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EBA International Committee’s “Energizer” Explores Aspirations and Challenges in European and U.S. Electric Systems’ Efforts to Bring More Renewable Resources Online

By Ken Barry


(Pictured from left to right, Robert Ichord, Non-resident Senior Fellow, Global Energy Center, The Atlantic Counsel, Will Polen, Senior Director, United States Energy Association, John Moura, Director, Reliability Assessment and Systems Analysis, North American Electric Reliability Corp, and Tim Burdis, Lead Strategist, State Government Policy, PJM.)

How are European countries navigating the challenge of “decarbonizing” their electric grids without jeopardizing reliability or impairing their economies?  And how are U.S. utilities rising to that challenge, albeit with more natural resources at their disposal?  These were the overarching topics at EBA’s International Energy Law & Transactions Committee’s “Energizer” lunch on March 28 featuring four well-versed panelists:

  • Robert Ichord, Jr. –- Non-resident Senior Fellow, Global Energy Center, The Atlantic Counsel (Ichord served as both panel moderator and speaker);
  • Will Polen, Senior Director, United States Energy Association (“USEA”);
  • John Moura, Director, Reliability Assessment and Systems Analysis, North American Electric Reliability Corp. (“NERC”); and
  • Tim Burdis, Lead Strategist, State Government Policy, PJM. 

Introduced by Committee Chair Julia Weller, the program, held at the offices of the USEA in Washington, D.C., explored these issues in detail: (1) the struggles of Germany to cost-effectively implement ambitious, government-directed goals for increasing wind and solar power; (2) the experiences of Southeast Europe nations, despite having sparser regional interconnections and financial resources than their EU counterparts, seeking to up their renewable energy game to improve their chances of gaining EU membership; (3) NERC’s perspective on the technical challenges of bringing significantly more intermittent energy online, consistent with its reliability standards; and (4) the critical role of an RTO (i.e., PJM) tasked with facilitating its members’ compliance with state or corporate renewable resource goals without compromising reliable transmission operations or resource adequacy criteria.

Germany’s Challenges.  Leading off the discussion, Atlantic Council’s Robert Ichord stressed a major difference between the U.S. and the European paths to integrating greater amounts of intermittent renewable energy: North America has an abundance of low-cost natural gas to serve as a complementary fuel to wind and solar generation, while Europe does not.  About 70% of the natural gas used by EU nations must be imported – largely from Russia – raising both security and cost concerns.  The high cost of such imports has, moreover, enabled coal and lignite in Germany to outstrip natural gas in powering generation. 

Ichord then sketched the EU framework governing member nations’ energy usage – a tangle of “treaties, directives, opinions, regulations, and implementing acts” that provide oversight and add complexity to each nation’s energy policies and goals.  The EU’s proposed “Winter Package” of directives and regulations, dubbed “Clean Energy for All,” is meant to usher in a suite of structural reforms, market design fixes, and green energy targets.  A key goal of the Package, which is currently under review, is to make the Europe’s electric and natural gas networks and markets more closely knit, competitive, and accessible to third-party energy producers, overseen by independent regulators and spurred by the elimination of cross-border tariffs.

Ichord perceives an inherent tension between the drive to create a more vibrant commercial energy market while, at the same time, supporting the EU’s commitments under international climate accords to substantially reduce greenhouse gas emissions. Noting the region’s previously adopted “20/20/20” goal of emissions cuts, efficiency improvements, and market share of renewables across all forms of energy use – each by a factor of 20% – by 2020 (using a 1990 baseline), Ichord stated that the members are pretty much on target to hit these marks.  However, just prior to the Paris climate agreement in late 2015, the EU raised these targets to 40/27/27 by 2030.  Analysts estimate that in order to achieve these ambitious levels, the power sector’s renewables market share must reach 50%.

Ichord observed that although Germany increased renewables’ share of power generation to about 34% last year (of which about two-thirds comes from wind/solar), this progress has come at a high cost, and the emissions impact has been reduced by the closure of nuclear plants.  In the aftermath of the 2011 Fukushima dissater, Angela Merkel’s government directed the shutdown of eight nuclear stations initially and the last nine by 2022.  Meanwhile, Germany has generously incentivized new wind and solar generation through “feed-in tariffs” – to the tune, since 2000, of about $200 billion.   But with the closure of zero-emission nuclear plants, the pace of reduction in Germany’s GHG emissions has slackened (only 6% reduction since 2010).  Electric tariffs, moreover, have climbed to the point that the cost of power has become a major concern for German industrial competitiveness (with the country relying on exports for 40-50% of its GDP). 

In recent years, German’s wind power output has increased so much that the transmission system is strained to deal with its intermittent surges.  The emerging transmission problem is exacerbated by the challenge of serving large loads in the south of the country, where six of the remaining nine nuclear plant closures are due to close in 2022.  Germany is “way behind” in the construction of transmission capacity to get northern wind power to serve southern Germany’s. loads, Ichord observed.  

As to the rate impact of Germany’s venture into renewables, residential and industrial tariffs are the second highest in Europe (second only to Denmark, which has the highest percentage of renewables) and are far in excess of U.S. prices.  At the same time, Ichord adds, the wholesale market price of power has dropped, putting pressure on the value of power-generating utilities assets.  Some relief may be on the horizon: under the proposed market redesign package, the EU would phase out the subsidies of feed-in tariffs, replacing them with an “auction” system.

Excess German wind generation spilling over into neighboring countries has also caused controversy and “pushback,” said Ichord, though it’s also “forced cooperation” among system operators having to deal with it.  As for the mounting cost of new transmission to integrate northern wind with southern loads, Ichord feels this problem badly needs to be tackled, especially as German utilities are being directed to build transmission facilities underground, at eight times the cost of overhead transmission.

Germany is not unique among European nations wishing to reduce reliance on nuclear power, Ichord added – France and Belgium are considering reductions as well – and, despite the higher cost of imports and Russian pipeline dependency, he foresees Germany turning more towards natural gas, in lieu of coal and lignite, as it struggles to achieve GHG reductions.


Integrating Intermittent Renewable Energy in Southeast Europe.  Will Polen shared his experiences assisting Southeast European nations in overcoming their grid challenges.  The USEA and USAID teamed up, over a 17-years period, in a project called the Southeast Europe Cooperation Initiative Transmission Planning Project (“SECI”) to help that region rebuild and rethink its transmission systems (which were damaged by NATO bombing in the Balkans war). While some of the Balkan states are not members of the EU, a secondary goal was to enhance their interconnections with European power markets.  Only recently has stewardship of this long-running project been transferred to ENTSO-E, the “European version of NERC.”

A primary mission of SECI was to develop the institutional and technical infrastructure for coordinated planning of the region’s transmission facilities, as a prerequisite to reaping the efficiencies of joint planning and greater integration of neighboring systems. Thirteen national system operators participated (including several as “observers”).

Polen believes the lessons learned are less applicable to the U.S. than to countries in developing regions seeking to forge closer inter-utility ties across national borders.  Creating a joint planning platform like SECI leads to greater cross-border transmission interconnections, improved grid reliability, cost-saving efficiencies, and more trading across energy markets. 

Because these countries view themselves as “accession candidates” to EU membership, noted Polen, they have adopted ambitious renewable energy integration goals.  The fact that their systems are simultaneously moving away from “central planning” towards a more decentralized, market-driven business model makes achieving state renewable mandates that much more challenging.  Nonetheless, SECI incorporated these targets into its planning model in load flow studies and applicable reliability criteria to determine the extent of transmission construction and/or generation reserves the Balkan systems would need. 

A key finding of the project was how expanding the transmission footprint of the region could facilitate reaching its renewable resource targets.  More grid integration and asset pooling would allow the amount of reserves necessary for reliability to be “cut by up to 50%,” Polen pointed out, versus a “country-by-country” approach.

The USEA and USAID are currently trying to address what Polen describes as a “seams” problem that gives national system operators a perverse incentive to game the system by understating their cross-border transmission transfer capacity.  This allows them to collect “congestion rents” that are, in theory, to be plowed back into transmission upgrades, but may not be in practice, since inertia allows the congestion rents to be booked as profits.  The hope is to increase the authority of independent regulators to detect and correct such counterproductive behavior.

Among other issues facing the region, Polen does not underestimate the seriousness of cost impacts.  To raise the level of renewable energy as proposed, the countries will have to offer incentives that will increase tariffs.  In a region already afflicted by widespread “energy poverty,” the renewable goals will only add to the affordability problem. Polen hopes the region will be able to import natural gas for power generation, but this goes hand-in-hand with “energy security” issues.  Finally, given the intermittency of wind and solar, he stresses the ongoing importance of fuel diversity.

NERC’s Take on Reliability in an Age of Growing Intermittent Energy.  John Moura prefaced his remarks by noting that even though (1) NERC is a “reliability extremist” and (2) increasing renewables in the generation mix does pose technical, infrastructure, and policy challenges, these are “not insurmountable.”  He added to this general assurance a list of “key messages” on how NERC views the transition to more wind and solar in the generation mix:

  • The retirement of conventionally fueled generation does present reliability concerns for the bulk power system, which has historically relied on these units for “Essential Reliability Services” (i.e., ancillary services) and “fuel assurance;”
  • Declining reserve margins in some parts of the U.S. are expected to tighten operational reliability;
  • While variable resources can be reliably integrated, it requires that they be “cautiously planned and operated;”
  • Fuel assurance generally benefits from fuel diversity, but regional differences must be accounted for; and
  • The search for solutions to limited gas pipeline capacity in certain parts of the country must entail action by “the wholesale electric market,’ not just natural gas markets and regulators.

Another way to express the problem of replacing conventional generation with wind and solar is the loss of “spinning mass.”  Wind and solar, with less spinning mass than thermal or hydro generation, leads to “lower system inertia” and less ability to physically control the system. 

Moura then turned to the phenomenon of rapidly increasing natural gas generation.  NERC-wide peak gas-fired capacity nearly doubled between 2009 and 2017 – from 280 GW to 442 GW – with another 32 GW of “Tier 1 gas-fired capacity” planned over the coming decade.  Six NERC assessment regions across the U.S. will have over 50% natural gas-fired capacity by 2022.

With increasing proportions of natural gas generation in the mix, Moura underscored the reliability risk posed by generators in certain regions (most notably the Northeast) lacking firm gas service contracts.  For example, in the New York/New England region, over 53% of gas generation is not supported by firm gas and will not get gas on peak demand days due to pipelines restricting interruptible services.  Hence, especially during extreme conditions, gas generation may not always be the “dance partner” variable resources need.  Dual-fuel capability helps mitigate the problem, but it is not a “silver bullet,” adds Moura; for example, during a cold spell in New England in early January, the region’s generation fleet came close to running out of oil reserves.

To successfully integrate more variable resources, Moura summed up, “significant changes” to traditional methods of system planning and operation will be required.  Paramount among these are improved weather-related generation and load forecasting; increased system flexibility (including more ancillary services and larger balancing areas); and the construction of more transmission lines to integrate intermittent resources from remote areas across long distances.  He stressed that “maintaining a diverse resource mix” is crucial to “increasing resilience, flexibility, and reliability,” that all generation assets must contribute to system reliability, and that reliability challenges are “bigger than any one organization,” requiring the support of numerous industry and regulatory institutions.

PJM in the Middle.   For PJM, planning the system to absorb greater amounts of renewable resources begins with a focus on state renewable portfolio standards (RPS).  Tim Burdis highlighted that ten states in PJM’s footprint have some sort of RPS, couched either as “mandatory” or as a “goal.”  The amounts range from as high as 50% for the District of Columbia by 2032 to as low as 10% for Indiana, with many states opting for RPS percentages falling in the mid-teens to mid-20’s, applicable between 2020 and 2026.

But as of today, PJM’s generation capacity mix is heavily slanted towards thermal energy (67.GW of installed capacity is natural gas, 57.7 GW coal, and 33.9 GW nuclear), with wind and solar (decremented for capacity availability) representing much smaller slices of the mix (about 1.5 GW collectively).   Hydro currently claims the largest share of installed capacity among renewables, at about 8.4 GW.  On a dispatch basis, renewable energy represents about 5% of PJM’s total generation, with nuclear, coal, and gas representing roughly a third each of the remaining 95%. 

As PJM has become less reliant on coal power since 2005, and wind power has started to play a meaningful role, its CO2 emissions have steadily dropped, notes Burdis, from nearly 1350 lbs/MWh to 950 lbs/MWh in 2017.  Thus far, Burdis attributes the 26% decrease in CO2 emissions to “market forces” alone.  But this trend will continue as state RPS programs exert a greater influence in the coming years. 

The impact of change on PJM’s wholesale prices has been quite favorable.  As PJM “sits on top of low-cost gas,” and given the “influx of zero marginal cost” wind and solar, the market has exerted a downward pressure on prices in the region.  Looking just at 2016, the $29/MWh average energy price (which excludes capacity and transmission costs) is the lowest the RTO has seen in the 20 years since PJM’s LMP pricing construct was inaugurated.

Looking to the future, Burdis charted the dramatic growth in wind and solar energy necessary to meet the aggregate state-driven goal of 13% of PJM’s energy to be served by renewables in 2031.  To hit this target, PJM estimates the region will require 29,000 MW nameplate capacity wind generation, along with 8100 MW of solar.  Demand growth over that period is projected to be slight: annually since 2014, PJM has decreased its outlook for load growth, as demand response programs have taken progressively greater bites out of such estimates. 

To accommodate ever-increasing amounts of renewables in the next 15 years, Burdis cited some of the same enabling tools as other panelists:  larger balancing areas, improved weather forecasting, shorter market intervals, and both regional and inter-regional transmission planning to improve reliability and reduce congestion.  A slide depicted a host of PJM renewable resource integration initiatives tied to energy markets, transmission planning, and advanced technologies.  Progress in the technology and deployment of storage assets would also help manage the ups and downs of intermittent energy.