The US electric sector is surprisingly easy to understand.  It’s big, capital-intensive, complicated and integral to our standard of living – which gives it a massive bias in favor of the status quo.  Neither its owners nor its regulators have any incentive to risk their money or their careers with sudden change.  This makes it fairly predictable: take what’s happening today, and assume that will continue indefinitely forward until such time as (a) we overshoot some fundamental technical constraint and/or (b) some regulatory action upends the balance of power in the industry.

There have been several, noteworthy instances where regulatory reform led to rapid change:  in particular, comprehensive energy bills passed in 1935 (PUHCA), 1978 (PURPA) and 1992 (EPACT).  But comprehensive, ambitious legislation isn’t the current Congressional toolbox.  So status quo is a safe bet.

However, that doesn’t infer stability of anything other than the trend line.  John Allen Paulos made a (painfully) amusing observation in his book Innumeracy that based on current trends, there would soon be a one year waiting list for abortions.  Thus do stable, linear sequences head inexorably towards physical impossibilities and system-wide disruption.   The US electric industry is currently riding atop several Paulos-like trends that are rapidly approaching practically impossible end-sates, primarily around generation reserve margins and congestion in the gas/electric distribution infrastructure.  Predicting when those limits will be reached is hard, but they’re close enough to make it worth watching out for these red-flags:

  1. Will an interruption in gas supply reliability lead to an interruption in electric grid reliability?  The reliability requirements imposed on the owners/operators of the electric grid are considerably higher than those imposed on the owners/operators of the natural gas infrastructure.  An inevitable consequence of natural gas’ transition from a peaking fuel to a base-load fuel is therefore  a reduction in electric grid reliability.  We could fix this with a lot more gas infrastructure, a lot more transmission infrastructure or a re-embrace of coal/nuke/hydro.  But none of those seem near-term likely.
  2. How will the northwestern US deal with low hydro capacity this spring/summer?   The NW US is uniquely dependent on hydro to serve as the balancing generation source.  The combination of rising wind penetration and conventional asset retirement has made the non-hydro sources much “peakier”, just as long-term water shortages are limiting the ability of existing hydro assets to fill in the gaps.
  3. How rapidly do capacity market prices move?   The market for capacity (a MW of available generation, as opposed to a MWh of output from same) has been depressed for a long time, removing the incentives for construction of new generation.*  To market purists, this reflects nothing more than a lack of a need for generation.  To utility CEOs, this reflects an inability of spot markets to reflect prices far enough in advance to start necessary permitting/construction cycles.  As planned coal retirements become real retirements, we’ll find out who’s right – but in either case, it will be too late to matter, so there’s an awful lot riding on as-yet untested economic theory.
  4. Is cheap wholesale gas and expensive gas delivery the new normal?  The gas shale boom continues to keep wholesale gas prices down, but the gas is increasingly not where it’s needed.  Over the last several months, we’ve seen unusually high natural prices on both coasts driven not by the commodity price, but rather by delivery charges (“basis” in industry parlance).  In theory, that creates an economic incentive to build new gas delivery pipelines, but those take time to permit & build.  What happens while we wait?
  5. When will the cost of coal retirements hit rates?  There is an unavoidable rate spike coming in the coal belt, paced only by math and politics.  Utilities earn a return on invested capital, over the life of that investment.  When assets are retired before they’ve been fully amortized, the outstanding balance hits rates.  That normally doesn’t matter – except when a wave of retirements comes at the same time, as is now the case with coal and the 2016/17 MACT compliance deadline.  The political pressure is always to kick that can down the road.  But there ain’t much road left between here and 2016.
  6. Does load growth return?  US retail electric sales have flat-lined since the recession after a century of steady ~1 – 5% per year growth.  Flat/falling loads are a path to insolvency in a capital-intensive industry, and utilities are justifiably scared by these trends.  (Their attack on DG/EE in 2013 is one response, but the underlying cause isn’t DG/EE – it’s the slowdown in electricity demand.)  We have no experience to suggest how this plays out, but…
  7. Watch utility credit ratings.  As investors watch these trends, we’ve seen a steady degradation in utility bond ratings.  This is driving up utility costs of capital, precisely at the time when the sector needs lots of capital for transmission, fuel conversion & pollution controls.  At some point, this is going to lead to a shortfall between capital needs and capital supply… at which point grid reliability is at risk.

Not all of these events will happen in 2014, and it’s possible that none of them will.  But they are interdependent, in the sense that the occurrence of one tends to increase the probability of another.  And since they are all driven by long-term trends, they are all inevitable eventually.   So that at least makes it worth watching out for them, and hedging against where you can.

In the meantime, buckle up.

* That is to say, generation that contributes to peak capacity delivery.  Other generation types (notably wind) have been built, but in response to different sets of incentives and therefore do not generally have the capability nor contractual obligation to serve peak load.