DOE's Very Vanilla Energy Markets and Reliability Report

Remember back in April when the new Secretary of Energy issued a memo calling for a report "including an assessment of the reliability and resilience of the electric grid and an overview of the evolution of electricity markets"?  Environmental groups and Trump-haters panicked and screamed about the report being the first step to reviving coal.

Sigh.

And these fools blared on and on for months about the people working on the report, and what it would say.  Someone "leaked" a draft of the report before it was released. The Sierra Club wasted time and resources suing DOE before the study was even released.

And guess what?  The report didn't do any of the things these prognosticators whined about.

So, the report was released last week.  In its wake, every special interest group claimed how the report provided support for their agenda.

DOE Throws Down Red Flags on Unreliable Wind and Solar

Top Three Takeaways From DOE's Grid Study - AWEA

What to Watch in the Wake of the DOE Grid Study

Energy Groups Push FERC to Make Changes Recommended in Grid Study

Could anyone write an impartial article that could serve as CliffsNotes in lieu of reading the whole boring study?  Give a gal a break?  Sorry, no.  I had to read it myself.  Warning... don't attempt in the evening, it's a real snooze fest.  Best tackled bright and early with lots of coffee.  Lots.

Just like everyone else who read the study (and even some reporters and talking heads who only pretended to read it before trying to write about it), I'm only going to concentrate on the parts that interest me.  Because just like a tub of vanilla ice cream, this "Grid Study" is so blah that you could make anything you want out of it if you sprinkle in your favorite ingredients.  Therefore, I proclaim that this report cautions against building a gigantic new electric grid to support remote renewable development.  Don't like that?  Go read the report and write your own article about it.

And here's how I support my opinion.

The report used a quote from NERC, made when the Clean Power Plan was a thing:

"Because the system was designed with large, central-station generation as the primary source of electricity, significant amounts of new transmission may be needed to support renewable resources located far from load centers.216"

But then the report said:

The studies (see Appendix B) that look into the distant future are exploratory only and represent initial investigations into how to implement high levels of VRE. They do not look into all the operational aspects of reliability due to the needed complex and computationally challenging modeling. Typical assumptions (sometimes implicit) include successful siting of (at times long multistate) transmission lines and new generation, sufficient new and existing economically viable conventional generation and other resources to support the VRE, institutional and market changes, and relevant grid modernization-type spending at both the transmission and distribution level. One study, for the ease of modeling, even assumes the nation’s 66 balancing authorities, including their governing boards and member states, would agree to one national joint dispatch). Some of these assumptions are non-trivial. These studies recognize that given enough time and money, power system engineers can make any resource and configuration reliable, as long as the laws of physics are not violated; whether the changes needed are indeed affordable, doable, and desirable may be a different question. Also, affordability was typically not in the scope of these studies.

So, yes, engineers can make things work.  That's what they do.  They're great problem solvers.  But making "VRE" (code for distant renewables) work is likely not going to be affordable.  So why aren't distant renewables affordable?

Most of the contiguous United States’ wind power plants are installed in the center of the Nation, which has the best wind resources.

Technical and economic factors may drive power plant operators to run generators even when power supply outstrips demand. For example:
For technical and cost recovery reasons, nuclear plant operators try to continuously operate at full power.
Eligible generators can take a 2.2¢/kWh or $22/MWh[yyy] production tax credit (PTC) on electricity sold. This means that some generators may be willing to sell their output for as low as -$22/MWh to continue producing power. Typically, wind generators are the largest such group in any region.
There are maintenance and fuel-cost penalties when operators shut down and start up large steam turbine (usually fossil-fueled) plants as demand varies over a day or a week. These costs may be avoided if the generator sells at a loss to attract a buyer when demand is low.

As EIA notes, the PTC can create an incentive for wind generators to bid at negative prices. If other generators located at nodes in the areas affected by negative prices are unable or unwilling to reduce output, they will have to pay the negative price for their output. That scenario has unfolded on some buses in PJM, as outlined in comments to DOE from PJM staff:
Tax and subsidy policies have had an impact on the economics of certain types of generation. The Renewable Energy Production Tax Credit and renewable energy mandates have had the most significant impact on nuclear generation. Specifically, the nuclear and wind generation are competing to clear in the market during off-peak hours when wind resources are the strongest and load is reduced. In those off-peak hours, the production tax credit has created an incentive for renewable resources to bid negative prices as they must run in order to receive their payment from the federal treasury. Since 2014, PJM has seen prices go negative at nuclear unit buses in approximately 2,176 hours—representing 14 percent of off-peak hours.

RPS compliance costs were found to total $2.6 billion in 2014, averaging $12/MWh for VRE and equating to 1.3 percent of average retail electricity bills.ffff 451 The actual effects of zero-marginal cost electricity on consumers’ bills is situational, and growth in VRE can drive additional costs, including transmission and integration costs.452 453 Because many utility-scale VRE plants are built in locations distant from load centers, they sometimes require major transmission additions to connect the remote generation to the rest of the grid and to load centers. Over the past five years, a portion of the 24,000 miles of new transmission built (about twice the number of miles added from 2006–2010) and $102 billion invested to strengthen the grid and interconnect new generation has been made to interconnect VRE.454 455 Transmission investments (regulated or merchant) can increase bulk power costs and therefore increase customers’ retail bills to the extent that they are not offset by savings attributable to access to lower-cost generation or reduced congestion costs.

Studies on RPS compliance costs do not fully capture the “all-in” costs that the ratepayer (and taxpayers) ultimately bear. These other costs are harder to measure, but may not be insignificant. They may be harder to quantify for many reasons, such as having multiple drivers behind those investments and various distribution-level grid modernization investments (e.g., smart meters and others that are touted to aid VRE integration). New transmission (other than the direct transmission interconnection charged to the renewable generation project and thus reflected in their PPA), as well as effects of VRE variability on the dispatchable fleet, are other examples of costs often not included in grid integration cost studies. Costs of various tax and other subsidies are also not counted.

Numerous technical studies on electricity systems in most regions of the Nation have concluded that significantly higher levels of VRE can be successfully integrated without compromising resource adequacy.hhhh Demonstrating resource adequacy is essential, but achieving the modeled levels of VRE penetration requires a full consideration of “all-in” costs, land use, siting, and other environmental impacts; sustainable economics for non-wind and solar resources; for some studies, required changes at the distribution level; wholesale market design and organizational changes; spending on relevant transmission and distribution grid modernization activities; and ensuring all aspects of operational reliability.iiii These caveats are non-trivial, as they would be for any substantial major changes in the electric power system. However, these studies (particularly those examining high VRE levels) may often assume (or ignore) modeled conditions that could be difficult and/or costly to achieve in practice, such as a large transmission buildout that may face siting or other obstacles, ability of non-wind and solar plants to remain financially viable and thus available, institutional changes, or, for one study, synchronization of all three interconnections.

There's also problems with permitting and siting new transmission for renewables (wind).

The challenge for building transmission continues to revolve around the three traditional steps involved, each of which can be time-consuming, involved, and complex: (1) demonstrating a need for the transmission project, also known as transmission planning, (2) determining who pays for the transmission project, also called cost allocation, and (3) state and Federal agency siting and permitting. FERC has taken steps to help with the first two, with reforms such as Order No. 1000, which remains a work in progress.258 259 260 261 262 Transmission planning entities, as well as regional state-based groups, are also contributing to improving these three necessary process steps. The current and past administrations, aided by various new Federal laws, have issued various Executive Orders and other initiatives to improve the processes involved in siting and permitting of transmission when Federal lands or waters are involved.
All three transmission building steps can be time-intensive and complex; in particular, siting and permitting for large networks or long multi-state lines is challenging. 263 264 265 The second necessary step of cost-allocation can be time-consuming as well. For example, large overlay networks now being built in MISO (“Multi-Value Projects”)266 and SPP (“Highway/Byway Plan”)267 required several years of sensitive negotiations among states brokered by the respective Organization of MISO States and SPP Regional State Committee to determine the cost allocation of each large transmission buildout.268 269

That's right, there's nothing a federal agency can do about state jurisdictional transmission permitting and siting.  I'm a bit puzzled by DOE's footnote referencing this vomitrocious opinion piece from Public Utilities Fortnightly.  Umm... this is only an industry opinion, not science, engineering or any other "data source."  Don't be fooled by this guy's use of his former job to try to pretend his opinion holds any weight.  He's a shill for WIRES, and WIRES is a trade organization for transmission owners, builders and suppliers.  Of course they want to build lots of transmission right now, that's where their paychecks come from!

So, are renewables causing baseload generators to retire?  This is where the vanilla gets flavored.  On the one hand, no, coal's economic problem is caused by low shale gas prices.  On the other hand, yes.

Fuel neutrality is essential for both monopoly-utility resource planning and competitive markets to manage risk and achieve reliability efficiently. Interventions to promote specific fuel types—such as bailouts for coal and nuclear or mandates and subsidies for renewables—skew investment risk and can undermine incentives for reliability-enhancing behavior (e.g., a public intervention to finance pipeline expansion removes incentives for the private sector to invest in fuel security). Fuel-specific subsidies and mandates replace individual choice with collective choice. This one-size-fits-all approach to risk mitigation ignores variances in individuals’ risk tolerances, results in high-cost risk mitigation, and creates perverse incentives for market participants by transferring risk and costs from the private to the public sector.

New technologies with very low marginal costs, i.e. VRE, reduce wholesale prices, independent of— and in addition to—the effects of low natural gas prices. To the extent that additional development of such resources is driven by subsidies and mandates, their price suppressive effect might place undue economic pressure on revenues for traditional baseload (as well as non-baseload) resources and could require changes in market design.

On modeling capacity factors for renewables: Each ISO and RTO calculates the on-peak contribution of renewable resources as a function of historic resource performance. Land-based wind plants are assumed to deliver four to 14 percent of nameplate capacity during peak summer afternoon periods, and solar resources are assumed to deliver between 10 percent and 80 percent of nameplate capacity. Note, however, that as the level of PV penetration increases, the cumulative amount of PV generation on summer afternoons is moving net load peak hour later.

Market designs may be inadequate given potential future challenges. VRE—with near-zero marginal costs and if at high penetrations—will lower wholesale energy prices independent of effects of the current low natural gas prices. This would put additional economic pressure on revenues for traditional baseload (as well as non-baseload) resources, requiring careful consideration of continued market evolutions.

And speaking of natural gas, the report attempts to pit the "no gas pipeline" folks against the "no electric transmission line" folks.  Personally, if I had to have one or the other, I'd go with the gas line.  Once constructed, it's buried (but hopefully not forgotten).  And pipelines are easier to build because they are not state-jurisdictional.  There's a lesson here for transmission opponents... never let the Feds usurp state electric transmission siting and permitting authority.

Natural gas-fired generation has grown nearly continuously since the late 1980s (see Figure 3.19) for several key reasons. These plants have low capital costs and are, in general, relatively less expensive than some competing technologies.108 They are also much less land-intensive than many other types of generation, and thus often can be more easily sited in urban areas near electric demand.109 Similarly, natural gas pipelines can be built more quickly than electric transmission lines (in most states) because they have a comparatively streamlined permitting process, which often has made it easier for a plant developer to build a new gas-fired plant near a large electric load than to build a power plant farther away and transmit its electricity to large load centers by wire.dd

Interstate natural gas pipelines can often be built more quickly than transmission lines because the pipeline owners, once granted a FERC-issued certificate of public convenience and necessity, have eminent domain power under section 7(h) of the Natural Gas Act and the procedures set forth under the Federal Rules of Civil Procedure (Rule 71A). By contrast, electric transmission developers are dependent on states to grant eminent domain authorization.

And let's hear from another former FERC Commissioner who isn't a spokespuppet for the industry and trying to line his own pockets:

Former FERC Commissioner Tony Clark summarizes today’s changing demands on centrally-organized markets: “Affordable power was the goal when markets were created. The current markets are still procuring affordable power, but many state public policy makers no longer see that as the only goal [...] other public policy goals [include...] incenting in-state jobs, promoting ‘green’ energy or other politically favored resources, preserving carbon-free resources, and retaining substantial tax revenues to state and local government.” Clark goes on to say, “[Markets] were never designed for job creation, tax preservation, politically popular generation, or anything other than reliable, affordable electricity.”

States that use public policy goals to determine whether or not a transmission project should be permitted are using the wrong numbers, and that's screwing with electricity markets and making electricity too expensive.

Therefore, states should stop relying on public policy goals like jobs, taxes and economic development, as well as freebies like new transmission headquarters or below cost transmission contracts, to justify approving huge new transmission projects that will only increase the cost of electricity in the long run.

And while we're at it perhaps DOE could start closer to home and take a fresh look at its decision to "participate" in the Plains & Eastern Clean Line under Section 1222 of the Energy Policy Act.  The decision to "participate" relied wholly on public policy goals and the desire to play resource favorites and promote a certain type of new generation (wind).  But will the DOE take its own advice?

You need to let them know that you've reviewed their report and that their own recommendations say DOE should end its troubled participation in the Clean Line projects as soon as possible. 

The DOE wants to hear your comments.  No, they really, really, really do!  Submit your comments here. 

Do it now!