EMK:Dispatch, Pricing and Power Flows

Disclaimer Reasonable care has been taken to ensure that the information in this paper is up to date at the time of issue. Potential users of EMarket should, however, ensure that they evaluate EMarket and this paper through an appropriate evaluation process in consultation with Energy Link. The authors are also reliant on certain information external to EMarket and Energy Link, for which no liability or responsibility can be accepted.

Introduction

This technical bulletin is intended to provide users and interested parties with a detailed explanation of how EMarket’s IQP dispatch and pricing module functions, including the DC power flow calculations embedded within it.

Other Documents

This bulletin is one of a series of technical bulletins relating to Energy Link’s EMarket and EMarketOffer (EMO) models. Taken together, the bulletins replace the old EMarket User Guide. A full series of bulletins covers an overview of the EMarket model, the details of the four major New Zealand hydro systems modelled in EMarket, water values and hydro offers, power flows, dispatch and nodal pricing, short term river chain optimisation and company optimisation.

Dispatch

Dispatch and pricing in EMarket and EMO are primarily determined by the methodology specified in Schedule 1 of Part 2 of the New Zealand Electricity Governance Rules (EGRs). The market implementation of these methodologies is currently Trans Power's SPD model which is a large scale LP.

Reserves modelling is required within EMarket, primarily due to their impact on generation. The reserve constraints are straight forward to model in principle, however, a major concern with reserves is the large number of reserve constraints which combine to significantly increase the processing time, often for little or no additional accuracy.

RiskOffsets are also required for the modelling of reserves. These are calculated for SPD using TransPower's RMT tool which is a complex non linear dynamic model of the generation and load on the Grid. RMT is too complex to implement within EMarket.

In EMarket and EMO dispatch, pricing and power flow are achieved by Energy Link’s IQP software module.

Optimum Dispatch

The dispatch objective function from Schedule G6 of Part G of the EGRs is to maximise the net purchaser surplus.

EGR Dispatch Objective

where the D_i are the demand bids and the BP_i the bid prices, G_j the dispatched generation with offers OP_j, R_k the dispatched reserves with offers OR_k.

This objective function is used to form the forecast prices and the pre-dispatch schedule using the demand bids BP_i, generator offers OP_j and reserve offers OR_k. But provisional and final prices are calculated using metered demand, so in effect it is performed by minimising the Cost function shown below. Note that the offers Ox have units of $/MWh whereas G and R have units of MW, so Cost has units of $/hour.

Pricing Objective Function

Both objective functions are subject to the constraints listed in the following table (This is not a complete list of all of the constraints within SPD). Note that j indexes generators, i indexes either lines or island, depending on context, n indexes nodes and c indexes class of reserve.

Constraint	Formulation
Generator output greater than zero	Gj ≥ 0 ∀j
Generator output less than maximum output	Gj - Gj,max ≤ 0 ∀j
Generation plus reserve less than generator's maximum output	Gj +Rj - Gj, max ≤ 0 ∀j
Reserve less than a specified input, rslopej, proportion of generation	Rj - rslopejGj ≤ 0 ∀j
Nodal Energy Balance Constraints: Energy conserved at each and every node. Note that the Zin and Zout include any HVDC flows in or out of node
AC line flow, Zi, within thermal limits which are usually the same in both directions	Zi - Zi, max ≤ 0 ∀j Zi, min - Zi ≤ 0 ∀j
HVDC MW within limits but note maximum transfer different in each direction	As for AC lines
Losses match power flows	Handled by DC power flow formulation
Island Reserve Constraints: For each island and class of reserve (6s and 60s) total reserves greater than or equal to island risk Si
For each island and class of reserve (6s and 60s) island risk greater than or equal to island risk adjustment factor times maximum generator unit output less RiskOffset	Si, c ≥ IRAFi, c max (Gj - RiskOffset)
For each island and class of reserve (6s and 60s) island risk greater than or equal to island risk adjustment factor times HVDC MW into island less HVDC overload factor ZDCOL for the island	Si, c ≥ IRAFi, c (ZDC - ZDCOL)