Issue 28 - System Operator Newsletter

Frequency keeping selection changes

In our March newsletter we commented on widespread concern regarding the cost of frequency keeping, especially over the previous four months in the North Island.  The concern was centred around constrained on costs paid to frequency keepers.  With Electricity Commission support, we have identified some changes to the selection methodology that could be introduced quickly and will target the constrained on prices being paid.

Using functionality available in our Freqkemy software application, changes to frequency keeper selection methodology will be introduced on June 2nd.  The main aim is to reduce constrained on payments without compromising our system security objectives.

Details of the algorithm of our Freqkemy application used to select the frequency keeper are available on the frequency keeping section of our website.

The chart below shows frequency keeping costs, updated to include data for March and April.

We also published on our website a presentation we provided to an industry meeting on frequency keeping costs, held in April.  As well as introducing the changes noted above we told meeting attendees we would:

• conduct a test with a smaller frequency band in the North Island over night, when suitable arrangements with would-be providers are in place and system conditions permit.  If the trial is successful it may allow other providers to enter the market and enable us to consider the implications of using an asymmetric band
• be open to a proposal whereby a selected frequency keeper may sub-contract part of its obligation to a third party generator, and so facilitate multiple frequency keepers.  Our concern regarding multiple frequency keepers is about governance – we need to have one provider that is responsible for its own and its sub-contractor's performance.

2008 winter and supply issues

Special winter schedule:  Publication of the System Operator’s new Special Winter Schedule (SWS) began on Monday 12th May.  Please give us your feedback on the schedule, especially about how useful it is, and the current format.

The schedule is being produced every 2 hours from 14:00 each day and will contain information for the following trading periods:

• at any time prior to 14:00 on any day, the remaining trading periods of that day
• at any time from 14:00 on any day, the remaining trading periods of that day together with each trading period of the next day. 

NI – SI transfer capabilities: Updated information regarding the transfer capabilities of the HVDC and the lower North Island system have been published on our website.
 
Within the next fortnight we expect to publish additional graphs which we will update daily.  These will display:

• HVDC transfer (last 7 days)
• transfer over the BPE- HAY line showing any spare capacity (last 7 days)
• South Island sustained instantaneous reserve quantities offered and cleared (last 7 days)
• South Island fast instantaneous reserve quantities offered and cleared (last 7 days).

Variable reserves:  We have developed a proposal to introduce a form of variable reserves in a way that avoids major systems changes and which can be introduced operationally in fairly short order. 

Rather than reducing the reserve adjustment factors (RAFs) from 1 to 0, we will have the option of making step reductions (or increases), in blocks of 20% of required and offered reserves, that would not be dispatched under the current policy.  We have provided a rule proposal to the Electricity Commission and recommended it be adopted as a matter of urgency.  The rule changes mainly affect the System Operator’s Policy Statement, with one minor consequential change to Part G. 

We have also identified other changes to Part G that we think should be carried out to ensure the operational changes have correct price outcomes. 

The draft rule change proposal is on our website, including an explanation of the operational changes.

Pole 1: Transpower recently returned its Pole 1 to limited ‘emergency’ service and is now offering the asset on a very restricted basis.  The pole will be offered: 

• only in response to a Grid Emergency
• only in north transfer
• only in current control mode
• for a minimum run time of four hours following a start
• for a maximum run time of 240 hours in a calendar year and/or a maximum of 20 starts in a calendar year (which ever is reached first)
• for a minimum time between load changes of 4 hours
• for a minimum transfer level of 130MW
• for a maximum transfer level of 200MW.

To allow normal market response outside the 2 hour gate closure,  Pole 1 will not normally be included into the schedules until gate closure has occurred for the initial trading period of the period that Pole 1 is required to be on, even if infeasible solutions are being published.

Emergency management: our Operations Managers have started a series of meetings with distributors to refresh system emergency management procedures - these meetings are scheduled to be completed by the end of May.

Procurement Plan review for 2008

Our draft Procurement Plan for the period starting 1 December 2008 will be available early next week.

We are talking directly to a number of participants to gather comments and other ideas that can be addressed in the new plan. The main changes we have included in the draft are:

Contact John Campbell  with any comments at:
john.campbell@transpower.co.nz  or 021 390 428

Market systems renewal project

A new delivery schedule for our renewed market systems has been decided by our Board.  Late last year we announced there would be a delay in the systems being implemented.  Last December we started a review of the project, to ascertain what needed to be completed in the applications and supporting infrastructure and to gain confidence in a revised schedule.  The review took longer than we hoped but is now complete.

The high level timetable is:

• mid August 2008: completion of system integration testing (now underway)and start of site acceptance testing
• September 2008: System Operator training restarts
• November 2008: start of simulator training
• end of December 2008: new systems handed over to System Operator for transition
• January  - March 2009: transition plan underway (includes parallel operations)
• March 2009: renewed systems implemented
• June 2009: automated constraint development application used operationally. 

We are now discussing the timetable and the implications of the new programme with major participants.  We will schedule a participant workshop later in the year.

Standby residual check notices

The standby reserve calculation process (SRC) has now been in operation for a year, during which time   SRC notices have been issued reasonably regularly.  The SRC calculates shortfalls for energy and energy plus reserves (capacity) that would occur if we lost the largest risk (contingent event) on the power system. The largest risk could be either a generator, or the HVDC. The calculation is completed for the Pre Dispatch schedule, Dispatch Schedule and the Security Schedule.

A year on and we are interested to know what participants think about the process and the notices we issue.  In particular, are the notices valuable and are there any changes that would materially improve the information provided or the utility of the information provided?

Initially, the new market systems will not have the capability to deliver the current SRC notices.  We will have to replace our SRC process and build a change into the new systems (after they have gone live).  This gives us the opportunity to improve the notices if there are practicable changes we should make. 

Please forward any thoughts or suggestions for improvement to: dan.twigg@transpower.co.nz