inclined enough to get the general layout.

In the Northeast population density is obviously centered on a few major metro areas, and unsurprisingly population density will have a direct correlation to overall power load. The New York/Newark area is clearly at the forefront, followed by the Boston area, and rounded out with the major metro areas in Pennsylvania. 

In the Northeast, the past 7 years have seen a rapid decline in available coal and heating oil generation capacity, as well as a noteworthy loss of nuclear capacity. This has prompted an increasing reliance on natural gas fired power, particularly in the summer months. Since 2014 approximately 10 GW of coal capacity in the Northeast has been scrapped, along with 6 GW of heating oil capacity, and in the past couple of years there is has been an accelerating loss of nuke capacity, which brings the 7 yr total decline in nukes to approximately 4 GW. Collectively losing 20 GW of capacity from these 3 sources has been met almost 1-for-1 with new natural gas fired capacity while renewable generation capacity has increased by a modest 3 GW. 

Throughout this report it will be important to remember that renewable generation runs at a much lower capacity factor than fossil fueled or nuclear capacity, simply because the ‘fuel’ sources are highly unpredictable and cannot be created through economic incentives.

Turning back to the Northeast it should be relatively obvious that gas intensity has increased substantially since 2014, the last time Henry Hub pricing was anywhere near $4.00. The ability to run the power stack on an alternative fuel source when regional NG prices spike is limited as a result. The past week has demonstrated the impact of this dynamic.  Temps were considerably warmer than normal creating sharply higher demand and likely a single digit natural gas storage injection for the region (Thursday 7/8 report date). When looking forward to the balance of summer there are two important things to consider. First, temps are going to be similar to warmer for the next couple of months barring a significant negative delta v. normal, before quickly cooling in the last week or two of August, of course barring a late summer strong positive delta v. normal. Secondly, the current forward strip for regional markets serving this region are weak in the producing area (Appalachia) thus the advantage gas holds over the minimal amount of ‘switchable’ non-gas capacity is still present in August and September.

Migrating south to a region with the capability of delivering market shifting power consumption numbers shows a slightly different dynamic, but thematically the same trend. The Southeastern U.S. has seen a whopping 27 GW of coal capacity permanently sidelined over the past 7 years along with 4 GW of petroleum fired generation capacity. The difference in this region v. the Northeast and for that matter all other regions is that nuke capacity has actually increased. The Southeast has seen nuke capacity climb from roughly 34 GW to almost 36 GW. Rounding things out there has been a renewable generation add of 10 GW, and a natural gas fired capacity addition over these same 7 yrs of just under 17 GW. 

This region does still have material switching capacity, however, it is critical to remember that during the mid-summer months it is an all hands on deck approach when temps are normal, and even more so when the mercury rises above normal. Until October there will likely be a marginal ability to reduce natural gas consumption for power versus what we have seen in June (on a weather adjusted basis) regardless of where we price from here. For clarity, this final statement on the Southeast is in respect to prices moving higher, as a sharp move below $3.00 while unlikely would create an noticeable uptick in Southeastern U.S. natural gas consumption in the power stack.

Sliding westward and into the South Central U.S. there is now a vey well know situation whereas the peak-to-trough impact of wind generation dramatically impacts the call on natural gas in the power stack. This was painfully experienced back in February and so far during the summer months we have witnessed the volatility in gas generation these peaks and troughs can create. The EIA reference week of June 17th was a hot week in Texas and Oklahoma with wind gen in these two key states plummeting and the resulting call on natural gas caused the EIA’s South Central storage region to post net withdrawal of 4 Bcf. Historically speaking the South Central is prone to withdrawals in July and August, but a net reduction in inventory in June of this year shows how the changing stack in this region is susceptible to steep increases in gas demand even without peak summer heat.  A repeat of the June 17 storage week is highly likely in the next weekly installment of the EIA inventory report, with a net withdrawal likely.

In terms of changes in available capacity the South Central region has seen a loss of 8 GW of coal capacity and a 21 GW increase in renewable capacity. At an effective capacity of 50%, which is generous, the add in renewables slightly outpaces the loss of coal. When capacity factors for renewables plummet the call on natural gas sky rockets, and this is a relatively frequent occurrence during the summer, and more acutely so when temps spike as this typically coincides with hotter temps. If the renewable portion of the stack weren’t so heavily tilted towards wind (>90%) this might not be such an issue, however, as it currently stands a peak summer ’21 heat wave in the South Central carries both the risk of West Coast like rolling blackouts, and parabolic increases in gas demand.

Marching northward to the Midwest there is a distinction in this region that has implications for other locales when it comes to peak summer temps. The Midwest has held on to coal gen for much longer than other regions following the first major coal-to-gas switching event in 2012. This is primarily due to the fact that installed combined cycle gas plants are not as prevalent as in other regions. Looking back over the past 7 years you can see how this reality has impacted summer natural gas demand. Since the effective heat rate of the natural gas fired power stack in the Midwest is significantly higher than other regions the amount of gas required to produce a MW of power is higher. Simplistically this means the natural gas price which triggers a gas plant to run in place of coal is often lower. In a subsequent Friday Focus we will likely spend more time explaining the calculations that impact this decision, but for now bear with us and assume a Midwestern 10 heat rate gas plant consumes 35-40% more gas per MW produced than a comparable combined cycle in the Southeast or South Central. 

Ramifications of this reality in the Midwest create wildly volatile changes in power consumption when the natural gas portion of the stack is called on. However, for context the lack of installed natural gas fired capacity in this region also means these wildly volatile changes are relative to the percent change rather than the overall number of MMBtus consumed. It is not uncommon for the Midwest to use 2.5x more gas for power on a hot week in mid-July or early August than a normal week in June, albeit never even reaching a minimum burn day in the Southeast. 
Like the South Central, the Midwest is subject to large swings in wind generation, and the week ending today was precisely one of those weeks. Poor wind performance in MISO drove material changes in gas consumption and the result may end up being a 10 Bcf or lower inventory build issued when the final tally is posted next Thursday. 

The read through from the Midwest to other regions is the critical understanding of how climbing the heat rate curve in the natural gas portion of the power stack can bring about sharp changes in consumption. Again, we will cover this in more detail at a later date, but please know that when temps spike towards the century mark all regions begin calling on a proverbial quick action force known as peakers. These peakers can range from a 9 heat rate up to a 15 heat rate. Back of the envelope math illustrates that for every 50 MWh of power that is served by a 12 heat rate peaker you consume 14,400 MMBtus of natural gas, which compares to 8,400 MMBtus for an efficient combined cycle. Extrapolate this quick calc to a spike in regional demand of 5,000 additional MWh and the scale becomes material. While the issue is particularly acute in percentage terms in the Midwest, the magnitude of this dynamic is market moving in the South Central and Southeast.

Finishing our trek across the natural gas fired power landscape in the U.S. we will take a more abbreviated look at the West. This region really needs to be broken in to sub-regions and understood through a different lens due to the impact of hydro-electric generation and how it can dramatically skew the effects of overall power load relative to the call on natural gas. In the West installed capacity has seen the following changes since 2014:
Coal: -6 GWNatural Gas: -4 GWSolar: +13 GWWind: +5 GW

Challenges facing the West are not as related to changes in the stack but more related to both the distribution of power and natural gas. Most large scale renewable projects are a significant distance from the load, and the amount of pipelines bringing natural gas in to the market areas is essentially unchanged in the past decade. These two points are born out in the fact that the West Coast is now experiencing a reign a top the basis throne with the most expensive natural gas in the country over the next year.

Please reach out to us if you need greater detail on any of the above regional dynamics as they relate to your natural gas or power price exposure.