$1 Billion in Electric Transmission Projects Approved by PJM; What’s the Impact on Network Integration Service (NITS) Rates?

Last week, PJM’s Board of Managers approved $1 billion in transmission projects for some of the various utilities in the territory, including PSEG, PECO, and ComEd.  Guess who gets to pay for the projects? (hint: it’s you, if you’re in PJM territory).  So why, and how, were these projects approved?  And what can you do to reduce your exposure to these cost increases?  Read on to learn about the transmission projects and Network Integration Service (NITS) rates.

• Why are transmission projects important?
• How does PJM determine what projects to approve?
• How do customers pay for these projects?

Why are transmission projects necessary?

The nation’s electricity transmission infrastructure is the backbone of our grid.  Transmission (think huge overhead wires that transmit electricity over long distances) enables the bulk transfer of electrical energy.  Transmission projects have been identified as the most difficult public infrastructure projects to develop; overhead wires are generally ugly, basically everyone exhibits NIMBY-ism (Not In My Back Yard), the projects are multi-jurisdictional spanning up to hundreds of miles and crossing counties, towns, hamlets, and villages, and almost no one understands how important transmission wires are for increasing reliability, reducing generation and congestion costs, and of utmost importance in today’s environment, reducing Greenhouse Gas Emissions.

Transmission and distribution comprise a substantial, and growing, portion of your costs.  But why? In short, our electricity (and energy in general) infrastructure is old.  Consider this:

• According to the US government’s Quadrennial Energy Review, the U.S. electricity grid is “aging, inefficient, congested, and incapable of meeting the future energy needs of the information economy without significant operational changes and substantial public-private capital investment over the next several decades.”
• The Edison Electric Institute estimates that by 2030 the US electric utility industry will need to make a transmission and distribution infrastructure investment of about $900 billion
• In 2013, the American Society of Civil Engineers gave the US energy infrastructure a grade of D+, citing T&D facilities that date back to the 1880s, rising congestion at key points in the system, and complex permitting and siting issues that prolong the modernization process and increase costs

With aging infrastructure and the need to meet reliability objectives, it’s no wonder there are (and will continue to be) substantial investments needed in transmission projects (not just in PJM territory as described in this article – see our prior article Costs for New Transmission Lines in NY Passed Through To You)

How does PJM determine what projects to approve?

PJM’s Regional Transmission Expansion Plan (RTEP) process identifies transmission system additions and improvements needed to serve more than 65 million people throughout 13 states and the District of Columbia.

PJM seeks transmission proposals during each RTEP window to address one or more identified needs – reliability, market efficiency, operational performance and public policy. RTEP windows provide opportunity for nonincumbent transmission developers to submit project proposals to PJM for consideration. The scope and timing of the issue to be addressed and likely type of solutions to be submitted dictate window duration. Once a window closes, PJM proceeds with specific company, analytical and constructability evaluations to assess proposals for possible recommendations to the PJM Board. If selected, designated developers become responsible for project construction, ownership, operation, maintenance and financing.

How do customers pay for these projects?

Each PJM zone has certain annual transmission revenue requirements, which translate to a certain $/MW-Year.  Customers pay based on their (NSPL) network service peak load contribution (PLC) tag (also called transmission obligation), which is similar to the way the capacity market works with capacity PLCs.  Your transmission PLC is determined by your load during the single highest peak load (1CP) – in your zone, not all of PJM – from the 12 month period November 1 to October 31.  This varies vs. capacity PLCs which are determined by the 5CP, or average of the 5 highest peak loads.  Charges are calculated based on the PLC tag (effective Jan 1 to Dec 31) multiplied by 1/365^th of the applicable Network Integration Transmission Service (NITS) rate times the number of days in the billing period.  Like capacity, you can’t control the actual rate that is paid (the $/kW), but you can control your account’s peak load with active peak load management.  By reducing your contribution to the 1CP, your transmission PLC will be lower, and thus the total NITS charges will be lower.