1. Mario S. DePillis Jr. USAEE Meeting, Pittsburgh, PA October 25-28, 2015

2. 2 RTOs in regions with divested generation have reformed their markets to stress payment for performance—firm generation RTOs in regions with vertically integrated utilities allow cost-of-service regulation to pay for long-term firm pipeline service—firm fuel Evidence here will show that divested generators have cost effective choices other than new pipelines New incentives should drive better investments Divestiture and Pipelines

3. 3 Perceived problem: “inadequate” pipeline capacity and investment Congested pipelines, high prices in both gas and electricity markets in 2013/14 Unregulated generators had not invested – Gas generators purchased cheaper “spot” pipeline capacity Perceived Problem

4. 4 Proposal in New England for states to purchase capacity to finance new pipelines and allocate the costs to retail electricity consumers Should public policy force investment in new pipeline for electric generation? Will financial penalties in pay-for- performance RTO market reforms work better? New England Debate

5. 5 Polar Vortex of Winter 2013/14 – Electric reliability strained in PJM – Extreme natural gas prices in New England – ERCOT prices at $5,000/MWh first time ever Market Reforms—Divested Generation Areas – Capacity market reform in North East – Reserve market reform for higher energy prices in ERCOT Trigger for Market Reforms

6. 6 ISO-New England and PJM – Capacity performance measured during system stress periods, low reserves, emergencies – Capacity performance defined as providing energy or reserve in real-time – New England penalty is $5,500/MWh plus opportunity costs. Total can be over $9,000/MWh ERCOT (no capacity market) – New reserve demand curve drives energy price to $9,000/MWh during system stress – New offer cap of $9,000/MWh Market Reforms: Incentive$

7. 7 Alternatives to New Pipelines

8. 8 Spot vs. Investment, 1-2 Average price = $1.59 NPV of cash flow net of demand charge is negative even at interest rate as low as 5% No risk neutral investor would buy long-term, sell short-term

9. 9 Long-term contract cost approximately $1.50 per Dth/day, 365 days, 24 hours Represents large adder to commodity price – One day use cost = $1.50 x 365 = $547.50 – 50% of days, 16 hour burn = $4.50/MMBTu adder Adder would make generator uncompetitive most of the time Can’t apply adder, can’t sell long-term excess in short-term at profit, no win Spot vs. Investment, 2-2

10. 10 Pipeline vs. Dual Fuel Source Levitan & Associates, Inc.: Eastern Interconnect Planning Collaborative

11. 11 LNG Imports Respond Source: FERC, National Energy Board

12. Conclusion 12 RTO market reforms, performance incentives, drive generators to choose best among alternatives for firm generation: – Spot gas – Dual fueling – LNG – New pipeline capacity RTO market reforms give generators the right performance incentives to make optimal investment decisions