How Cost Allocation Works for Transmission Lines

A brief history of transmission cost allocation

Historically, deciding who paid for new electrical infrastructure was relatively straightforward. For most of the 20th century, utilities existed as vertically integrated monopolies serving a particular geographic area, and were responsible for building all of the electrical infrastructure (generation, transmission, and distribution) in that area. Transmission lines were relatively short, mostly connecting individual power plants to population centers, and the customers of a given utility bore the cost of its new transmission. As time went on, different utilities increasingly tied their transmission systems together into large, interconnected grids¹ and began to jointly build large-scale infrastructure, but this same basic pattern of development remained.

Today, this pattern has changed. In the 1990s, states and the Federal Energy Regulatory Commission (FERC) began to restructure the electrical industry, in what is often referred to as “deregulation.” Power plants began to be built by independent merchant generators instead of utility companies, and utilities were forced to open up their transmission lines and transmit power from anyone who wished to use them. FERC also pushed utilities to join “Regional Transmission Organizations” (RTOs) that would manage a utility’s transmission lines and allocate their capacity in a fair and unbiased manner. Today, roughly two-thirds of the nation’s power is supplied by RTOs.

Deregulation severed the tight link between the builders and users of transmission infrastructure. Now, a utility that built a new transmission line might find it being used to supply power generated by an independent generator to another utility’s customers. And in RTOs, transmission projects might be built specifically to improve the functioning of the electricity market, rather than being attached to any specific generation project.

At the same time as the power industry was being restructured, states increasingly began to favor renewable energy sources, often creating renewable portfolio standards (RPS) mandating that a certain fraction of the electricity in a state come from renewable sources. As some areas are much windier and sunnier than others, renewable-generated electricity was often transmitted long distances over high-capacity transmission lines, crossing several states and utility boundaries in the process.

FERC recognized that the question of cost allocation was now much more complex, and issued several orders to try to bring clarity to the issue. The first, Order 890 in 2007, established nine principles of transmission planning, including cost allocation. FERC noted, “Transmission providers and customers cannot be expected to support the construction of new transmission unless they understand who will pay the associated costs.” In this order, FERC allowed transmission owners significant flexibility in deciding on cost allocation methods, and would judge the methods chosen based on several factors:

“First, we consider whether a cost allocation proposal fairly assigns costs among participants, including those who cause them to be incurred and those who otherwise benefit from them. Second, we consider whether a cost allocation proposal provides adequate incentives to construct new transmission. Third, we consider whether the proposal is generally supported by state authorities and participants across the region.”

Order 890 was followed by 2011’s Order 1000, which aimed to further clarify the cost allocation issue. While still allowing transmission owners flexibility to decide their own allocation methods, Order 1000 required each planning region to file cost allocation schemes that would govern future projects, subject to six principles² of cost allocation:

1. The beneficiary pays: the cost of transmission facilities must be allocated to those within the transmission planning region that benefit from those facilities, in a manner that is at least roughly commensurate with estimated benefits. 
2. Those who receive no benefit from transmission facilities, either at present or in a likely future scenario, must not be involuntarily allocated any of the costs of those transmission facilities.
3. If a benefit-to-cost threshold is used to determine which transmission facilities have sufficient net benefits to be selected in a regional transmission plan for the purpose of cost allocation, it must not be so high that transmission facilities with significant positive net benefits are excluded from cost allocation.
4. The allocation method for the cost of a transmission facility selected in a regional transmission plan must allocate costs solely within that transmission planning region, unless another entity outside the region or another transmission planning region voluntarily agrees to assume a portion of those costs.
5. The cost allocation method and data requirements for determining benefits and identifying beneficiaries for a transmission facility must be transparent, with adequate documentation to allow a stakeholder to determine how they were applied to a proposed transmission facility.
6. A transmission planning region may choose to use a different cost allocation method for different types of transmission facilities in the regional transmission plan, such as transmission facilities needed for reliability, congestion relief, or to achieve Public Policy Requirements.

In addition to addressing cost allocation, Order 1000 removed a utility’s “Right of First Refusal” (ROFR) for regional or interregional transmission projects, forcing such projects to be subject to competitive bidding rather than simply being built by the utility.³ However, critically, FERC allowed exemptions from competition for reliability-focused projects for which there was “an immediate need.” This ruling has incentivized utilities to focus on short-distance transmission lines, and to avoid longer-distance lines.

Like the allocation of the costs of transmission lines, waits for interconnection have also restricted the construction of new generation capacity. Put simply, an energy generation project must be studied before it’s built to see if the grid can accommodate it, or if the existing transmission network must be upgraded. Projects wait in the “interconnection queue” prior to being evaluated. Historically, any transmission additions were paid for entirely by the builder of the new generation project. This system worked acceptably when a relatively small number of large power plants were being added each year. But today, projects are often much smaller, and the number of proposed projects has increased enormously. In fact, the amount of generation capacity waiting in the interconnection queue is greater than the capacity of all existing US power plants.

This has strained the interconnection queue system. Allocating the costs of new transmission upgrades entirely to a single project places a disproportionately large financial burden on those projects, since subsequent projects will often benefit from this new transmission infrastructure. As a result, developers of electricity generation now wait to determine the burden on them before committing to projects. Developers enter generation projects into the queue, wait to find out what transmission infrastructure (if any) they would be required to pay for, and then drop out if the cost is too high. When projects drop out, queue wait times lengthen (since now other projects need to be re-evaluated) and transmission planning costs increase.

In an attempt to address this issue, FERC recently issued Order 2023, which changes the interconnection process so that projects will be evaluated in batches, rather than one by one. Additionally, the costs of new transmission infrastructure will be spread across the entire batch. Hopefully, this policy change will allow more new generation projects to be built.⁴

The current state of play

New transmission projects are planned by regional entities, such as RTOs, and also by individual utilities. Projects can be planned for a variety of purposes: smaller-scale reliability improvements may be undertaken by a single utility, regional projects are used by multiple utilities within an RTO, and long-distance “backbone” lines might cross the boundaries of multiple RTOs.

Cost allocation is often highly contentious for regional transmission projects. FERC Order 1000 and federal courts require costs to be allocated roughly in proportion to benefits (i.e., beneficiary pays), and FERC approvals of cost allocation methods are often litigated if someone believes this isn’t taking place, or if allocations aren’t “just and reasonable,” as required by the Federal Power Act, which gives FERC authority over interstate transmission. For instance, courts have rejected spreading the costs of a transmission project over an entire region (called “postage stamp allocation”) when it has not been specifically supported by evidence, as the practice places cost burdens on some customers who do not derive meaningful benefits. Similarly, courts have rejected methods that allocate costs entirely locally, when some benefits accrue to the region as a whole.

But even though FERC Order 1000 and legal precedent require cost allocation to be commensurate with benefits, in practice these evaluations can be crude, and decisions are often controversial. Recently, FERC was sued by two transmission owners in Long Island for approving a 50-50 cost allocation between local and regional customers. FERC prevailed in this lawsuit, but the court noted that 50-50 was not a “magic number,” and that a 60-40 allocation in either direction would likely have been acceptable as well, illustrating the difficulty of allocating costs precisely. And while postage stamp allocation is not allowed over entire regions, FERC still approves it for new transmission projects on a sub-region basis, which can be contentious. A group of communities in Colorado and Nebraska, for instance, recently filed a FERC complaint against the Public Service Company of Colorado, asserting that a proposed $2 billion power line would double their transmission costs even though the line would likely provide no benefits to them.

Moreover, there is no standard list of benefits agreed upon by all parties. This makes regional cost allocation more complex, as various regions have to find agreement on what benefits to consider. Currently, utilities and organizations are able to choose whatever benefits (reliability, addressing congestion, cost reduction, etc.) seem most appropriate to them. An RTO might plan new transmission projects that cross multiple states, and those states may have different energy policies and may consider different benefits to be important. Quantifying benefits is not always easy, and some may question whether a supposed benefit is in fact providing much value. A Brattle report noted that the easily quantifiable benefits of a transmission project may be less significant than the benefits overall (when difficult-to-quantify benefits are included). Of the quantifiable benefits, those that can be easily divided and clearly allocated may be an even smaller subset. And the benefits of a more “holistic” approach to transmission, where multiple pieces of infrastructure work in concert, may be missed when analyzing projects in isolation.

For interregional projects, such as those that cross the “seams” of different RTOs, the cost allocation problem is even more difficult. FERC Order 1000 requires regional organizations to coordinate on interregional transmission planning, but does not require any specific planning or study method. Because organizations use different cost allocation methods, and may not agree on the relative costs and benefits of different transmission projects, interregional transmission lines face an enormous approval hurdle. In practice, almost no interregional projects are built. An Americans for a Clean Energy Grid report tracking progress on several different high voltage transmission lines noted that successful projects were largely those able to sidestep difficult cost allocation issues. These projects were either funded directly by builders of new generation projects, or they existed within the bounds of a single utility. Large-scale regional or interregional projects, by contrast, had much lower success rates.

As a result, transmission investment is overwhelmingly focused on smaller-scale local and reliability projects. Because transmission owners have first right of refusal for these projects, they can build them, and recover the costs from their ratepayers, without needing to solicit competitive bids. And local, reliability-focused projects are also immune from being subjected to an often-contentious regional planning process. An ACORE report noted that it’s “very difficult to get [utilities] to support new transmission construction,” and a Brattle report found that by far the easiest projects to get built are those that don’t involve any disagreements on cost allocation, where the entire project takes place within the boundaries of a single utility. 

Because of the pattern of transmission investment, fewer actual lines of new transmission are being built, even though the quantity of investment is steadily increasing. Projects that do get built often bypass the federal cost allocation problem entirely. Merchant transmission builders, for instance, can recover their costs from power companies that subscribe to use their capacity.

Looking ahead

FERC realizes that current cost allocation issues have not been fully resolved by Order 1000, and is considering new rules to address them. A proposed FERC rule would require transmission organizations to undertake more long-term planning, specify the benefits that may be considered, and give individual states more of a say in cost allocation methods. It would also partially reinstate the first right of refusal for regional projects, in the hopes that this would increase utility’s incentives for building them (though under the new rule such projects would need to have joint ownership). However, the current proposal would allow a transmission developer to use a pre-approved cost allocation method if states couldn’t come to an agreement on cost allocation. 

Some opponents of the new rule have voiced concerns that, because long-term planning must take into account things like states’ renewable energy policies, the rule will have the effect of forcing some states to pay for transmission built for the purpose of other states’ renewable energy policies, effectively subsidizing other states’ renewable energy construction. Republicans had the same concerns of unfair cost allocation when Order 1000 was passed.

However, it’s unlikely this will be the case: the current proposed list of benefits to be considered do not include renewable or low-carbon energy as a benefit itself, and the principle of “beneficiary pays” is expected to remain.

To accommodate growing demand, and to decarbonize energy production, America needs to construct an enormous amount of electrical infrastructure. Saul Griffith estimates that producing all required energy with solar PV would require 15 million acres of solar panels, an amount of land area roughly the size of West Virginia. Producing it with nuclear power would require on the order of 1,000 more large nuclear plants. Whether we build 10-mile transmission lines to connect new power plants to nearby cities, or 1,000-mile transmission lines to move power across the country, we’ll need a lot of them. The REPEAT project estimates that to avoid restricting the growth of solar and wind generated electricity, we’ll need to double the recent construction rate of transmission lines. 

Though progress is being made on transmission reform, more work is needed, such as rules that would allow FERC to designate transmission corridors and issue federal permits. But while these rules will undoubtedly continue to evolve and be debated, the principle of “beneficiary pays” for cost allocations is expected to remain.