LDC Procurement and Hedging

1. LDC Procurement and Hedging American Gas Association Energy Market Regulation Conference Steve Levine Frank Graves October 9, 2014

2. Introduction • State of the markets • Relatively calm period for U.S. gas markets shaken somewhat by Polar Vortex last winter • Polar Vortex highlighted gas-electric interactions/competition for pipeline capacity • Polar Vortex may not repeat, but still potential for local mismatches between supply and deliverability • Implications for LDC procurement and risk management • Is risk management dead or alive in today’s gas markets? • Low prices and low volatility  less risk management, or a good time to lengthen hedges? • Should gas LDCs revise practices towards value versus volume risk management? • Is liquidity a new problem, requiring physical solutions?

3. Prices and Volatility Have Declined Since 2009

4. Implied volatilities and futures over time Average 12-Month Forward Implied Volatility and Futures Implied Volatility as of May’12 Implied Volatility as of Oct’13 • Both volatility and seasonality have also declined in the past couple of years • There has been a lagged, usually positive correlation between future prices and volatility

5. Are Electric and Gas Futures Myopic? • Recent gas futures reflect a nearly flat real outlook for the rest of this decade, suggesting that demand-side pressures from coal plant retirements, LNG exports and industrial demand growth are dominated by expected supply-side optimism. Henry Hub Futures (real $/MMBtu) • However, many fundamental forecasts (e.g., AEO2014) show price bumps around 2016-18 and 2020-23.

6. Coal Plant Retirement Impact on Gas Demand • Retirement of 59 – 77 GW of coal capacity by 2016 could result in 3.3-6.1 Bcf/d increase in gas demand, depending on share of gas in marginal fuel mix. (More possible if 111(d) implemented) • Increased use of gas by the existing gas-fired generation fleet (376 GW) would result in 5-8% increase in fleet-wide capacity factor. Source: “Coal Plant Retirements and Market Impacts,” Metin Celebi, The Brattle Group, February 5, 2014.

7. About 42 Bcf/d of Proposed U.S. LNG Export Capacity • Most (35 Bcf/d) proposed in the Gulf Coast • 1.6 Bcf/d East Coast, 2.5 Bcf/d West Coast, 2.5 Bcf/d project in Alaska • One plant under construction (Sabine Pass); another (Cameron LNG) has made its final investment decision • 8 (10.6 Bcf/d) with DOE approval for exports to non-FTA countries • Sabine Pass (2.2 Bcf/d), Freeport (1.8 Bcf/d), Lake Charles (2.0 Bcf/d), Cameron (1.7 Bcf/d), Cove Point (0.8 Bcf/d), Jordan Cove (0.8 Bcf/d), Oregon LNG (1.3 Bcf/d), and Carib Energy (0.1 Bcf/d). • 3 (5.7 Bcf/d) with FERC approval • Sabine Pass (2.2 Bcf/d), Freeport (1.8 Bcf/d), and Cameron (1.7 Bcf/d)

8. Pipeline Projects from the Marcellus • Shale offtake projects may not serve the areas that were most affected by the Polar Vortex 1.0 Bcf/d to MI 0.18 Bcf/d in PA with access to TGP and TETCO Marcellus/Utica Production Growth By 2019 ~+5 Bcf/d 1.18 Bcf/d to IN 0.44 Bcf/d to KY 2.5 Bcf/d to Midcontinent 1.25 Bcf/d to South/Gulf Coast 2.15 Bcf/d to South/Gulf Coast

9. Basis and Delivery Point Risks:Polar Vortex 2013/2014 Natural Gas Prices • PV showed that some gas procurement locations (citygates) carry more risks than others (basins) . • Black swan or recurring prospect? • Low liquidity plus local competition with electric peaking • Potential for unhedged expected volumes plus cold weather unplanned volumes • At very high local prices • Physical procurement considerations include: • How much pipeline capacity from which basins? • Diversity of receipt points? • Market area storage capacity? • More interruptible demand? How can gas buyers manage risks around these uncertainties?

10. Key risk management insights to establish with regulators and customer groups • Volume versus price risk management • Proper definitions (hence expectations) of risk and risk management; distinction between risk and “regret” • Criteria and tools for setting goals and monitoring activities in risk reduction • No “one size fits all” for risk reduction; need customer engagement to determine appropriate risk management goals • Monte Carlo methods, VaR, TEVar and other metrics of net open position • Standards for reviewing prudence of risk management efforts • Distinction between risk management and least cost planning • Hazards of ex post reviews of hedge performance • Reviewing adherence to risk control protocols

11. Volume Hedging vs. Price Risk Management Many gas LDCs tend to manage risk with storage and financial forwards/swaps for a fixed volume (35-75+%) of expected needs • This reduces risk, roughly in proportion to target volume hedged, but actual amount of risk reduced or remaining is not measured or considered • No explicit consideration of shifts in market forward prices or volatility • Nor consideration of rare event price spikes • No basis for changing extent, type, or timing of hedge positions • Usually very mechanical • Or worse, accelerated or decelerated when market prices move down/up relative to past history (which is likely to increase risk) • Risk of imprudence if approach seems outdated, passive, or naïve after adverse events Best defense is to develop forward-looking risk metrics of exposure of total future costs to current net open position • And to educate regulators and customer groups on how to evaluate risk management outcomes.

12. Risk versus regret • Risk is ex ante exposure to future volatility (unexpected potential variability) – eliminated by forward purchases at fixed or capped prices. • Regret is ex post disappointment if a hedge turns out to be more costly than not hedging would have been. • Not quite a fair complaint: insurance has value even if not used • Regret is a valid concern, but: • Regret reduction is generally antagonistic to risk reduction • The more ex ante certainty, (risk reduction) the greater the chance of ex post disappointment (regret), and vice versa Alternative hedging strategies can shift the weight between risk and regret exposure – subject to customer preferences. 100% Zone of Indifference Satisfied Cumulative Probability 50% Regret Hedge Price Cost

13. Capturing risk information in market prices • Market volatility can be estimated from historical patterns or inferred from the price of traded options (implied volatility) • Monte Carlo simulation then used to generate future possible price distributions consistent with current forward prices and their volatility • Volume uncertainty, basis risk, and rare extreme events can also be added to the mix of risk drivers Spot Prices and Change in Forward Curves Conditional Probability Distributions

14. Specifying Goals for Risk Management • Developing an effective hedging strategy requires four types of information based on consumer preferences: • Risk tolerance for high cost extremes (how high is too high, too often?) • Regret avoidance (do you want the low end open?) • Zone of indifference (how wide or narrow should the middle section be for confidence about expected costs) • Time frame (how far ahead do you want these assurances?) P95 Zone of Indifference Regret

15. Comparing alternative hedging strategies • The range of potential delivery period costs are calculated by applying simulated market outcomes to the utility’s net open position under a given hedging strategy. Value at Risk (VaR) Volatility Term Structure DCA +$0.9 Spot +$1.9 Options +$1.1 -σ=-26% +σ=26% Forward Curve and Confidence Bands ― All Spot ― All DCA ― All Options Mean = $4 (under all strategies) Spot –$1.5 Options –$1.4 DCA –$0.8 Regret

16. Conclusions and Recommendations • Gas utilities should study their 2-4 year (mid-term) vulnerability to future Polar Vortex like events • Looking closely at regional deliverability, electric competition, depth and diversity of suppliers, and pace of near-term supply versus demand shifts. • If liquidity a big factor, physical solutions may be better than financial ones, e.g. local storage • Shift risk management practices towards simulation of uncertainty in total future costs or typical bill due to uncertainty in net open position over time • Puts the focus of performance review on whether the expected risk was controlled, not on the luck of hedges ending up in or out of the money. • Provides an economic basis for modifying hedging strategy over time in response to volatility increases/decreases • Likely to require educational workshops with staff and key intervenor groups to agree on risk goals, approaches, and strategy

17. Presenters Mr. Steve LevinePhone:+1.617.864.7900 PrincipalEmail:Steve.Levine@brattle.com Mr. Levinespecializes in energy and regulatory economics. He has over 20 years of experience as a consultant providing advice, expert testimony, and litigation support on such matters as the competitiveness of natural gas markets, damage claims in energy contract pricing disputes, the conduct of gas market participants, gas pipeline business risk, and the reasonableness of utility contracting and risk management decisions. He also has expertise in financial modeling, pipeline ratemaking, and utility asset valuation. • Mr. Frank Graves Phone: +1.617.864.7900 • Principal Email:Frank.Graves@brattle.com • Mr. Graveshas advised gas and electric utilities for over 30 years on such matters as system capacity expansion, network modeling, procurement and hedging, investment and contract prudence, service design and pricing, financial performance evaluation, and asset and contract valuation. He frequently testifies in regulatory venues in regard to prudence, ratemaking, and impacts of new or proposed regulatory policies on the market and individual companies, as well as in state and federal courts in regard to contract disputes and securities fraud.

18. About Brattle • The Brattle Group provides consulting and expert testimony in economics, finance, and regulation to corporations, law firms, and governments around the world. About half of our work is in energy and utility-related planning, regulatory and litigation support. NORTH AMERICA Washington, DC San Francisco New York Cambridge EUROPE Rome Madrid London