Ensure appropriate investment in transmission and generation infrastructure;
Recognize and respect regional industry differences and preferences;
Encourage cost-effective and not overly complex regional solutions;
Support rational long-term generation resource arrangements that are in turn supported by long-term transmission service provided at just and reasonable rates;
Foster well-functioning wholesale electric markets; and
Ensure that public utility sellers of power at market-based rates
charge “just and reasonable” prices.
- There is no way to achieve coherence in transmission policy without formal cooperation between federal and state regulators. Congress should urge these regulatory bodies to begin this process, in order to address issues of transmission pricing, unbundling of services, siting, access, and planning.
- Who should bear the risks of a transition to a more competitive industry? This is clearly a question of policy, and should be treated as such. As a matter of policy, the jurisdiction which is responsible for creating stranded assets should be the one which deals with its consequences. I applaud the California and Michigan commissions for dealing with this issue explicitly as part of their proposals. The FERC has done the same in its recent NOPR, but has left unclear the issue of possible preemption of state jurisdiction.
- Registered holding companies are currently shielded from competition by the ability to pick the regulatory forum to which they turn for decisions, and by judicial determinations which insulate self-dealing from market forces. The proposed "fix" to the Ohio Power case, now before the Congress, is a step in the right direction. However, there are still gaps and overlaps between federal and state jurisdictions that need to be addressed. In order to supervise transactions involving registered holding companies, the FERC and state PUCs need to work together. If the Congress is unwilling to codify the Pike County doctrine, it should urge the FERC to adopt it explicitly as a formal doctrine of regulatory federalism, andmake rulings that are consistent with multiple layers of jurisdiction.
Excerpt from the Introduction:
Thank you for the opportunity to participate in this technical conference. My comments here and during the conference are my own and do not represent the opinions of anyone else. The focus of my remarks will be on carbon pricing and the interactions with short-term electricity markets as found in the organized wholesale markets in the United States. I do not address the design and implementation questions focused on investments and resource adequacy that underpin capacity markets.
On August 3, 2015, the U.S. Environmental Protection Agency (EPA) issued the Clean Power Plan (CPP) under Clean Air Act 111(d). The CPP limits carbon dioxide emissions from existing fossil fuel-fired electric power plants by providing state specific goals for carbon dioxide emissions from affected electric generating units. As part of the CPP, EPA considered the potential impacts of the CPP on electric system reliability. Specifically, the CPP requires each state to demonstrate in its final state plan submittal that it has considered reliability issues in developing its plan. Separately, on August 3, 2015, EPA, the U.S. Department of Energy (DOE) and the Commission agreed to coordinate certain activities to help ensure continued reliable electricity generation and transmission during the implementation of the CPP.
While the CPP assigns no direct role to the Commission, it is possible that the Commission may be called upon, through the EPA-DOE-FERC Coordination Document or for other reasons, to address concerns about reliability as the CPP is implemented. In that case, the use of appropriate modeling tools and techniques will be helpful to the Commission in carrying out its responsibilities for reliability.
This white paper identifies four guiding principles that may assist transmission planning entities, which may include regional transmission organizations (RTOs), independent system operators (ISOs), electric utilities, or other interested stakeholders, in conducting effective analysis of the CPP and associated state plans, federal plans or multi-state plans (compliance plans). The North American Electric Reliability Corporation (NERC) and the regional electric reliability organizations may also benefit from following these guiding principles as they perform CPP-related analyses. These guiding principles address four areas: (1) transparency and stakeholder engagement; (2) study methodology and interactions between studies; (3) study inputs, sensitivities and probabilistic analysis; and (4) tools and techniques.
Incorporating these guiding principles in the modeling of the CPP compliance plans is one way to promote a robust analysis of the reliability impacts of the CPP. The guiding principles discussed herein may form the basis for additional action by staff, such as industry outreach or technical conferences, or future action by the Commission.
Excerpt from the Executive Summary
The Environmental Protection Agency’s proposed Clean Power Plan (CPP), published in June 2014, raises substantial operational challenges for regional transmission organizations (RTOs). In the CPP, EPA specifies emission reduction targets for 49 of the 50 states, based on EPA’s modeling that purportedly shows that each state can achieve the specified reduction targets through the use of four “building blocks.” States are to develop plans to meet the targets between 2020 and 2030, and are offered “flexibility” to use any combination of the four building blocks specified and/or other means (if approved by EPA) to achieve these targets. The State plans – required by June 30, 2016 (unless an extension is granted) - must specify how each state intends to meet the targets.
While there are many issues, questions and concerns with the ability of states and utilities to meet EPA’s emission reduction targets based on the use of EPA’s four building blocks (or through other means), building block 2, in particular, raises substantial issues for systems operators and RTO/ISO market operations because it involves changing the current methods of how electricity is dispatched throughout the nation’s bulk power systems.
Either FERC or the states have always overseen how security constrained economic dispatch is conducted to maintain reliability while cost-effectively serving customers. But, if EPA’s proposed rule becomes final, it, and not the system operators that federal and state regulators have entrusted, will make such critical decisions for our nation’s utility customers regardless of costs.
Excerpt from the Executive Summary:
It is time to take stock of the Federal Energy Regulatory Commission’s (“FERC”) electric restructuring policies. APPA believes substantial “mid-course corrections” to FERC’s policies are needed to fix existing Regional Transmission Organizations (“RTOs”) and to encourage non- RTO alternatives in those regions where RTOs are not likely to form.
To protect electric consumers, as the Federal Power Act (“FPA”) requires, FERC should reorient its policies to make sure electric consumers in fact— not just in economic theory—benefit from electric restructuring.
Excerpt from the Introduction:
Electric-industry restructuring has derailed. The massive blackout of August 14, 2003 certainly was not needed to underscore the point, but it adds urgency to the effort to find solutions. Wholesale markets continue to evolve slowly and erratically but are impeded by state- federal conflict, regulatory and legislative uncertainty, malfeasance, poor credit and outright collapses, of which Enron is only the most notorious. FERC’s efforts to promote more efficient markets through regional transmission organizations and a wholesale market platform offer promise, but have generated confusion and opposition. In the last five years, increased generation competition has elicited more than 100,000 megawatts of gas- fired peaking and baseload capacity, which has contributed both to a period of relatively low wholesale prices in many regions and increased exposure to gas price volatility across the system. But competitors’ losses have created substantial uncertainty about how quickly and on what terms capital markets will support additional investment throughout this sector. Indeed, investment in all categories of electricity infrastructure is down significantly, in part because of surplus capacity conditions in certain regions, but also because of uncertainty concerning which entities have the responsibility for identifying and making investments in the transmission and distribution networks, and uncertainties about how the associated costs will be recovered. A challenge in reviving these capital flows is to clarify prospects for cost recovery and reward: for example, when and on what terms will distribution utilities have the ability to enter into long-term contracts with generation service providers; how will distribution utility responsibilities interact with the opportunities created for competitive retail suppliers in states with retail competition; who has the responsibility for identifying needed enhancements to the transmission network; how will they be paid for securing them; and who will pay? The August 2003 blackout is a reminder of how much hinges on finding practical answers promptly.
Excerpt from theIntroduction:
The era of electric and natural gas industry restructuring ushered in by Congress and implemented by FERC and state public utility commissions has now been in place for more than five years. In the wake of these momentous shifts in regulatory policy, electric and gas companies have responded with fundamental changes in their business strategies. Some have decidedly “stuck to their knitting,” while others have merged, sold assets, invested overseas and in new businesses, and in some cases completely abandoned their historic business roots. With the economic downturn, the collapse of merchant generators and the decided slowdown in industry restructuring, the time is opportune to examine corporate winners and losers from this unprecedented round of industry restructuring.
Winners and losers in the battle of restructuring can be measured from a variety of perspectives. The major constituents, however, are clearly shareholders and investors on one hand and consumers on the other. The focus of this analysis is the shareholder. In examining the impacts on shareholders, we look to a variety of related metrics that speak to financial performance.
Our analysis focuses on total shareholder return for the group of 64 companies that compose the Fortune 1000 energy companies.2 Within this mix is a combination of utilities, pipelines, energy merchants and independent generators with diverse business strategies. Aligning companies with their returns to shareholders paints a dramatic picture of widely differentiated financial performance. The degree of variation is particularly notable in light of an industry once noted for its stable returns appealing to the most conservative investors.
Excerpt from the Executive Summary:
News of Enron’s accounting improprieties and subsequent collapse have been part of the continued eventful last two years for the electric supply industry. Shortly after the skyrocketing prices in California and the West of 2000 and 2001 had subsided, the Enron developments began to come to light in late 2001. This has lead to investigations by several federal agencies and revelations of improper trading and reporting practices of other energy companies. As a result of this and reduced demand for electricity, the industry has been hit by a “credit crunch” as investors have become more wary and has forced many energy companies to cut back on trading activities, sell assets, and reduce future investments in order to improve their balance sheets. In the face of all the industry turmoil, while many retail markets remain relatively inactive, particularly for smaller residential customers, overall market activity has increased from last year. Wholesale markets since California settled down, continue in general to function well from an operational standpoint, however, there continues to be strong evidence that significant market power is being exercised in all markets that have been examined.
The passage of the Energy Policy Act in 1992 ushered in a new competitive era in the U.S. electricity industry. The task ahead for both state and federal regulators is to make the regulatory changes that are a necessary part of these changes in the industry in a coherent fashion.
The Congress must encourage the FERC and the state commissions to exercise statesmanship on these issues, rather than continuing to engage in bureaucratic turf battles.
general, is characterized by a massive cognitive dissonance. FERC issues a lengthy series of
significant questions about just about everything a federal regulator would ever want to know about
transmission, except for how they relate to the other set of regulators who have so much to say
about the grid. Other than a passing reference, that question did not get asked at all. Thus we are
involved in a debate where most of the discussion takes place in a forum that is responsible for
significantly less than half the revenue that's derived from transmission. Moreover, the regulators
that are responsible for the bulk of transmission revenues set them as part of bundled retail rates
and rarely, if ever, think about transmission in discrete terms. Accordingly, we not only have
cognitive dissonance as to the forum and the substance, but we have decision-makers making critical
decisions who simply do not think about what their peers may be doing, except to the extent that
state regulators worry about FERC preemption of their authority, and FERC fears that state
regulators are actually monopolists who intend to impede all competition. Beyond that, there is
not much dialogue. Given this state of affairs, it seems unlikely that coherent transmission policies
will emerge in the absence of a more formal system of cooperation.