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Grid Modernization – A Counter Narrative Policymakers Should Consider

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"Our state deserves excellent electric reliability, and freedom from prolonged outages. The utilities here need the incentive to invest more to make this happen.  Our citizens and businesses are worth the investment, the infrastructure spending stimulates our economy, and a stronger grid will make our state more attractive to industry." These words, uttered or believed by many legislators and/or regulators in every state, illustrate the popular thinking behind distribution grid modernization today. Often prompted by the threat of hurricanes, Public Safety Power Shutoffs (wildfires), ice storms, tornadoes, cyberattacks, and other potential interruptions of our society's electric life-blood, policymakers can find these well-intended instincts difficult to question, like motherhood or apple pie. However this popular thinking must be questioned, as embedded within its good intentions lie errant assumptions and half-truths which threaten the very economic benefits grid modernization has the potential to deliver if appropriately applied.

As the leader of a consultancy which has critiqued more investor-owned utility (IOU) grid modernization plans than any other, on behalf of consumer, business, and environmental advocates, I offer a counter-narrative which merits policymaker consideration. While state legislators and regulators weigh the merits of IOU requests to speed cost recovery and invest more in their grids, policymakers need to consider the other side of the coin -- that grid investments lead to rate increases, and rate increases which don’t deliver benefits in excess of costs act as a drain on state economies. Rate increases for grid modernization last 15-40 years or more.  These rate increases require consumers to reduce discretionary spending, prompt businesses to look elsewhere for expansion, and cause governments to raise taxes and/or reduce services.  Policymakers should always examine grid modernization proposals and likely (not exaggerated) benefits in the context of customer rate increases.  

Falling natural gas prices have masked grid modernization rate increases to date, and the current economic contraction is giving regulators reason to reduce capital investment/rate increases in the near term. But my perspective is that rate increases should always be considered a precious resource, not to be spent unless necessary, regardless of electric commodity prices or economic conditions. With all the upcoming investments our grids will need – from the ability to accommodate growing distributed generation capacity to beneficial electrification – we should reserve rate increases for the future whenever possible. We are likely to need some fuel in the tank, so to speak. Our economy, which competes with countries across the globe, deserves the best balance between reliability and affordability which can possibly be delivered. Paying more than necessary for a given level of reliability puts the US economy at a competitive disadvantage.  

While policymakers will certainly agree with my perspective in public pronouncements, their actions often speak much louder than their words. In truth, few if any legislatures, commissions, or intervenors have the experience in grid planning, operations, or asset management to effectively question the cost-effectiveness of multi-billion-dollar IOU grid modernization proposals. Historically, the real action has been in generation and transmission, and in integrated resource planning (IRP) proceedings. In such proceedings, the pros and cons of potential capital project portfolios are debated with the benefit of extensive examination under multiple future state scenarios. State economies and IOU shareholders both benefit from these thoughtful analyses.      

Commission approvals of IOU grid modernization proposals and cost recovery today seem to rely on past experience. This experience indicates that IOUs only invest in their grids the amount needed. Whether to accommodate load growth/economic development, replace damaged or failed equipment, or fund customer-paid and government-requested infrastructure relocations and redundancies, grid investment has historically been required, not optional. Furthermore, policymakers could always count on future growth in energy sales to mitigate rate increases associated with grid investments.

Times have certainly changed. Proposals for extra-ordinary investments in grid reliability and resilience are optional, as electricity distribution in the US is already safe and reliable.  Energy sales and peak demand are falling in almost all jurisdictions, with multiple implications. The rate increase damping factor from future sales growth is gone. In addition, falling sales and peak demand deprive IOUs of profit opportunities from both generation investments and sales growth between rate cases. These historical means of achieving earnings-per-share (EPS) targets promised to shareholders are essentially non-existent now, and transmission requires at least a decade to plan, design, and construct. All this leaves IOU executives with one best opportunity to achieve the challenging EPS growth targets implied in their stock option incentive plans: distribution grid investment. Further, there is no current capability for transparent examination of alternatives under multiple scenarios as there is through resource planning.  

In reliability and resilience, IOUs have found a grid investment justification which defies accountability (how can an IOU be held responsible for the weather?), is difficult to question technically, and resonates with policymakers of all stripes. Further, once the reliability/resilience tag is applied to a proposal, an IOU places its regulators in an unenviable position. That is, if the regulator denies the proposal, he or she might be blamed for any future weather event with a lengthy restoration. These are all reasons why pressure on legislators and regulators to authorize ever-greater grid investment, and ever-improved cost recovery, in the name of reliability or resilience, is unlikely to end.  They are also the reasons why the assumptions and half-truths embedded in reliability and resilience justifications are important for policymakers to understand, and to begin addressing.   

There is only so much reliability benefit capital can deliverThe grid is subject to the law of diminishing returns. Each additional dollar invested brings less incremental reliability improvement than the most recent dollar invested. Consider Florida Power and Light, which invested $2 billion to harden its grid in the decade or so since Hurricanes Charlie and Wilma in 2004 and 2005. Despite the $400 per customer investment, when powerful Hurricane Irma hit in 2017, 9 days were required to restore power to the last 50% of customers out of service.  While this was better than Wilma’s 13 days, the question must be asked: were 4 days without power once in 12-years for a minority of FPL’s customers worth $2 billion? What would be the cost to get to 5 days? Last year, FPL CEO Eric Silagy estimated the cost to underground all FPL’s overhead lines – which might not be enough to get to 5 days – at $25 to $35 billion, and would take 30 years to complete. FPL’s distribution rate base today is only $17.15 billion.

We are likely already seeing the point of diminishing returns. As seen in the graphic below, distribution grid investment by US IOUs has significantly outpaced electricity sales and peak demand, which have fallen in recent years. One would expect this excess investment to deliver reliability improvements. Yet key reliability statistics SAIDI and SAIFI are trending slightly worse (higher). It appears excess grid investment to date has not improved reliability, and independent research by Lawrence Berkeley National Laboratory (LBNL-188741) confirms the lack of correlation between capital investment and reliability.

Some types of reliability-related investments are simply not cost-effective. Many IOUs in storm-prone states tout undergrounding of overhead lines as a practical storm resilience strategy. While intuitively appealing, undergrounding is anything but practical.  A recent Storm Protection Plan submitted to the Florida Public Service Commission by Duke Energy disclosed plans to underground 45 miles of overhead distribution lines serving 1,765 customers in 2020 at a cost of $42.5 million. This amounts to almost $24,000 per customer, though I note that the average installed cost of a natural gas- or propane-fueled generator suitable for home back-up is only $5,900. Independent research in a hurricane-prone state (Texas) indicates that the benefits of undergrounding amounted to just $0.30 per $1 invested (LBNL-1006394). Perhaps state- or IOU-sponsored generator rebate and financing programs would be a more cost-effective approach to reducing storm impacts.

Even cost-effective solutions can become cost-ineffective if deployed too widely.  Grid reliability is also subject to the Pareto Principle, better known as the 80/20 rule, which postulates that 80% of the potential benefits of a technology are available through 20% of its applications. Grid flexibility, which enables re-routing of power in cases in which a normal route into a neighborhood is disrupted, has proven reliability benefits. The capability can also be helpful as distributed generation capacity reaches high levels. However, the technology has Pareto-related limits. It is more costly, and benefits fewer customers per dollar, as customer density falls. Its value can also be limited in cases of widespread damage, such as in extreme weather events, when re-routing options are also inoperable/unavailable.

US IOU reliability performance is already strong; many IOUs need no improvement at all. In 2018, US IOUs restored service after an outage within 6 hours on average. Remove storms, and the average falls to 2 hours and 16 minutes – a remarkable 99.974% uptime. The average US IOU customer experienced only 1.3 service outages in 2018 including storms. However, even top-performing IOUs cite improvements in reliability, or its impending deterioration, as justification for grid investments. Indianapolis Power & Light recently proposed a $1.2 billion ($2,400 per customer) grid modernization plan as a way to avoid deteriorating reliability.  I note that Indianapolis Power and Light has performed in the top 10% of US IOUs on SAIDI in each and every year (without storms) since the US Energy Information Administration began collecting reliability information from US IOUs in 2013. Despite the apparent lack of an impending reliability emergency, the Indiana Utility Regulatory Commission approved the Plan, based in large part on ill-informed state legislation. Grid legislation which was similarly well-intentioned, and similarly difficult to control in practice, has also been passed in Florida, Missouri, and Virginia in the last two years.

Different customers have different tolerances for, and different risks of, multi-day service interruptionsPolicymakers should be asking, “to what extent should the cost to insure against such interruptions be socialized through utility investment/rates, and to what extent should customers with an interest self-insure, for example by purchasing a generator?” At some point, the responsibility for the average customer to fund ever-improving reliability for other customers ends. Individual customers can always vote with their own wallets; a recent study commissioned by the US Department of Energy indicated that over 80% of critical facilities, including retail facilities like banks and grocery stores, have back-up generation available; almost 50% of these back-ups were viable for 1 to 5 days.

Prospective asset replacement is not cost-effective. The Indiana experience is notable for another “innovation” related to reliability. The IOUs there have been using age-based models to predict which assets are likely to fail in coming years, and to justify prospective replacement on that basis. IOUs nationwide are jumping on this bandwagon with the support of depreciation experts at engineering firms like Black & Veatch, and Burns & McDonnel. The innovation is fundamentally flawed for at least three reasons. First, age is a terrible predictor of failure; a 30-year-old asset can fail tomorrow, or 30 years from tomorrow. Second, objective tests (which utilities nationwide have been employing for decades) can accurately identify transformers, circuit breakers, and relays about to fail; there is no need to estimate which assets are at risk, or to prospectively replace assets which pass the tests. Third, the engineering firms identifying the assets stand to gain consulting revenues from the increased rate of asset replacement associated with predictive modeling.                

Is Machiavelli at work? In California, the rush to avoid Public Safety Power Shutoffs (PSPS), a sort of self-induced reliability crisis, has prompted a capital bonanza for IOUs. Reluctant to take responsibility for the vegetation management and equipment inspection and maintenance practices they themselves control, IOUs have instead begun shutting down power during high wildfire risk conditions. Outrage by remote communities has prompted the IOUs to propose billions of dollars in capital-intensive solutions, from reconductoring (using insulated conductor) and prospective equipment replacement to redundant, remotely-located generation and transmission. PSPS may not be the result of improper motivations, but the potential relationship between IOU actions and capital bias is worth examining. For example, is the slight negative reliability trend in nationwide IOU data presented earlier the result of more accurate reliability reporting? If so, is more accurate reporting intended as an aid to performance improvement, or to justify greater capital investment related to reliability?     

Benefit-cost analyses to date are of highly inconsistent quality and cannot be relied upon. Most state legislation and regulatory rules require “cost-effectiveness tests” or “benefit-cost analyses” which indicate that grid modernization benefits exceed costs. I urge regulators not to take the analyses provided by IOUs at face value. I routinely identify egregious benefit exaggerations and cost understatements in such analyses. In one business case I examined, an IOU estimated the annual cost-savings from laid-off meter readers at an amount which was 164% of its historical annual meter reading departmental expense. In all cases I examine, IOUs compare customer benefits to IOU costs rather than to customers’ costs, by which I mean revenue requirements. The difference between IOU costs and the revenue requirements customers must pay over, say, 30 years is significant; as a rule-of thumb, 2.5 times higher in nominal terms and 1/3 higher in present value terms. In addition, the outcomes of present-value calculations are particularly sensitive to the discount rate used. There is a strong case for using customers’ collective discount rates, rather than IOU weighted average cost of capital, in present value calculations. This would more appropriately value long-term benefits from a customer, rather than from an IOU, perspective. I also note that all IOUs which attempt to quantify the economic stimulus associated with grid modernization investment ignore entirely the economic drag of associated rate increases.        

A particularly challenging aspect of benefit-cost analyses is the translation of reliability benefits into economic value. While many IOUs use “dollar values per outage” estimates from secondary DOE-sponsored research (LBNL-6941E), or the online DOE tool which employs these estimates, I urge regulators and Staff to examine the authors’ own critique of these estimates. I do not believe the self-critique to be comprehensive. Not only is the commercial customer survey data on which the estimates are based fundamentally flawed, and not appropriate to the manner in which the data is now being employed, the aggregation of individual customer impacts to represent community-wide economic impacts of service interruptions severely exaggerates community-wide impacts. Pointed research into the community-wide economic impact of service interruptions of various extents and durations is critically and urgently needed. In my opinion, there is no valid way to translate reliability benefits into economic value today. 

Providing IOUs with Additional Investment Incentives is Not Necessary.  As is clear throughout this editorial, capital bias plays a key role in grid modernization. Not yet mentioned are tangential investments IOUs claim are needed to improve reliability, such as cybersecurity (where the most impactful efforts are the least capital intensive), communications networks (which the major carriers’ new “Internet of things” networks could securely and cost-effectively substitute), or software (which, like communication networks, non-profit utilities outsource to a dramatically greater degree than do IOUs). But instead of recognizing this bias, many legislators and regulators expand upon it by providing enhanced cost recovery, higher authorized rates of return on equity than necessary, and tweaks to the existing cost-of-service ratemaking model (such as authorizing profits on capital avoided, or on avoided operations and maintenance spending).

Regulators already authorize a rate of return on equity which is sufficient to encourage needed grid investment. Additional incentives appear to encourage extraordinary investment which may not be cost-effective. Further, the existing regulatory compact requires IOUs to provide safe, reliable, affordable service in exchange for their authorized monopoly and a reasonable opportunity to earn profits. The compact implies that when a less-costly option is available, IOUs must select it in the public interest. In addition to bribing IOUs to make cost-effective choices, or to make extraordinary investments in the name of reliability, regulators should consider stricter enforcement of the terms of the existing compact.

Further, legislators and regulators should recognize that providing additional incentives to IOUs with operations in multiple states represents a form of escalating competition between states which is mutually destructive, and which cannot be won. (Perhaps, given this editorial’s content, such a competition is not something a state wants to win.) As with bidding wars for personal protective equipment in this era of pandemic, regulators should be coordinating their efforts with compatriots in other states served by multi-state utilities to avoid bidding wars for grid investment.              

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Policymakers concerned about errant reliability-related assumptions and half-truths may be interested in potential solutions. One option is to shift to a ratemaking model which eliminates capital bias. Europe has had some success with price-cap ratemaking, which caps rates rather than IOU return on equity, combined with reliability-related incentives and penalties. This idea is considered too radical by most, and could require some European utility industry characteristics to work well, but merits strong consideration. If the return on equity approach, and its associated incentive to invest capital in grids, is to be retained, it seems that improved regulatory control over the amount of capital invested, and to what ends, is a more practical option.

One way to improve control of the amount of capital invested, as well as the goals to which capital is deployed, is to increase transparency and stakeholder engagement in grid planning and capital budgeting processes. Patterned closely after integrated resource planning, such a process would involve stakeholders in decisions regarding grid spending which is outside the normal course of business. It seems reasonable for stakeholders to be involved in 1) visioning which specifies long-term goals and quantified targets (reliability, distributed generation capacity, etc.); 2) guidelines for evaluating IOU proposals and alternatives (including the estimation of benefits, costs, and risks); 3) processes for prioritizing and selecting investments for implementation (as well as investments which can wait); and 4) post-deployment benefit and performance measurement.

Finally, we must consider the elephant in the room: regulatory governance. In most states, regulators serve at the pleasure of the governor or the legislature. As a result, governor and legislator priorities and perspectives often become regulator priorities and perspectives, with all the pros and cons that reality presents. IOU positions have significant influence on governors and legislators, though these policymakers are unlikely to understand the technical issues and risks at play, nor the impact of legislation on regulators’ decisions. As implied earlier, this combination can result in poor outcomes. A great example is in South Carolina, where the Commission reports to the Legislature. To make a long story short, legislation unduly favorable to nuclear plant construction was passed in 2007. A decade later, the construction of a nuclear plant was abandoned mid-point at a potential cost per customer of $6,200; the Commissioners were fired; and IOU investors lost as much as 1/3 of their equity.

On a related note, governors and legislators often assume regulators’ role is to protect customers. They do not appreciate that regulators’ role is to weigh evidence and issue orders. In most states consumer advocates, not regulators, are responsible for protecting customer interests. These advocates, generally funded by state governments, do not have the resources or technical expertise required to effectively question the cost-effectiveness of IOUs proposals. Even the most die-hard small government proponent should agree, especially upon reading this editorial, that authorized monopolies warrant greater scrutiny, not less.  Given current and approaching state government budget challenges, governors and legislators should make extra effort to preserve or increase existing consumer advocate budgets. Advocates are advised to pursue new funding sources. In some states, ratepayers pay for the cost of defending their interests before state regulators. In my experience, ratepayers receive hundreds or thousands of dollars in rate increase mitigation for every dollar spent by consumer advocates.    

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Policymakers should strive to secure for their states safe, reliable, and affordable grids through the addition of needed capabilities (no more), at the right time (no earlier), to an appropriate extent (governed by accurate benefit-cost analyses), in the most cost-effective manner possible (as indicated by equitable evaluations of available alternatives). IOU employees are good people, and generally want these same outcomes. The heroism and dedication of linemen and troublemen, who work tirelessly under dangerous conditions to restore power quickly during and after extreme weather events, or who ensure the power remains on during a pandemic, is without question. However, IOU executives work to advance shareholder interests, as they are required to do by federal law, enforced by the Securities and Exchange Commission. They are very good at doing so, as evidenced by the $450 million just 41 IOU CEOs earned in 2019 alone. Policymakers must recognize IOU motivations and act accordingly in all aspects of IOU regulation, including grid modernization, reliability, resilience, affordability, accountability, and ratemaking. Addressing the challenges of for-profit monopoly regulation has never been easy, and it appears to be getting more difficult. But the sooner policymakers recognize the challenges, and attempt to address them, the better off the American public served by our electric distribution grid will be.


Review of Florida’s Electric Utility Hurricane Preparedness and Restoration Actions. Florida PSC. July 2018. P. 24

Heroux Pounds, M. Our power lines will be buried for storm safety. It could cost FPL up to $35 billion.  South Florida Sun Sentinel.  October 17, 2019.  Accessed via Internet at http://sun-sentinel.com.

 FPL FERC Form 1. December 31, 2018.

Larsen et al. Assessing Changes in the Reliability of the U.S. Electric Power System. Lawrence Berkeley National Laboratory and Stanford University report LBNL‐188741. August, 2015. Page 37.

Florida PSC 20200069. Direct Testimony of Jay W. Oliver dated April 14, 2020. Exh. JWO-1, pages 5-10.

Researched via Internet at http://www.costestimates.com June 17, 2020.

 Larsen P. A Method to Estimate the Costs and Benefits of Undergrounding Electricity Transmission and Distribution Lines.  Lawrence Berkeley National Laboratory and Stanford University report LBNL‐1006394.  October, 2016. Section 4.3 (not paginated).

 US Energy Information Administration Form 861, 2018. Data summarized by the Utility Evaluator, available at http://www.utilityevaluator.com.

Ibid, 2013-2018.

Phillips J et al and Eto J. Onsite and Electric Power Backup Capabilities at Critical US Facilities. Argonne National Laboratory and Lawrence Berkeley National Laboratory.  April, 2016.  Pages 13 and 14.

Sullivan et al.  Updated Value of Service Reliability Estimates for Electric Utility Customers in the United States. Lawrence Berkeley National Laboratory Report LBNL-6941E. January, 2015.

Interruption Cost Estimator. US Department of Energy.  Available via Internet at http://www.icecalculator.com.

 Sullivan et al; page 48.

 Alvarez P, Stephens D, and Ericson, S. Challenging Utility Grid Hardening Proposals Part 2: Emerging Practices in Customer Benefit and Cost Estimation (tentative). Accepted for publication in a September, 2020 issue of Public Utilities Fortnightly; page numbers to-be-determined. See also Direct Testimony of Paul J. Alvarez dated February 18, 2020 in NCUC docket E-7, Sub 1214, pages 29-33; and Comments by the Office of People’s Counsel dated June 8, 2020  in MDPSC case 9353, pages 26-27.  

In a recent “honeypot” operation conducted by Cybereason, which IOUs are likely to cite as evidence of increasing cybersecurity risk and justification for cybersecurity investment, the vector used by the successful, role-playing cyber attacker was an insufficiently complex Administrator password. This illustrates how inexpensive policies and process controls can be more effective than costly investments at thwarting cyber attacks.

Moore, T.  Failed Nuclear Project to Cost Typical Ratepayer $6,200. The Post and Courier. August 1, 2018.

Smyth J and Pomerantz D. Utility CEOs Received Over $1 Billion in Executive Compensation from 2017-2019.  Energy and Policy Institute. April 27, 2020.  Accessed via Internet at http://www.energyandpolicy.org

Discussions

Matt Chester's picture
Matt Chester on Jun 24, 2020 12:32 pm GMT

Definitely a thought-provoking take, Paul-- thanks so much for sharing.

Despite the $400 per customer investment, when powerful Hurricane Irma hit in 2017, 9 days were required to restore power to the last 50% of customers out of service.  While this was better than Wilma’s 13 days, the question must be asked: were 4 days without power once in 12-years for a minority of FPL’s customers worth $2 billion? What would be the cost to get to 5 days? Last year, FPL CEO Eric Silagy estimated the cost to underground all FPL’s overhead lines – which might not be enough to get to 5 days – at $25 to $35 billion, and would take 30 years to complete. FPL’s distribution rate base today is only $17.15 billion.

I moved to Florida about a year ago, and the presence of above ground wires in hurricane country has always seemed baffling, but those prices figures are indeed eye-popping. The question definitely brings me to think about the health and safety implications of power outages for extended periods of time, particularly in a state with a prominent elderly population, but that just goes to show it's a hard question to answer. What does the cost-benefit analysis say is the right move? It might be hard to get a consensus there based on who is affected, how much it will cost different customers, the particular hazards around them, etc. 

In the end, do you think it's more a matter of 'those billions would better serve customers being invested elsewhere' or 'our customers would simply be better off if we didn't collect those billions?' Either way, it highlights the unique business positioning utilities are in where they are essential services for health and well being of society, often without any choice as to individual providers, but they are still looking out for the bottom line. 

Paul Alvarez's picture
Paul Alvarez on Jun 24, 2020 10:18 pm GMT

Thanks for your comment Matt.  If you look closely at the Florida IOUs' recent storm preparedness proposals, the undergrounding they are proposing relate almost exclusively to low voltage residential "laterals" which route through customers' back yards.  Overhead lines without access (like an alley) are harder to maintain (tree trimming) and harder to repair (no bucket trucks).  I appreciate these concerns, but the fact remains that undergrounding such lines is prohibitively expensive, and benefit very few customers per $.  Faults on underground lines are also subject to longer blue-sky outages (as they are harder to locate and must be dug-up to repair). Underground lines are at increased outage risk from flooding and digging.  Underground lines must also be replaced more often, and cost much more to replace, than overhead lines.  To summarize, undergrounding is not the panacea many believe it to be.   

As mentioned in the article, perhaps generator subsidies or financing programs are less costly ways to ensure that homeowners with medical needs can avoid a lengthy outage.  By and large the higher-voltage overhead lines (which serve higher-density areas, commercial customers, apartment buildings, and nursing homes)  have already been hardened or undergrounded.  Higher-voltage overhead lines are also generally located along roadways, making them easier and faster to access and to repair.  Homeowners in the least dense geographies with overhead lines through backyards are at greatest risk of lengthy outages. Unfortunately, those situations are exactly where undergrounding is costliest on a $ per customer basis.   

To answer your question, I think undergrounding is an issue of both 1) there are better ways to spend the $; and 2) those better ways to spend $ can be delayed. For example, we know that accommodating a high capacity of distributed energy resources (DER) and beneficial electricification are going to require big grid investments.  But those investments needn't be made universally, or today.  More appropriately, those investments should be made over time, on a circuit-specific basis, as DER and electrification grow.  Better to reserve big investments, and big rate increases, for future use, as we know the needs are coming.  To summarize, from my post: Grid investment should be in the right capabilities, to the right extent, at the right time.  I hope you (and others) find these additional perspectives helfpul. 

Matt Chester's picture
Matt Chester on Jun 25, 2020 11:33 am GMT

I really appreciate the detailed follow up, Paul! This is most helpful

Patty Durand's picture
Patty Durand on Jul 6, 2020 1:31 pm GMT

Great perspective Paul. I am particulary concerned about this sentence: Falling natural gas prices have masked grid modernization rate increases to date. That is alarming. I take it from your piece that regulators probably don't realize this so when natural gas prices increase, as they inevitably will, there will be serious pain for rate payers. Correct? If that's true then I think these concepts need to be aired and discussed at the next few NARUC meetings. 

Paul Alvarez's picture
Paul Alvarez on Jul 6, 2020 6:16 pm GMT

Yes Patty your assumption is correct.  While natural gas rates (the single biggest determinant of electricity commodity prices) have been falling in recent years, distribution charges have been rising.  And yes, when natural gas prices increase, pain will be inflicted on electric rate payers, as the fixed nature of rate increases related to distribution investment in recent years will remain.  For any interested NARUC Electricity Committee or Sub-Committee members in the Energy Central audience, I am available to provide my counter-perspective/counter-narrative at your convenience . . . .

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