Ohio PUC Refuses to Gamble Ratepayer Money on Coal Plant Cost Stability

By Amelia Schlusser, Staff Attorney

The Public Utilities Commission of Ohio (PUCO) recently issued an order granting conditional approval for American Electric Power Ohio’s (AEP) electricity rate plan. PUCO declined, however, to approve AEP’s proposal to transfer excess costs or revenues from the utility’s coal-fired power sales onto ratepayers. The PUCO decision may represent a growing regulatory reluctance to subsidize high-risk fossil fuel plants with ratepayer dollars.

AEP’s Proposal

AEP Ohio sought PUCO approval to implement a Power Purchase Agreement (PPA) Rider that would require ratepayers to pay for any revenue shortfalls the utility incurred through its sales of coal-fired power. This rider centered on AEP’s ownership interest in two Ohio coal plants that were constructed in the 1950s. Under AEP’s proposal, the utility would sell power from these coal plants into the PJM Interconnection’s wholesale electricity market. AEP would deduct its operating costs from power sales revenues, then pass the difference onto the utility’s ratepayers. Thus, if the revenues exceeded the utility’s costs, ratepayers would receive a credit on their electricity bills. If the utility’s costs exceeded the revenues, ratepayers would be charged extra to make up the difference.

AEP argued that this PPA rider would “be used as a hedge against future market volatility, in order to stabilize customer rates.” According to the utility, the coal plants’ fixed costs are relatively stable in comparison to wholesale electricity costs. Therefore, when market prices rise (and AEP’s revenues are high), AEP’s ratepayers would receive a credit on their bills. When market prices drop, AEP’s ratepayers would be on the hook for the utility’s revenue shortfalls. The PPA rider would thus serve as a hedge against price volatility in the wholesale market, and in AEP’s view, ratepayers would benefit from more stable electricity rates.

PUCO’s Conclusion

PUCO acknowledged that the proposed rider would reduce ratepayer vulnerability to market volatility to some extent. However, the commission questioned whether AEP’s proposal would actually benefit ratepayers. In answering this question, PUCO noted that AEP’s ratepayers would not actually receive any of the power from the two coal plants. The PPA rider would therefore only provide a financial hedge against price volatility, and ratepayers would not directly benefit from the facilities’ power generation.  

PUCO then assessed whether this financial hedge was likely to benefit or harm ratepayers. The commission noted that the utility’s own projections on the rider’s rate impacts were inconsistent, ranging from an estimated $52 million net cost to an $8.4 million net benefit. The PUCO concluded that while the rider’s potential impacts were highly uncertain, the potential costs to consumers outweighed the potentially negligible benefits. The Commission ultimately found AEP’s arguments unpersuasive and was unable to conclude that the rider would actually promote rate stability or was within the public interest. Citing “considerable uncertainty with respect to pending PJM market reform proposals, environmental regulations, and federal litigation,” PUCO found that it was inappropriate to approve AEP’s rider proposal.

A Transparent Attempt to Pass Risks onto Ratepayers

AEP’s rider proposal appears to be a thinly veiled attempt to hedge itself against potential economic losses associated with its coal-fired generation. Both the 1.1 gigawatt (GW) Kyger Creek coal plant and the 1.3 GW Clifty Creek coal plant will celebrate their 60^th birthdays this year. At the time these plants were constructed, their heat rates were approximately 9,100 BTUs per kilowatt-hour of generation, According to the facilities’ respective websites, these were the two most efficient coal plants in the U.S. in 1955. Under the EPA’s proposed Clean Power Plan, however, Ohio coal plants are expected to improve their heat rates by 4–6%. During AEP’s rate plan proceedings, PUCO staff argued that ratepayer benefits from the proposed rider would be highly dependent on cost stability at these two coal plants, and noted that these costs “could increase significantly over the next few years as a result of additional capital expenditures, increases in coal prices, and environmental regulations.”

A number of environmental and industry interveners raised concerns that AEP’s rider aimed to force ratepayers to subsidize the utility’s aging coal plants and protect AEP’s investors from risks presented by future carbon and environmental regulations. These arguments may have influenced PUCO’s decision to reject the PPA rider. The Commission admonished AEP for attempting to maintain discretion to discontinue the rider after a two-year period, finding it “evident from AEP Ohio's testimony that the Company has made no offer to ensure that customers receive the alleged long-term benefits of the PPA rider.”

According to the U.S. Energy Information Administration, “Ohio is the third largest coal-consuming state in the nation after Texas and Indiana.” The PUCO’s apparent willingness to protect ratepayers from the risk of rising coal costs at the expense of utility profits may thus represent a sea change in the utility regulatory arena. On the other hand, the decision may simply stem from the PUCO’s reluctance to capitulate to overt utility self-dealing at ratepayer expense. In either case, it seems inevitable that these types of schemes will become increasingly common as coal power profits wane, and the PUCO should be commended for rejecting AEP’s rider proposal.

For more information on the PUCO decision, see EnergyWire’s coverage of the topic.

The Constitutional Implications of Oregon’s Coal to Clean Power Bill in Light of North Dakota v. Heydinger

By Amelia Schlusser, Staff Attorney

The Oregon legislature is currently considering a bill (introduced as SB 477 in the Senate and HB 2729 in the House of Representatives) that would prevent Oregon’s investor-owned utilities from selling self-generated coal-fired power to Oregon consumers after January 1, 2025. Last week’s post described the proposed legislation’s requirements and explained some of the bill’s practical implications.  I also noted that the bill raised some unanswered questions. The bill’s proponents explained that the introduced text is undergoing amendment to address these issues, which is a routine step in the legislative process. I also alluded to some potential legal implications associated with the bill’s distinction between utility-generated power and power sold on the wholesale market. This distinction helps ensure that the bill’s provisions comply with the Commerce Clause of the U.S. Constitution, which is the subject of this week’s post.

The Commerce Clause in Article I, Section 8 of the U.S. Constitution gives Congress authority to regulate interstate commerce. The negative corollary to this exclusive grant of federal authority is referred to as the “dormant” commerce clause. Under the dormant commerce clause (DCC), states may not enact laws or regulations that discriminate against or place an undue burden on interstate commerce. While states can enact laws that are necessary to protect the health, welfare, and safety of their citizens, these laws must not protect the economy of the enacting state at the expense of other states’ economies.

The Supreme Court has created a series of tests to determine whether state laws that discriminate or unduly burden interstate commerce violate the DCC. While these tests allow courts to give some level of consideration to state interests or purposes behind discriminatory regulations, the Supreme Court has held that state laws that regulate extraterritorially—regulating conduct beyond the enacting state’s borders—are per se invalid.

The Minnesota Decision

The federal district court in Minnesota recently issued a decision in North Dakota v. Heydinger, which involved a challenge to a Minnesota law that prohibited individuals from importing, committing to import, or entering into a long-term contract to purchase electricity that would increase power sector carbon dioxide emissions in Minnesota. The State of North Dakota, coal companies, and multi-state electricity providers challenged the Minnesota law, arguing that it violated the dormant commerce clause. The district court agreed and held that the law was per se invalid because it had an extraterritorial reach and regulated commerce that takes place entirely outside of Minnesota.

The district court determined that the Minnesota law applied to “power and capacity transactions occurring wholly outside of Minnesota’s borders” in violation of the dormant commerce clause. The court’s conclusion was premised primarily on the fact that Minnesota’s power grid is managed and operated by the Midcontinent Independent System Operator (MISO). Within the MISO territory, electricity generators from throughout the multi-state region sell power onto the grid, and electricity providers purchase power from the grid. The district court determined that this market-based grid system does not recognize state boundaries and cannot differentiate between power entering the grid in one state and leaving the grid in another. Therefore, the court reasoned, a non-Minnesota utility could inject electricity in the grid outside of Minnesota with the intent to sell this power to consumers outside of Minnesota, but this power could still end up in Minnesota and contribute to power sector CO₂ emissions in the state.  In the district court’s eyes, because a North Dakota generator could not guarantee that the coal power it injected into the MISO grid would not enter Minnesota, it would presumably be forced to adjust its non-Minnesota business practices to comply with Minnesota’s law.

Implications for Oregon SB 477 and HB 2729

The Minnesota district court’s decision is currently under appeal in the federal Court of Appeals for the Eighth Circuit, and while it’s difficult to predict exactly how the appellate court will rule, it’s entirely possible that the lower court’s decision will be overturned. Nevertheless, Oregon’s SB 477/HB 2729 was clearly written to avoid North Dakota v. Heydinger’s outcome. First, the bill only applies to investor-owned utilities (IOUs) operating in Oregon, so non-Oregon utilities are not subject to the bill’s requirements. Second, the bill explicitly exempts “market purchases of unspecified power” from the bill’s reach, so coal power generators outside of Oregon can still sell their power on the wholesale market without violating Oregon’s no-coal mandate. Finally, the bill directs Oregon’s IOUs to “reduce the allocation” of coal-fired power to zero by 2025, which indicates that IOUs operating both inside and outside of Oregon can still sell their coal-fired power to non-Oregon consumers.

These provisions should help the bill avoid the legal outcome that Minnesota’s law faced at the district court level. However, the Minnesota decision only addressed that law’s extraterritorial reach; because the district court determined Minnesota’s law was per se invalid under the DCC, it didn’t consider whether the law was discriminatory against out-of-state interests or whether it imposed an undue burden on interstate commerce. A full analysis of applicable DCC case law is beyond the scope of this blog entry. Nonetheless, it’s reassuring that the bill’s drafters appeared to recognize the potential Commerce Clause implications and took efforts to minimize the proposed legislation’s vulnerability to a constitutional challenge. 

Coal to Clean Power: The Oregon Legislature Considers a Bill to Replace Coal-fired Electricity Generation With Clean Energy

By Amelia Schlusser, Staff Attorney

The Oregon legislature is currently considering a bill that aims to reduce the generation and

PGE and PacifiCorp own shares in the Colstrip
Generating Station, a coal-fired power plant in Montana  

use of coal-fired electricity in the state and replace coal with clean energy by 2025. The bill’s sponsors, Senator Chris Edwards and Representative Tobias Read, introduced the proposed legislation as S.B. 477 in the Oregon Senate and H.B. 2729 in the Oregon House of Representatives. The introduced bill requires an “electric company” to “(a) Reduce the allocation of electricity from coal-derived generating resources to zero on or before January 1, 2025; and (b) Replace those coal-derived generating resources with clean energy.” This post discusses the bill’s applicability and specific requirements.

The Bill’s Applicability and Primary Mandate

The bill applies to electric companies that sell power to Oregon consumers. However, many electricity providers in Oregon don’t qualify as “electric companies” under Oregon law. The introduced bill uses the existing definition of the term found in ORS 757.600, which defines “electric company” as “an entity engaged in the business of distributing electricity to retail electricity consumers in this state, but does not include a consumer-owned utility.” In other words, the bill only applies to Oregon’s investor-owned utilities (IOUs), including PGE, Pacific Power, and Idaho Power. It does not apply to consumer-owned utilities, including municipal electric utilities, public utility districts, or rural electric cooperatives.

So under the introduced bill, Oregon’s three investor-owned utilities (IOUs) must “[r]educe the allocation of electricity from coal-derived generating resources to zero on or before January 1, 2025.” But what does this mean? Each of the IOUs operating in Oregon (PGE, Pacific Power, and Idaho Power) own or partially own coal-fired generating resources. Presumably a portion of the power from these plants is “allocated” to the utilities’ customers in Oregon. The bill requires these utilities to “reallocate” their coal-fired power to their customers outside of Oregon. In other words, the bill prohibits the IOUs from selling the coal-fired power they generate to Oregon consumers after January 1, 2025.

However, the bill “[d]oes not apply to market purchases of unspecified power.” This presumably means that the bill’s requirements don’t apply to wholesale sales of coal-fired power from third party generators to IOUs selling power in Oregon’s retail market. In other words, Oregon’s IOUs could still purchase coal-fired power on the wholesale market and sell that power to Oregon consumers. This distinction has legal significance, because the Federal Energy Regulatory Commission (FERC) has exclusive jurisdiction over wholesale electricity markets and the Commerce Clause of the U.S. Constitution restricts states’ from regulating commercial activity outside of their borders. I will explore this issue further in a later post. For now, I think it’s important to note that the bill would not create a total barrier to coal-fired power consumption in Oregon.

The Bill’s Secondary Mandate: Replace Coal-fired Power With Clean Energy

The bill ultimately requires Oregon’s investor-owned utilities (IOUs) to stop allocating (i.e. selling) electricity they generate from coal to Oregon consumers by 2025. In the meantime, the bill requires the Oregon Public Utility Commission (PUC) to direct the IOUs to “develop a least-cost plan” to reduce their allocations of coal-fired power. These plans must include “a comprehensive accounting” of the utilities’ coal-fired generating resources. Plans must also include an analysis of the costs each coal-fired power plant will incur over the remainder of the plant’s useful life and an analysis of whether a coal-fired power plant will become “uneconomical before the end of the plant’s useful life.” In addition, utility plans must include a “least-cost, least-risk analysis of the order in which the electric company will reallocate electricity generated by [coal-fired power] plants.” This presumably means that each IOU must evaluate different options for reducing sales of coal-fired power in Oregon and replacing that lost generation with power from other, “cleaner” resources, while minimizing costs and risks to ratepayers.

In addition to producing a “least-cost plan” to reallocate their coal-fired power, the bill directs each IOU to “identify the quantity and type of supply-side and demand-side resources that will replace the coal-derived generating resources.” The utility then must “identify the least-cost method of achieving a mix of energy resources that is at least 90 percent cleaner than the coal-derived generating resources being replaced.” So each IOU must determine which resources are available to replace their coal-fired generation, and identify the combination of resources capable of replacing coal power at the lowest cost to consumers. These replacement resources must be “at least 90 percent cleaner” than the coal-fired resources they replace. In addition, utilities must “give preference to resources that allow electricity to be transmitted to this state on a real-time basis without shaping, storage or integration services,” so long as the resource is not more expensive or less reliable than alternative resources. This means that utilities may only replace their coal-fired generation with variable renewable resources, such as wind and solar power, if these variable resource options are less costly than other options and do not compromise the reliability of the grid.

Unanswered Questions

The bill, as introduced, aims to achieve an important and admirable objective. Coal-fired power pollutes our air and water, emits more carbon dioxide than any other source in the U.S., and destroys our national landscape. Oregon’s proposed legislation strives to protect our air, land, water, and climate by eliminating this resource from the state’s energy supply. While this is a commendable goal, the proposed bill creates some significant questions. First, it does not define “90 percent cleaner,” and this ambiguity could leave the bill vulnerable to legal challenge if it becomes law. Second, the bill explicitly disfavors replacing coal-fired power with a combination of wind or solar power and energy storage. Given the bill’s least-cost resource mandate, this preference for non-variable resources is a little befuddling. And finally, the bill would repeal Oregon’s existing greenhouse gas emission standards for investor-owned utilities, which limit carbon dioxide emissions from all generating resources, including natural gas plants.

In addition to these textual ambiguities, the bill raises some interesting legal questions regarding state energy regulation. I’ll explore these issues in greater detail in next week’s post.