Revisiting Texas's Electrical Power Predicament—Part 3

I hadn't intended there to be a part 3—but I would like to share three interesting pieces of news that nicely fit in with some themes of this series, and, I have a bit of free time on my hands this weekend to write about it.

The Bankruptcy and Restructuring/Breakup of Energy Future Holdings

Energy Future Holdings, Texas's largest power provider, came into existence in 2007 with a $45-48 billion leveraged buyout of TXU Corporation, as brokered by the likes of KKR, TPG and Goldman Sacks.  Overvaluation of TXU's assets, especially in the face of the subsequent economic depression of 2008 and continued low energy prices (thanks to the fracking boom), has made it impossible for EFH to repay the increasing debt burden associated with the LBO, and now, bankruptcy looks inevitable (see, Greed doomed the TXU buyout).  The recent departure of KKR CEO, Marc Lipschultz, for the Board of Directors of EFH probably signals a likely Chapter 11 restructuring of EFH's assets.

EFH is the parent of three subsidiaries: Oncor, which handles electricity transmission to 3 million customers, TXU energy, the states' largest electricity retailer, and Luminant, which generates about 18 percent of Texas' electricity, at least in the summer months.  Both Oncor and TXU energy look economically viable, and therefore, are attractive subsidiaries to buy. 

As I wrote in Part 2, Luminant owns five of those old coal-fired electricity generating plants, some of which have been getting mothballed during the winter month, and, which are too unprofitable, at least a today's energy prices,  to retrofit to comply with the Clean Air Act requirements.  Those five plants have a name-plate capacity of about 8000 MW which correspond to about 11-12 percent of Texas power generation capacity at any given time during the summer months.

There is speculation (In Energy Future Holdings shakeup, size matters) that a restructuring would go easier if the coal-fired plants were to be split off from Luminant's nuclear and natural gas, and, further speculation, that as part of a restructuring, those coal fired plants will not just get mothballed, but torn down.  I wonder who would want to buy Luminant if the maintenance or retrofitting these five plants was part of the deal (even a tear down of these plants would be very expensive, I think).

If the closure of these five plants were to happen, however, then ERCOT's summer power reserve margins would get blown away.  For instance, a loss of 8000 MW of power generating capacity would drop ERCOT's previously expected reserve margin from 13.6%, for the summer of 2014, to only 1-2%.  Under this scenario, I would expect that that there would be multiple rolling blackouts, and a spike in electricity prices, this summer.

Does the fate of Texas' coal plants and potential permanent loss of 8000MW of power have ERCOT worried or sounding the alarm?   Why no, quite the opposite.

ERCOT'S Revised Load and Reserve Margin Forecast

In a dramatic turn-around from its previous forecast of May 2013, Capacity-Demand-Reverse Report for 2013, in January 2014, ERCOT announced peak demand margins going forwards that implies that the possibility of rolling blackouts is remote.    There is no electrical power predicament after all.  

What happened?

Instead of an annual growth rate in peak electricity of 2-3 percent/year, as predicted by ERCOT last May 2013, ERCOT's new forecast predicts 1.3±0.1 percent/year demand growth for the next decade.  This results in a dramatic increase Texas's expected reserve margin for the next several years. 

What is the reason for this abrupt about-face?  ERCOT explains:

In the past, ERCOT has used weather and economic indicators, such as non-farm employment, to forecast future electric demand. However, the relationship between economic growth and electric demand has changed in recent years. While peak demand growth has slowed to about 1 percent annually, the economic forecasts and non-farm employment statistics used in recent load forecasts have resulted in growth forecast estimates of 2 to 3 percent in the two- to three-year outlook.

This recent trend implies a less direct correlation between these economic indicators and electric demand than in the past. To address this decoupling, ERCOT staff has developed a new load forecasting model that uses forecasted growth rates in customer accounts, or premises, to project future growth trends in each region served by the ERCOT grid.

In short, ERCOT's new model assumes a decoupling between electricity demand growth and economic indicators, such as employment, and instead now looks at growth rates in customer accounts or premises to predict future electricity demand.  

In a another publication describing this new method of future load forecasting (based on a neural network model) ERCOT presented a figure which I think sums up their reason for adopting a new model (Figure 5):

As you can see, starting from the mid 1990s, there has been an increased decoupling between electricity demand and GDP.  ERCOT attributed this to things like increasing efficiency of electrical devices (think light bulbs), declining energy use per customer and improvement in electricity distribution.  But maybe there are other reasons as well.

Based on this new model, at the end of February 2014, ERCOT came out with its latest Capacity Demand and Reserves Report (CDR)—the report being released four months earlier than previous in years.  In particular, a new Summer Summary prediction for demand, capacity and margins, reproduced in Figure 6 below, reflects the new margin and peak demand estimates.

The result of the new model is a prediction of much higher reserve margins than previously forecast.  For instance, the reserve margin (red) is predicted to actually go up to 15.4% in 2015, and, it doesn't drop below 13% until after 2018.  In contrast, the May 2013 CDR (Figure 4) had predicted the 2018 margin to be 9.4%.  Notable, 13.75% has long been considered an acceptable target reserve margin by ERCOT.

With peak demand growth assumed to be 1.3 percent/year, the Feb 2014 CDR predict a peak power demand (blue) of 71806 MW by 2018, which is ~4400 MW lower than the peak power demand of 76186 MW by 2018, predicted in the May 2013 CDR.  

Moreover, this increased margin is in spite of the 2018 total power resources being lowered from 80760 MW, as predicted in the May 2013 CDR, to a predicted 79575 MW in the Feb 2014 CDR.

Brattle Group Report (BGR)

Commissioned by the Public Utility Commission of Texas (PUCT), this report published at the end of January 2014 attempts to estimate the "economically optimal reserve margin for ERCOT’s wholesale electric market."

The bottom line of the BGR is that, from an economic perspective, a reserve margin of 13.75% is "inefficient" because it is designed to meet a one-day-in-10-year load loss event (0.1 LOLE)—a standard to ensure loss of power, on average, only 1 day in ten years.  Instead, the BGR recommends a new reliability standard that would be more "economically optimal."  This new standard, termed, "expected unserved energy" (EUE) standard, weighs the "total system" cost of building more power generation plants to keep the reserve margin high, versus the costs related to a "scarcity-event."  The BGR finds that only a 9-11% reserve margin is economically optimal.  The report estimates that a 11.5% reserve margin, would be insufficient to meet peak loads only once every three years.  On average, a 1600 MW short fall would only need to be curtailed for 2.6 hours on average during such "load shedding" event.

Interestingly, this report was shortly followed by a memorandum to ERCOT from PUCT commissioner Anderson questioning the need for PUCT or ERCOT to take any quick action based on this report:

If the Commission were to adopt a mandatory reserve margin, what Brattle refers to as a “reliability based standard,” they recommend the adoption of the “normalized expected unserved energy” (EUE)⁶ standard because it considers the magnitude and duration of events among its factors.⁷ Adopting a EUE approach would constitute a total redesign of ERCOT’s reliability standard, which should not be done without careful evaluation by the Commission and the ERCOT stakeholders. Analyzing the EUE recommendation should be conducted as part of a truly broad and intensive study of the appropriateness of ERCOT’s reliability standard and resulting reserve margin.

The BGR's assertion that a 10 reserve margin is contrary to the North American Reliability Corporation’s estimate of an acceptable reserve margin of 15 percent—a margin that ERCOT has not been able to attain in the past several years.

Summary and Thoughts

I don't think that it a coincidence that the early publication of ERCOT's Capacity Demand and Reserves Report, and, the publication of Brattle Group Report are being released just as Texas's largest electricity provider, Energy Future Holdings, heads into bankruptcy. 

The new Capacity Demand and Reserves Report suggests much a lower rate of demand growth increase, and therefore Texas, can have "acceptable" reserve margins of 13.75%  for the next several years.  Brattle Group Report goes one further in suggesting that this 13.75% margin is way too high and could instead be 10-11% for "economic optimization." 

Let's just set aside the apparent paradox of ERCOT adopting a new method of predicting demand growth that specifically does not directly consider economic indicators, and, the BGR that specifically recommends lower reserve margins based on "economic optimization."  

To me these two reports may be setting the stage for a restructuring of Energy Future Holdings where those five coal-fired plants are rapidly phased out of ERCOT's power grid.  The ability to eliminate these uneconomical  coal-fired plants would make the purchase Luminant more attractive. 

Still, the loss of 8000 MW of potential power provided by the five plants reduces ERCOT's summer reserve margin to only 1-2 % and that would be a problem. How can we reconcile this?  

It seems like a no-brainer to say that, for at least the near future, at least some of these coal-fired plants have to be maintained and de-mothballed each summer in order to provide an acceptable margin of peak demand.  

But, perhaps now in light of the new CDR and BGR, it will seem more acceptable for some plants to be decommissioned immediately or next year. 

For example, consider the new CDR shown in Figure 6.  According to ERCOT, for 2014, summer resources equals 74805 MW and firm load equals 66179 MW, giving a 13.5% margin.   If one were to eliminate one or two coal-fired plants with a total capacity of about 2000 MW, then resources drops to 72805 MW, and therefore, the new margin becomes 10% which just happens to equal BGR's "economic optimum."  Likewise for 2015, if coal-fired plants with a total capacity of about 4000 MW are eliminated, then the margin again equals 10%.    

In my opinion, not running one to four of these coal fired plants during the summer months would obviously increase the risk of load shedding or rolling blackout events.  Texas only needs to have a summer as hot as the summer of 2011 to test this.  Perhaps from the Battle Group Report author's perspective, cozy in their offices in Cambridge, Massachusetts, the prospects of industrial and residential load shedding and rolling blackouts for several days in August fall within the scope of "economic optimization."   After all, this is estimated to only be for 2-3 hours per day and only occur every 3-4 years.  

I seriously doubt, however, that that the "total system"  economic repercussions of an electricity "scarcity-event" has been fully accounted for in the BGR.  For instance, will businesses still want to relocate to Texas when they hear news of several days of rolling blackouts or load shedding by  industries and residents in the summer months?  Also "economic optimization" does not necessarily mean optimal for human living.  People, especially the elderly, suffer or die in the summer in Texas when the air-conditioning goes out.   Is that considered as part of the "total system" cost?   Maybe, from an economic perspective, who cares, so long as the state government, PUCT or ERCOT doesn't have to pay for it directly. 

And, what about looking further out to more than a few years?  Look again at Figure 6, for 2020 and beyond.  Even with Luminant's coal-fired plants considered as part of the summer resources and assuming only 1.3%/year peak demand growth, the reserve margin was predicted to drop below BGR's "economic optimum" of 10 percent.  What then? 

With the present stricter enforcement of the Clean Air Act and other EPA rules, the prospects building of new power plants that would provide significant base load (i.e., coal, nuclear or even natural gas) in time to mitigate the reserve margin drop look very remote. The price of electricity would have to rise significantly before that would happen, I expect.  But doubling or tripling electricity prices would cause demand to go down.  And, there you have a downwards energy spiral, Texas-style.

Perhaps targeting peak demand growth to customer account growth does make more sense than using employment or other economic indicators.  After all, an unemployed Texan probably moves out of their own residence and moves in with someone else, moves out of state, or, out on to the street.  Consequently, their utility provider account gets closed. Of course, such repercussions of scenarios are really not ERCOT's problem.  Again the this reflects a difference between an "economic optimum" versus a "human optimum."

From a broader perspective, the increasing decoupling between GDP and electricity use (Figure 5), to me, just represents the increasing decoupling of GDP numbers from reality.  That is, the increased churning of digital money between parties all counts towards GDP, which increasingly, has little to do with the real physical world or  the life of the average human. 

Revisiting Texas's Electrical Power Predicament—Part 2

I ended Part 1 with questions about the future of older coal fired electricity power plants and the possibility of replacing plants and expanding electricity demand as Texas's economy and population continue growing.

The demise of coal-fired plants

Back in late 2011, the owner's of Monticello coal-fired plant in Titus County, Luminant, had threaten to shut down or "idle" rather than implement costly upgrades  to put the plant in compliance with the Clean Air Act, and, ERCOT suggesting that they couldn't force Luminant to keep a plant open in violation of federal pollution rules (see e,g,m Texas power grid operator says blackouts possible). 

What happened to these and similar coal fired plants? 

It appears that the Monticello plant was mothballed for the winter of 2012.  The plant capable of producing 1,880 MW, enough to power 0.94 million homes in normal conditions, apparently was not needed in winter months and therefore was not given a “Reliability Must Run” designation by ERCOT.  After re-opening for the summer of 2013, the plant again was mothballed for the winter, and Luminant requested to also mothball its Martin Lake coal-fired plant for the winter (A Changing Market and Dim Future for Coal in Texas).  Martin-Lake has a capacity of 2,250 MW enough to power 1.12 million homes.  Altogether, Luminant owns five coal-fired plants with a name-plate capacity of 8,017 MW—I wonder if eventually all five of these plants will get shut down during non-summer months. 

Although part of Luminant's reason for mothballing the plants is stiff economic competition from power generated by natural gas plants, I think that it is the cost to comply with the EPA rules under the Clean Air Act is what will lead to the eventual demise of all of these plants. 

Indeed, last summer, the DOJ, at the behest of the EPA, filed a law suit against Luminant alleging continued violations under the Clean Air Act, citing the Martin-Lake plant and the Big Brown Power Plant, located near the Dallas-Fort Worth area (Luminant hit with suit alleging Clean Air Act violations).  Luminant has argued for special protection against the Clean Air Act for violations during startups and shutdowns,and  the Fifth circuit agreed, but then, the denial of an appeal to the Supreme Court doesn't bode well for eliminating the possibility of subsequent law suits attacking this theory. 

Additionally, CPS Energy, in San Antonio, appears to on track with its plan to shut down entirely the JT Deely coal-fired plant at the end of 2018, citing as the reason the high cost for environmental retrofits to comply with new emissions requirements. The Deely plant which has a power generating capacity of 871 MW will be replaced with a natural gas-fired plant. 

A new coal fired plant, the Sandy Creek plant near Waco, with a 900 MW capacity, did come online in 2013.  Its opening, however, was only after a settlement with the Sierra Club who had fired a lawsuit against the plant's owner alleging violations of the Clean Act, among other things.  After years of legal battles, as part of the settlement the owners agreed to pay for stricter air pollution controls and to not build coal-fired plants in Georgia and Arkansas.  The Sandy Creek owners are still embroiled in legal battles with a company, NAES, hired to maintain and operate the plant, alleging that NAES's mismanagement damaged the plant's boiler (Sandy Creek power plant owners suing over 2011 boiler incident). 

It is apparent to me that no additional, Clean Air Act Compliant coal fired-plants will be opened in Texas any time soon (if ever)  due to litigation costs, federal regulations and the present low price of natural gas (After White Stallion Power Plant Canceled, Coal Faces Dark Future in Texas). 

A power vacuum

While some see this as "big win for clean air in Texas," and it probably is, I wonder how this will impact Texas's ability to meet its growing power demand. Are there any non-coal power generating projects underway to actually expand the power grid and not just replace the existing capacity produced by the coal plants being mothballed or shutdown? 

In an interesting Forbes article, Will Summer Blackouts Doom The Texas Boom?, Christopher Helman gave a summary of Texas's energy status going forward.  New electrical capacity from Nuclear Power does not appear to be in the cards given the blockage of to two new Japanese Toshiba reactors.  Two 760 MW capacity gas-fired plants owned by Panda Power are scheduled to come on line in 2014, and there is a third plant scheduled to come on line in 2015.  The 540 MW natural gas-fired Ferguson power plant in Llano in 2014 will replace the old 420-MW plant which closed in the fall of 2013.  Such gas fired plant are important to ERCOT for their ability ramp up quickly when electricity demand spikes—something that wind or solar power, or, even nuclear or coal are NOT particularly good at.   Finally, Helman's article talks about another 3,000 MW of wind power set to be built by 2015.  But even if all of this wind power is built, for reasons already discussed in past articles in this blog, on a hot Texas summer day, one might only expect to get ~10% or less of the name plate capacity from wind.

That seems to be about it—about 1,500 MW in 2014, and another 1,000 to 1,500 MW in 2015, depending on how you feel about the wind power contribution you could count on in the summer.

Keeping in mind that at a peak summer power usage of around 67000- 68000 MW, and, the need to grow the capacity by about 2 percent per year, ERCOT's goal should be to add about 1350 MW capacity per year every year, just to keep it's reserve margin about constant.

But ERCOT's own Capacity-Demand-Reverse Report for 2013 shows their expectation of a shrinking reserve capacity, going forwards (Figure 4). 

As illustrated (red circle), ERCOT expects its summer reserve margin to steadily decline from a margin of about 13.6% in 2014 of total capacity to 4.5% by 2023.  For comparison, the North American Reliability Corporation’s acceptable reserve margin is 15 percent, and, NARC estimate of Texas's reserve margin to be 12.9%. NARC indicated that the peak demand growth rate in Texas (about 2.7%/year) is projected to be the highest in the United States.

It is noteworthy that the growth in year-to-year summer peak demand shown in the above table (blue circle) appears to be based on (or is equivalent to) an assumption of demand growth increasing by 3 percent per year (e.g., 72071 x 100%/69807=103 %) for the next few years, and then, suddenly slowing down to less than 1 percent per year by 2021.   I don't know where these projections come from. 

If I take ERCOT's 2014 "firm load forecast," and increase it by a constant 2 percent per year every year, then the reserve margin drops below 0% by 2023.  If I take that same 2014 firm load forecast and increase it by a constant 3 percent per year every year, then the reserve margin drops below 0% by 2020.  Of course, weather is the wild card, and on any one summer day, particularly hot weather could shift ERCOT into emergency load shedding.  We already know from the experience of 2011, and ERCOT's own emergency plans, that coming within ~3.4 percent of power resource capacity would trigger industrial load shedding with rolling blacks outs to follow soon afterwards.  Texas has just been lucky so far.

ERCOT has done two other things in an effort to mitigate Texas's inadequate and declining reserve power margin.

Understanding that Texas needs the summer capacity from the aging coal-fired plants like Monticello, Martin-Lake and Big Brown, ERCOT has raised its price cap on wholesale electricity, presumable to motivate owners, like Luminant, to de-mothball these plants every summer and supply an important part of the based load summer power capacity.  A coalition of these power providers are pushing for some kind of guaranteed compensation in the form of permanent cap increases to keep these plants available for summer use in the years ahead (Rolling blackouts are Texas' future without reform, generators say)

I don't see this as a workable solution, given that in 2014 the EPA wants to implement more stringent rules for CO2 emissions from existing plants, and, none of the existing plants in Texas are in compliance with such limits.  The owners of these plants, like Luminant, find the costs of retrofitting these plants with carbon capture technology "unworkable." (Texas electric grid getting greener even before EPA crackdown). 

If, for example, Luminant decided that it wasn't financially worthwhile anymore to "de-mothball" the Monticello and Martin-Lake  plants for the summer and just leave them closed for the summer of 2014 and beyond, then that would drop ERCOTs power generating capacity by about 4000 MW. The 2014 reserve margin would then drop to 7.8% percent and to only 4.8% by 2016.  I'm not sure who the public would blame for the likely ensuing rolling blackouts—the EPA, Luminant or ERCOT?  Would the Clean Air Act rules be waived after a few summers with extended periods of rolling blackouts and people dying from heat exhaustion?  Perhaps we will see.

The other thing that ERCOT is doing is promoting voluntary conservation.  In 2013 ERCOT introduced a voluntary pilot program, the 30-Minute Emergency Response Service ("30-Minute ERS), for homeowners groups and commercial users to be compensated for cutting their electricity use during times of peak demand when power supplies are tight and prices spike, if, they can reduce power use by at least 0.1 MW within 30 minutes (ERCOT plan rewards electricity cuts during peak demand).  Presumably this option would be implemented at Energy Emergency Level 1, when the grids' reserve margin drops below 2300 MW.   This pilot program is still being tested, but from a November 2013 report with about 1600 potential participants it looks like the 30-Minute ERS could produce reductions of 100 to 200 MW.    

With over 6 million residential smart meters installed across Texas the potential impact of some form of residential power load shedding program is much larger than this.  Residential load shedding would work best if those volunteering for the program simple have their power load shed automatically as needed by the electric utility via a smart meter. For instance, PUC of Ohio is advertising how smart meters will give customers the opportunity to "assist" PUC through voluntary “load shedding” where PUC will send signals to thermostats and other appliances to adjust the devices’ activity until another signal is delivered to restore normal activity. I would think that a special device would have to be installed so that the power company could selectively remotely control these appliances.   But perhaps a smart meter could be used to more grossly limit the total amount of power flowing into individual households.  A smart grid controlling smart meters has been proposed as a solution to mitigate Pakistan's terrible grid problems by Dell.  Pakistan is currently facing a power generation shortfall of 6000 MW which results in 8-12 hours blackouts throughout the country.

Of course, the "carrot" to volunteer for such programs will be a price reduction, or rebate, when and if your power load gets shed (ERCOT will pay homeowners to conserve electricity this summer).   Low income customer will be attracted to this, and, a partial shutdown of certain appliances is certainly preferable to full-scale rotating blackouts.  Those who can afford to pay a higher price for electricity need not worry about such inconveniences—for now.   

Winter power woes

One final note that involves those those coal-fired power plants that are mothballed over the winter and the reliability of the grid.  I expect that mothballing will be a growing trend if natural-gas prices stay low and rules under the Clean Air Act become increasingly stringent and enforced. 

But mothballing a significant portion of the States' steady base load capacity can start to affect power reliabilty during the winter months.  Last November 2013, a cold winter snap caused Texas to have its highest electricity use on record for the month of November of 46,931 MW on November 26. The previous month, October, had also set a new demand record of 54,710 MW for that month.  The absolute magnitude of this amount is paltry compared to the summer month's daily peak usages of 66,000-68,000 MW, but it is during the fall and winter months that power plants either get mothballed or shutdown for servicing.  Still, despite these records set in October and November, I saw no reports of the Texas power grid being stressed. 

A few weeks later on December 6, about 250,000 people lost power in the Dallas Ft, Worth Area during that week—but that was due to downed frozen overhead power lines from a massive storm of freezing rain. Once again there were no reports of the power grid being stressed. 

On Monday, January 6, another cold snap through Texas did cause ERCOT to issue a Energy Emergency Alert and implement “demand response" mitigation with entities that contract to reduce their electric use when needed.  What was the demand level that cause this alert?  Only 55,486 MW—just slightly higher than that October record.  

Power consumption of 55,486 MW was enough to get to an Energy Emergency Alert Level 2, meaning that the reserve capacity was less than 1750 MW.  Texas was probably less than 1000 MW away from rolling blackouts, I suspect.   At the heart of the emergency was the unexpected loss of 3700 MW of power production capacity from two plants that had equipment failures due to the cold weather.  That caused ERCOT to import about 1000 MW of power from the Eastern USA and Mexico and for wholesale electricity prices to hit the cap limit set by ERCOT. 

While the loss of 3700 MW from these two unnamed plants might have been a "surprise," what was not a surprise was the about 10,000 MW worth scheduled plant shut down in capacity for maintenance and mothballing. 

What about the winter wind?  Well that Monday, the wind capacity at ERCOT's disposal was 17 percent of the 10,400 MW nameplate capacity, providing about 1782 MW or 3.2 percent of the grid's total power generation.  (Role of Texas wind power debated after winter emergency; Did Wind Really Save Texas from Rolling Outages?).  I think this just goes to show, once again, that wind can provide some base load capacity but that base load contribution will variable.  There still has to be enough steady base load (coal and nuclear) and variable (gas) capacity to provide a reliable power margin.  In my opinion, as the coal-fired plants get mothballed in increasing amounts, the size and reliability of this margin will diminish.

This Saturday, January 18, ERCOT issued another Level 1 energy emergency alert after yet another expected/unexplained power plant outage of 1200 MW.  As noted by one reporter, Saturday morning was rather unremarkable weather-wise, with temperatures in the 50s°F.  It is hard to imagine that this plant outage was due to equipment failure from cold weather.  Once again, a Level 1 alert is issued when the margin drops below 2300 MW, so the loss of 1200 MW from one plant was enough to drop the grid below this margin.  If this plant had gone out the week before, then there highly likely would have been rotating blackouts in Texas. 

These alerts underscore just how close Texans are living near the margin for rolling blackouts—trying to walk a tight rope between high prices, federal air pollution regulations and a reliable electricity grid.

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This has been my first "free" weekend since October, where I have not either been sick, working, or, both!  I will be back again, to what has become this occasional blog, as time and health permits.  

4-6-2014: clean up some types and add to legend of figure 4.