Presentation on theme: "Hedging Energy in the New Marketplace Scott E. Thompson Portfolio Director SPP/ERCOT."— Presentation transcript:
Hedging Energy in the New Marketplace Scott E. Thompson Portfolio Director SPP/ERCOT
To Regulate? or Not to Regulate? That is the Question!
Regulated Market Characteristics Cost of Service Studies Rate of Return Regulation Guaranteed Margin Annual Fuel Adjustment Clause Long-term Contracts (20+ years) Stable Rates Limited Concern of Counterparty Contracts & Credit Suppressed Volatility VERY LITTLE RISK
Transition to un-Regulated Markets Federal Deregulation is moving at a faster pace than State Deregulation, which limits the tools available to many Utility Energy Risk Managers compared to un-regulated marketing companies.
Energy Market Evolution Un-Regulated or Competitive Markets do not behave like Regulated Markets. Buyers & Sellers Beware!
Un-Regulated Market Characteristics Market Pricing vs. Cost of Service Pricing Uncertain Margins vs. Guaranteed Margins Competition vs. Guaranteed Margin Monthly - Fuel Adjustment Clauses Shorter Term (< 5 year) Contracts Less Predicable Rates Significant Contracts & Credit Severe Price Volatility Specialized Risk Management and Trading Skills VERY RISKY BUSINESS
To Hedge or Not to Hedge? Most Utility Managers would like to hedge to reduce some of the risks on the previous slide. Many Utility Managers are not familiar enough with the hedging alternatives to fully explain them to the regulators or management, causing state regulators to move more slowly. Many of the hedging tools require infrastructure upgrades or education (contracts, credit, accounting and analytical) Will current regulation allow the utility to effectively hedge and is there a defined process?
To Hedge or Not to Hedge? (cont.) Can the LDC or Power Company pass the net effect of the hedge through to their rates? PGA, GCR, PCA …….Sometimes Some state regulators do not allow any hedge losses to be passed through to customers. no incentive to implement a hedging program Some states allow physical losses to be passed through but not financial losses. Incentive to hedge physically only Financial Hedging in some cases is much more efficient than Physical Hedging (example)
Hedging Example 200 MW Natural Gas Fired Peaking Plant (CT) is expected to run 1000 hours this summer to produce electricity for a utility. 200 MW x (1000 hours) x 10 heat rate 2,000,000 DTH or 2 BCF of Natural Gas Should you Purchase Fixed Price Physical Gas from a producer who will to deliver the gas to the plant or Purchase NYMEX Financial Contracts as Hedge? Can you pass through Financial Gains/Losses through the Fuel Cost Adjustment (FCA)?
Hedging Example (cont.) Purchasing Physical Gas: Removes Delivery Risk Removes Price Risk (Reduces Volatility) Adds Credit & Contract Risk Limits Ability to change Positions (Liquidity Risk) Requires un used gas to be sold (non-ratable) Purchasing NYMEX Financial Gas: Removes Price Risk (Reduces Volatility) Cash Margining to NYMEX Allows for Purchasing Physical gas only on days unit runs, rather than baseload (everyday), as gas units are not usually run around the clock baseload.
Hedging Example (cont.) For those that can’t pass through Financial Hedge results, they are forced to hedge with Physical gas via a marketing company with a structured product that includes a NYMEX derivative for (Fixed Price) and a physical delivery component with a “Buy Back Premium” for unused volumes. This “Buy Back Premium” causes a Financial Hedge to usually be more efficient and a better hedge. The marketing companies thrive on providing these types services that bridge the gap between regulation and de- regulation.
Hedging Example Summary Some hedge transactions are restricted from selling –Coops are subject to the 85/15 tax laws Liquidity for physical gas at the plant may be limited and therefore utility may have to pay a “buy-back premium” Hedging with NYMEX Futures contracts can be more efficient –If one can pass derivative gains/losses thru on the fuel clause? Typically gas fired generation is not a baseload plant and is dispatched non-uniformly which could add costs to hedging with physical gas. –Gas Fired CTs usually don’t run on weekends or off-peak periods resulting in volumetric risks
To Hedge or Not to Hedge…. What is your Goal? YES Reduce Volatility Predictable Price Avoid Price Spikes Favorable Regulatory Predictable Cash Flow Trained Management Developed Infrastructure Proper Controls NO Achieve Lowest Price Float with Market Price Spikes Unfavorable Regulatory Unpredictable Cash Flow Not Trained Lack of Infrastructure No Controls
Hedging the Spark-Spread…. Example? Hedge Natural Gas for July 2005 Plant Characteristics: –Purchase 225,000 Dt @ $7.00/Dt –Combined cycle gas –On-peak hours (5x16) –Heart Rate 7.0 Dt/MWh 32,000 MWh Power is $53/MWh
Hedging the Spark-Spread…. Example? (cont.) Cost to run plant for July ($7 x 7) = $49/MWh Cost to Purchase Power $53/MWh Savings by running gas-unit $ 4/MWh Total Saving (32,000 x 4 = $128,000) POSITIVE Spark Spread BUY Gas, not Power
Hedging the Spark-Spread…. Example? (cont.) Gas Price $8.00, Power Price $53 Cost to run plant for July ($8 x 7) = $56/MWh Cost to Purchase Power $53/MWh Loss by running gas-unit $ 3/MWh Total Loss (32,000 x 3 = $96,000) NEGATIVE Spark Spread BUY Power, not Gas
Hedging the Spark-Spread…. Example? (cont.) Gas Price $8.00, Power Price $53 Sell Gas ($8 - $7) x 225,000 Dt= $225,000 Buy Power ($53 - $49) x 32,000 = Savings= $ 97,000 Gas Unit now becomes available for additional transaction opportunities
Summary To Hedge or Not to Hedge? A decision NOT to hedge will place the buyer with much more risk in the new marketplace A decision to hedge must be made carefully so one fully understands what risks are going away and what new risks they are obtaining. Develop a hedge plan which includes identifying and measuring risk within an appropriate infrastructure of contracts, credit, accounting & regulatory constraints. Educate management, staff, board and regulatory staff of goals of the hedge plan in detailed format (prior to implementation).
So Why Change from the Traditional Transmission Market Structure? Fair & Open Access to a constrained transmission system –Eliminate manipulation & abuse of transmission use –Effective FERC oversight & regulation More efficient use of generation & transmission resources Create a structure that yields delivered power prices based on actual flow versus contract path Create broader access to competitive power markets
1.$20/MWh + 2+3+2+2 = $29.0/MWh 2.$25/MWh + 2.5 + 2= $29.5/MWh 3.$28/MWh + 2= $30.0/MWh Which alternative should the Buyer Purchase and why?
Example: Where Do you Buy? $20/MWh + 2+3+2+2 = $29.0/MWh Least expensive but far away, transmission may get a TLR $25/MWh + 2.5 + 2= $29.5/MWh Closer, only 2 transmission paths but $0.50/MWh more. $28/MWh + 2= $30.0/MWh Purchase from neighbor utility with only one transmission tag.
Natural Gas Market Update To be added if necessary?