New Customer 138kV Utility Transmission Service 2

[rockman7892]

I'm involved in the early conceptual stage for a project that involves expansion of an industrial customer process which will add and additional 70MVA to their current base load of aprox 30MVA. In total new plant demand will be 100MVA.

The existing 30MVA base load is currently served by a utility service at 34.5kV but with the addition of the new 70MVA this will exceed 34.5kV capacity and utility will require plant to upgrade to 138kV service from nearby 138kV transmission lines.

I was hoping to get some input here from some folks on the utility side to hear standards, opinions, etc.. from utility perspective on this type of transmission service on a customer property.

1) My understanding with transmission level service is that due to NERC requirements the 138kv transmission service can be built on customer property but must be owned and operated by utility? Is there a typical voltage threshold at above which voltage these requirements come into play?

2) The customer's plant distribution will be 34.5kV so customer will build adjacent substation with 138kV-34.5kV transformers which they will own/operate. In this application with utility 138kV yard on-site is it typical for utility to leave their yard with breaker to feed over to nearby customer yard (one or multiple breakers depending on arrangement). What type of protection does the utility require that the customer provide on these incoming lines? In the case where customer has transformer in their yard does utility require customer to provdie high-side protection of this transformer (IE incoming breaker) in order to trip customer breaker before tripping off utility breaker?

3) Utility in this case requires customer to maintain a .95pf Lead/Lag however there is no documented PF penalty. Is that typical for utility to require high PF at this transmission voltage? Do they typically charge PF penalty if not met?

4) Does utility always require customer to pay for capital expense of any new service (distribution or transmission) with the cost of new equipment and construction? Is this always required for customer to pay up front, or does this sometimes can incorporated into rate charge?

5) The billing rate per kwh at 138kV is a fraction of what it is at 34.5kV. What is usually the typical driver for this much lower rate?

 

[waross]

Many of the answers to those questions may be unique to your local utility.
PF. Look under tariffs to find PF penalties.

--------------------
Ohm's law
Not just a good idea;
It's the LAW!

 

[FacEngrPE]

In Dominion Energy territory the information is likely in this document.
Dominion Energy - NERC Program Document Facility Interconnection Requirements - NERC Standard/Requirement: FAC-001 (R1, R3).
Your utility likely has a similarly named document.

 

[crshears]

Hello rockman7892,

What Bill said is a good place to start.

You asked:

Q: My understanding with transmission level service is that due to NERC requirements the 138kv transmission service can be built on customer property but must be owned and operated by utility?

My answer [MA] : This is not necessarily so; in my view, provided a customer understands the implications and consequences of playing with the big boys, there should be no overriding reason why a customer cannot own equipment at any voltage level, and I mean ANY; here in the province of Ontario, Canada, there are two major wind farms that tie into the 500 kV grid partway along a pair of 500 kV circuits. The utility chose to split the lengthy circuits into two separate ones such that the utility owns the 500 kV ring bus and the three circuit breakers at the split point switching station, but the lateral tap into each of the wind farms changes to customer ownership only a span or two away from the switching station; the customer owns and operates the 230 > 500 step-up autotransformers, the 34.5 > 230 step-up transformers, and all the interposed circuits.

Q: Is there a typical voltage threshold at above which voltage these requirements come into play?

MA: Not that I am aware of, but the customer must either be able to operate and maintain their equipment using in-house staff, or dependably contract this work out to others.

Q: The customer's plant distribution will be 34.5 kV so customer will build adjacent substation with 138 kV - 34.5 kV transformers which they will own/operate. In this application with utility 138kV yard on-site is it typical for utility to leave their yard with breaker to feed over to nearby customer yard (one or multiple breakers depending on arrangement)?

MA: Generally speaking, yes.

Q: What type of protection does the utility require that the customer provide on these incoming lines?

MA: The AHJ will dictate this, but there should be no reason why a customer cannot own, operate and maintain their own portion of a circuit protection scheme, provided this work is properly co-ordinated with the utility.

Q: In the case where customer has transformer in their yard does utility require customer to provide high-side protection of this transformer (IE incoming breaker) in order to trip customer breaker before tripping off utility breaker?

MA: Sometimes, but not necessarily; Hydro One has numerous 115 kV and 230 kV connected customer transformers whose protection schemes will trip their own secondary circuit breaker and send remote or transfer trip signals to utility breakers to clear the line, simultaneously sending an open command to the customer transformer high-side disconnect switch; the sending of TTs/ RTs are held on long enough to allow the primary ABS to open, following which these release allowing the supplying circuit to automatically return to service, typically by having a UV + T [ undervoltage + time ] circuit breaker place the circuit back on potential, with subsequent reclosure of the remaining breakers supervised by synchro-check relays. Incidentally, the utility uses this scheme for its own transformers as well, and sees no issue with a customer going the same route; nevertheless some customers have not done their homework and end up adding a not-necessarily-required but definitely quite expensive high-side circuit breaker to each customer transformer.

Q: Utility in this case requires customer to maintain a .95pf Lead/Lag however there is no documented PF penalty. Is that typical for utility to require high PF at this transmission voltage? Do they typically charge PF penalty if not met?

MA: What Bill said; careful checking of the fine print will reveal whether in fact there is "no documented PF penalty". Let us know when you have definitive answers on this one; it may open up an entirely separate thread . . .

Q: Does utility always require customer to pay for capital expense of any new service (distribution or transmission) with the cost of new equipment and construction? Is this always required for customer to pay up front, or does this sometimes can incorporated into rate charge?

MA: Maybe negotiable, maybe not, depending on the capitalization and financial standing of the utility, and whether or not politics get in the way and skew the process . . .

Q: The billing rate per kwh at 138kV is a fraction of what it is at 34.5kV. What is usually the typical driver for this much lower rate?

MA: It depends, specifically upon how the utility bills for its services, but generally speaking, the less equipment the utility has to design, build, operate, maintain and capitalize to supply power to any given customer, the less it costs the utility to supply power to that customer, hence the power charges for that customer will be lower; the customer gains this benefit at the cost of the increased capital and OM&A spending it requires to have their own high-voltage electrical equipment.

It is therefore incumbent upon the customer to not only do the math, but consider everything it will be taking on, and, if it looks favourable, take a deep breath and jump into the pool.

End of Q&A.

Supplementary anecdote:

The customer, whether generator or load, must take care to situate their revenue metering appropriately: a non-utility generator I know of got a rude awakening when they received their first power bill; the dual supply into their facility was from a pair of 230 kV circuits with other transformer stations tapped off of them, and the circuits also commonly transferred large amounts of remotely generated energy into a major metropolitan area [think Toronto]. Whenever there was any imbalance whatever between the two circuits, whether due to the utility unloading one of the tapped station transformers, or one of the circuits' terminals and/or breakers for maintenance, power would circulate through the customer's site.

This would not normally be a significant issue - but the NUG's revenue metering had not been configured to totalize the individual generator's outputs, but instead had been stupidly installed in the 230 kV taps to the circuits; four quadrant metering was employed, and since the cost for power FROM the system was charged at the consumption price and the revenues generated were paid for power sent TO the system, whenever there was power circulation through the customer's switchyard, they were billed for the net, the silly buggers.

This was remedied by the customer choosing to run with their 230 kV yard normally split, the yard being run "solid" only when and once the amount being generated on site was well in excess of any possible circulating power flow. They were not willing to spend the money to modify the revenue metering, instead choosing to live with the reduced security of running with their yard split whenever the weren't generating, and generating a lot, viz., > 25% of their installed capacity.

The moral of the story is, plan ahead, and ask lots of questions about whether what you're contemplating will have any unexpected consequences.

Hope this helps.

CR

"As iron sharpens iron, so one person sharpens another." [Proverbs 27:17, NIV]

 

[transmissiontowers]

I do the structural review of the customer owned dead end tower and the metering transformer stand for my utility in Texas. IIRC, in Texas the utility is required to provide the connection line and owns the towers, but we may get reimbursed for the cost of the tower line ( I don't get involved with costs, but we supply the design for the towers). The customer provides all the sub equipment including the dead end and metering support structure but must meet our tension load requirements. We supply the PT/CT to meter the load so I check the calculations for the support. We have a spec we give to the customer with all kinds of electrical requirements plus the structural requirements. Our philosophy is if the customer has an structural or electrical problem, we do not let it become our problem. Our normal customer T-Line voltage is 138kV and we have several industrial load customers that own the sub, but lately a few solar farms have been built that connect at 345kV because it was too costly to build a 138 line to them.

The customer typically locates the new sub close to one of our lines so the tap is very few tower spans. I'm not sure who fights with land owners for the line to connect their sub to our lines. The public hearings can get confrontational when we want to get approval to build a new T-Line, so I assume the customer would fight that battle.

_____________________________________
I have been called "A storehouse of worthless information" many times.

 

[davidbeach]

As stated, it's almost entirely up to the serving utility. I don't see any problems supplying upwards of 300MW at 34.5kV but it's something the utility has to be willing to do.

138kV, networked transmission, is definitionally BES. As such it will be owned by a NERC registered TO and operated by a NERC registered TOP, and ... A 138kV radial feed into a load serving substation is not BES and if it serves a single customer it be owned and operated by anybody without NERC registration (lots of customers and then it needs to be under the perview of a NERC registered DP.

The usual answer "it depends" applies.

I’ll see your silver lining and raise you two black clouds. - Protection Operations

 

[bacon4life]

When considering power factor, be sure to account for which side of the transformer the metering is placed. I had a case of a customer moving from secondary metering to primary metering without realized the power factor on the high side would be much lower.