The Financial Model

The Financial Model An Introduction to Locational Based Marginal Pricing Concepts Dean Chapman New York Independent System Operator

Financial Model • Addresses operation of power system through financial incentives/disincentives • Elements of Financial Model: • Congestion Management accomplished by Redispatch with locational pricing • Transmission Service is implied, not specifically reserved or purchased • Congestion charges may apply • Financial hedging instruments available • Balancing Market integral part of model • Two settlement market typically employed • Day-ahead by hour and real-time spot market

Locational Pricing is Key to understanding Financial Model • We will discuss: • Security-constrained dispatch with locational pricing • Spot market and bilateral transactions • Imports, exports and wheels • Losses • Use NY as example • Pure financial model, automated • Development was driven by early IPP development in NY, NYPP experience

Outline • Locational Pricing Example w/wo Congestion • Internal Bilateral Transaction • External Wheel Example • Financial Transmission Rights (TCC) • Losses • Actual Example

Start with simple example • Assume isolated control area with west and east region • Assume single transmission path between west & east • East load is typically higher than west

Simple Example(No congestion) Interface Limit = 400 200 Gen2=600 Load2=800 Gen1=400 Load1=200 West East 30 LBMP =30 LBMP =30 30 400 600

RTO Balance Sheet(unconstrained – pure spot Mkt) Income W. Load 200x$30 = $6,000 E Load 800x$30 = $24,000 total = $30,000 Payout W. Gen. 400x$30 = $12,000 E. Gen 600x$30 = $18,000 total = $30,000

Transmission Congestion Interface Limit = 400100 200100 Gen2=600 700 Load2=800 Gen1=400 300 Load1=200 West East 40 LBMP =20 LBMP =40 20 300 700

RTO Balance Sheet(constrained – pure spot Mkt) Income W. Load 200x$20 = $4,000 E Load 800x$40 = $32,000 total = $36,000 Payout W. Gen. 300x$20 = $6,000 E. Gen 700x$40 = $28,000 TCC Pmt @ (40-20) 100x$20 = $2,000 total = $36,000

Locational Pricing • Generators selling into market get paid LBMP • Load buys from market, pays LBMP • Generation more valuable in east ($40 vs $20) • It can serve heavy load without contributing to congestion • Incentive is to build generation in east (or build more transmission) • Load in east is “dis-incented” • Curves are bid by generators • Will be paid LBMP as long as bid is lower or equal to LBMP • Can bid any price but will not be dispatched if bid>lbmp

Internal Bilateral Transaction • Suppose Generator in west wants to sell 50 MW to load in east • Parties agree on sale price in private (say $30) • Generator may or may not change bid curve • No reason to do so • If not, Dispatch does not change!

Bilateral Transactionfor 50 MW from west to eastwith Congestion Interface Limit =400100 200 100 Gen2=600 Load2=750+50 700 Gen1=350250+50 Load1=200 West East LBMP =20 LBMP =40

Internal Bilateral Transactionwith congestion • Difference between pure spot market and bilateral transaction is ONLY in the way it is billed! Two ways to accomplish Transaction • Contract for Differences – ISO not involved • Generator sells 50 at his bus for $20/MW. • Load buys 50 at his bus for $40/MW. • Generator makes up difference by paying load $10/MW. • Gen nets $10 (does it cover his cost?) • Register with ISO – • Generator withdraws 50 from spot mkt. Sale • Load does not pay ISO for 50 • Load pays gen. $30/MW. • Tx customer pays ISO difference in LBMPs ($20/MW) as congestion charge. • Net to gen. is $10 (same result)

Hedging against Congestion Charges • Suppose generator owns 50 MW of TCCs (Transm. Congestion Contract or FTR) on this interface • For every hour there is congestion, he gets paid 50 x difference in LBMPs • In this example, payment would exactly cancel $20 cong. charge he would have paid • He buys TCC on auction or in secondary market • Must judge purchase price against hourly exposure to congestion • (More about TCCs later)

RTO Balance Sheet(constrained – Internal Transaction) Income W. Load 200x$20 = $4,000 E Load 750x$40 = $30,000 Cong. Chg 50x$20 = $1000 total = $35,000 Payout W. Gen. 250x$20 = $5,000 E. Gen 700x$40 = $28,000 TCC Pmt @ (40-20) 100x$20 = $2,000 total = $35,000

Gen. Balance Sheet(constrained – Internal Transaction) Income Sale 50 x $30 = $1,500 TCC Income 50x$20= $1,000 total = $2,500 Less payout = $2,139 Net = $361 Payout Cost of gen 50x$20= $1,000 Cong chg 50x$20 = $1,000 TCC Purch1 = $ 139 total = $2,139 1Assume TCC cost $100,000 for 50 MW for 30 days, 24 hr/day Per hour cost = $100,000/ (30*24)= $139

External Transactions • External entity can bid generation into market, buy energy from market • Delivers to or takes delivery from pseudo-bus at border • Also possible to wheel energy through market • Next example shows 150 MW west-to-east wheel

Wheel with Transmission Congestion Interface Limit = 400100 150 200100 150 Gen2=600 700 Load2=800 Gen1=400 300 Load1=200 850 150 West East 45 LBMP =20 LBMP =40 15 45 15 150 850

Wheel with Congestion • Note that interface flow does not change • Wheel is for greater than interface limit! • ATC would have been zero before scheduling this transaction! • Congestion charge is now $45-$15=$30 ! • Financial congestion increases • Additional wheels can be accepted until west generation down to minimum or east generation hits max (or price becomes prohibitive!!!)

Financial Transmission Rights • Total Capacity on this interface is 100 MW • In old world, reservations only available for 100 MW • In financial system, set of awarded TCCs must form feasible case observing all limits, therefore only 100 MW of TCCs available also! • TCC owner does NOT have to schedule transactions to get paid • Transmission customer does NOT have to own TCCs to use transmission • Scheduling of energy does not have to consider who owns what transmission rights. All have equal access but may be exposed to congestion charges

Observations • All internal transactions are automatically accepted, never curtailed • Redispatch to control congestion • Externals accepted up to physical limit of redispatch • Rules allow bilateral transactions to be ignored when dispatching system • Generator does not have to actually generate – can buy at local LBMP • Load can use less, sell excess into market • Congestion Management (i.e. re-dispatch) and Bilateral Market are effectively decoupled!

Losses • ISO dispatches to total load + losses • Pays generators, collects from loads but generation exceeds load by amt of losses • Cost of losses built into LBMP • LBMP adjusted by loss factor • Adjustment equal to difference between Incremental cost of supplying 1 MW to reference bus at that bus and delivering it to the reference bus from the actual generator bus

Adjustment in LBMPfor Losses 200+1+ 200-1- Ref Bus (1 MW) Gen2=600+1- Load2=800 Gen1=400+1+ Load1=200 West East LBMP =30-D1 LBMP =30+D2

Losses (cont.) • Delivering 1 MW from west increases system losses and therefore detracts from price • Deliver from east reduces system losses and is therefore more valuable, price higher • West to east transmission charge is ($30+D2) – (30-D1) = D1 + D2 • East-west transaction gets PAID D1 + D2 because it is counterflow • Charging at marginal rate results in over-collection which is paid back

Example of R/T LBMP in NY • Security-constrained dispatch runs every 5 min (actually dispatches generators!) • Incremental loss component calculated in real time • Predominant flow from west to east, north to south • Unit that is ramp-limited cannot determine LBMP • Spikes as LBMP shifts to next highest-priced unit

Example from March 2000 C/E i/f L.I. Cable NYC Load Pickup L.I. Cable Congestion Central/East Congestion Diff. Due to Losses

Two Settlement MarketDay-Ahead • Generators bid into day-ahead market (DAM) • Loads do forecast, bid percentage of load into DAM • Security-Constrained Unit Commitment commits generation, determines hourly prices, locks Gen & Load into forward contracts • This includes bilaterals and externals as well • SCUC optimizes for energy, reserves, and regulation, all of which are bid in • About 90-95% of market is conducted in day-ahead, half of that is bilateral

Two Settlement MarketReal-Time • Balancing Market takes place in real time using bids left over from DAM plus new hourly bids • R-T market more volatile because of operational events, inaccurate forecasts, and natural fluctuations in load • Net Real-time energy to be billed is total MW less amount contracted in DAM less amount due to bilaterals. • Can be + or – for generator or load

Summary • Locational price varies to account for effect of congestion and losses • Priced to encourage movement toward reduction of congestion and/or losses • Transmission charge for bilaterals difference between loc. Prices at sink, source • Comprised of congestion, losses components • Can be + or – • Congestion cost can be hedged up to limit of interface • Transactions can be scheduled “independent” of congested interfaces

Summary (cont.) • For Internal Transactions: • No Transmission Reservations needed • No Tags Needed • No TLR so do not need info on source & sink to do schedule or to operate • No ATC postings needed

Questions???

The Financial Model