BC Hydro Price Forecast

Transcription

1 BC Hydro Price Forecast Natural Gas and Electricity Price Forecast Scenarios Quick Links: Introduction Gas Price Scenarios Electricity Price Forecast Components Electricity Price Scenarios 1. Introduction Uncertainty in gas and electricity wholesale price forecasting is assessed through scenario analysis. BC Hydro has selected a range of natural gas and corresponding electricity prices to represent a wide range of possible outcomes. The gas price forecasts were selected using three criteria: Information is derived from reputable sources; Forecast information is public or can be made public; and Forecasts represent a range of possible futures. Three main gas price forecasts are used: Confer LRMC, EIA Reference, and High Gas. For each gas price forecast, two corresponding electricity price forecasts are developed. One reflects a full capital recovery scenario and the other reflects a 25% capital recovery scenario. The capital cost recovery is based on a 250 MW F-series CCGT. These forecasts are used for all long term applications such as the Integrated Energy Plan, the Vancouver Island Call for Tenders, other business cases and project valuations. The Scenario Average is the arithmetic average of the previously described forecasts. For the gas price forecast, this is the average of the three main forecasts: Confer LRMC, EIA Reference, and High Gas. For the electricity price forecast, this is the average of the three full capital recovery scenarios and the three 25% capital recovery scenarios. The forecast is typically used to track changes to the scenarios from one forecast to the next. Market Forwards through March 2009 are provided by Powerex. These are quoted and distributed on a monthly basis. If a current forward quote is required then Powerex should be contacted since this forecast is only issued semi-annually. The market forwards are used for all short-term applications such as forecasting trade income and Cost of Energy reporting. Each scenario is presented with a monthly gas price resolution and monthly electricity prices for Heavy Load Hours (HLH) and Light Load Hours (LLH). Table 1 and 2 summarize the components of the forecasts. March 31, 2005 P A G E 1

2 Table 1 Natural Gas Price Forecasts Gas Price Forecast Update Frequency Application* Market Forwards Monthly Short Term Scenario Average Annually Confer - LRMC Annually Current Month to 2007 Time Frame Market quote from Powerex 2007 to March 2009 March 2009 to 2025 Average of Confer, EIA, and High Gas Annual North American outlook for long run cost of gas EIA - Reference Case Annually Base case from Annual Energy Outlook report Greater of average forward strip for last three months and highest High Gas Annually historical rolling 12 month rolling average spot price escalated at 1% real per year *Short-term applications include, for example, revenue forecasting. *Long-term applications include IEP, VI CFT, business cases extending beyond five years (approximate). Table 2 Electricity Price Forecasts Electricity Price Forecast Update Frequency Application* Market Forwards Monthly Short Term Current Month to 2007 Time Frame Market quote from Powerex 2007 to March 2009 March 2009 to 2025 Scenario Average Average of six scenarios (Confer, EIA, and High Gas) Confer - LRMC: Full Capital Recovery EIA - Reference Case: Full Capital Recovery MARKETSYM modelled prices High Gas: Full Capital Recovery Confer - LRMC: 25% Capital Recovery EIA - Reference Case: 25% Capital Recovery 25% capital recovery Minimum of MARKETSYM modelled price and CCGT UEC with High Gas: 25% Capital Recovery *Short-term applications include, for example, revenue forecasting. *Long-term applications include IEP, VI CFT, business cases extending beyond five years (approximate). 2. Natural Gas Price Scenarios The BC Hydro long-term price forecasting process employs a multiple scenariobased approach to price forecasting. BC Hydro has selected three main gas price scenarios to represent a broad range of possible future energy market outcomes. Table 3 summarizes the scenarios: March 31, 2005 P A G E 2

3 Table 3 Natural Gas Price Scenarios Scenario Confer Consultant Study of North American Gas Market Energy Information Administration (EIA) Reference Case High Gas BC Hydro Developed Date Issued January 2005 January 2005 March 2005 Description Relatively optimistic view of ability of technology to keep ahead of demand leads to relatively low price forecast. Strong demand growth and cost of production increase with cumulative consumption. Prices increase at a Environmental Situation Assumptions Technological Innovation Assumptions Moderate: Not major focus. Strong enough to keep prices low. relatively high rate. Moderate. Considered in detail. Moderate specification of technological parameters. Continued high prices into the future. Captures the possibility that prices remain high or fluctuate around a high average. N/A N/A Two third-party gas price forecasts are used: the long-run cost projection from the U.S. Energy Information Administration s (EIA) Reference Case; and industrial consultant, Confer Consulting. In addition, High Gas is an internally developed forecast that assumes a continued high gas prices into the future. These forecasts provide a wide but plausible range of possible outcomes. The scenarios are described in detail below: 2.1. Energy Information Agency (Sumas levelized 2005 US$3.90/MMBtu) The Energy Information Administration ( EIA ) of the U.S. Department of Energy annually produces a complete energy forecast, the latest one being reported in Annual Energy Outlook 2005, published in January EIA s forecast is for several forms of energy and is linked to an economic outlook that specifies the rate of economic and population growth. The forecast is produced using substantial modeling resources. Numerical projections are generated by the National Energy Modeling System ( NEMS ). Interactions between the different energy categories are estimated; prices and quantities are forecast simultaneously for all important energy categories including oil, coal, natural gas, electricity and green energy. The impact of the macroeconomic environment and of government regulation and policy is considered. For long run natural gas prices, a key issue is whether technology and exploration will be able to keep pace with growing demand by finding sufficient supplies and developing them at an economic cost. On this issue EIA's Reference Case position is that exploration and technology will have difficulty keeping up and that, as a consequence, real gas prices for natural gas will rise steadily in the long run. The EIA Reference Case has U.S. real GDP growing at a rate of 3.1% per year for the period Natural gas consumption, for the U.S. in the Reference Case, increases at 1.5% per year from 22 TCF per year in 2005 to 31.0 TCF per year in % of demand growth is accounted for by increasing use for electric generation and industrial applications. March 31, 2005 P A G E 3

4 Additional supply expected to come from Northern pipeline projects and LNG imports. Domestic production reaches 21.8 TCF by 2025, which is significantly lower than projected in the 2004 forecast. Lower because of slower reserve growth, fewer new discoveries, and higher exploration and development costs Confer (Sumas levelized 2005 US$3.36/MMBtu) Confer Consulting Ltd. is a Calgary based consulting firm, which has provided services to BC Hydro since Confer s forecast is the lowest natural gas price scenario among the base cases of the various price outlooks. The basic analysis performed by Confer is to examine the underlying factors that drive the demand for natural gas in North America, and then assess the supply potential to meet demand at economic prices. The potential supply is assessed by analyses of the long-run marginal cost ( LRMC ) of new gas supply; that is, the full cost of investing in and operating new gas supply through its economic life. In other words, the forecast does not account for a scarcity premium above the cost of supply. Several supply sources and technologies are assessed. Strong demand growth expectations for natural gas cause the need to examine the long-run marginal costs of supply from remote areas, such as the Mackenzie Delta; nonconventional technology, such as coalbed methane; and imports of LNG. The lower level of Confer's price forecast as compared with EIA is due to Confer's view that demand in North American for natural gas will be lower than forecast by the EIA and that improvements in technology will continue and lower the cost of new gas supply below that forecast by the EIA. Prices reflect the high end of supply cost for LNG. The forecast assumes good supply execution and that North America will be the preferred market for LNG High Gas (Sumas levelized 2005 US$6.17/MMBtu) This scenario is not based on any model or analytics. This scenario assumes that the current high prices priced environment persists. High Gas is an internal forecast that is developed as follows: 1. Average last 3 months of daily forward strip quotes to create a single forward strip quote that extends to the end of three calendar years. Average the monthly products from the new quote into calendar averages. Daily forward strips for the period December 2004 through February 2005 were used for this forecast to produce an average forward price for 2005 to Determine highest rolling 12 month historical spot price and escalate from the current year at 1% real. Currently, the highest period daily spot prices on record is from 13Mar04 to 14Mar05. This period yields a price of 6.01 USD/MMBtu, which forms the base price for For each of the next three calendar years, select the highest price from step 1 and step 2 to produce the High Gas scenario. Beyond the third year, use the greater of the third year price from step 1 and the price from step 2. This scenario is intended to form an upper bound for the natural gas price forecasts. March 31, 2005 P A G E 4

5 3. Description of Electricity Price Forecast Components 3.1. Short Term: Market Forwards Short Term: Current Month to March 2009 (five fiscal years) Applications: examples include revenue forecasts and scheduling outages Description: Electricity prices at MidC consist of market forwards provided by Powerex. Prices at BC - US border are calculated with a formula that incorporates MidC forwards, the R bch forecast, and a projection of tie-line constraints. Quotes are provided monthly. Thus, since this forecast is only issued semi-annually, current forwards quotes should be obtained directly from Powerex : MARKETSYM Modelled Prices and CCGT UEC : 2007 to 2025 Applications: examples include Integrated Electricity Plan and Vancouver Island Call for Tenders (VI CFT) Description of MARKETSYM Modelled Prices Use of the modelled prices in the scenarios is described in Section 1. The electricity prices at the B.C.-U.S. border are based on a forecast of supply and demand for electricity and the cost drivers expected to prevail. They are modelled under a computer simulation of the hourly supply-demand balance for the Western Electricity Coordinating Council (WECC) regional market, which includes the Western U.S. states, B.C. and Alberta. BC Hydro uses the MARKETSYM Energy Services simulation software, using certain inputs based on BC Hydro s knowledge and system, which, among other modelling details outlined below, accounts for transmission costs and limitations. The dispatch cost of the marginal resource at the point where supply and demand are in equilibrium determines the market price for that hour. Monthly and yearly average prices are obtained by aggregating the computed hourly prices. Additional modelling details include: Hourly simulation of 20+ WECC areas; Expected WECC load growth (2%); Expected hourly load shape (estimated from historical hourly load data from 1993 to 2002); Expected BC Hydro electricity load forecast and resource plan; Forecast natural gas prices; Average hydrological conditions throughout WECC; Existing WECC resource base less expected retirements plus expected additions; Generic resources added to maintain reserve margin targets for WECC subregions; Expected inflation; and Expected long-term transmission limits, losses and costs. Figure 1 provides a schematic of the WECC market s transmission configuration. March 31, 2005 P A G E 5

6 Figure 1 - WECC Transmission Area Configuration ALBERTA CENT-N BC ALBERTA SOUT H MONTANA PNW IDAHO WYOMING COB CNORTH N NEVADA CO EAST CZP-26 UTAH CO WEST LADW P CSCE CSDGE S NEVADA IID PALO VERD E ARIZONA NEW MEXICO NBAJA Description of F-Series CCGT Unit Energy Cost (UEC) Model Use of the UEC model in the scenarios is described in Section 1. The prices are set equal to the estimated unit cost of the most economical resource addition, currently a natural gas-fired combined cycle gas turbine (CCGT). Capital and operating costs are based primarily on third party sources. Key costing details (all costs in real 2005 dollars) include: Greenfield project (i.e., a new project, not a re-powering of an existing facility) located in the Lower Mainland; 262 MW (average over life) F-series Combined Cycle Gas Turbine (CCGT); Capital Cost = U.S. $250 million; Variable operating and maintenance cost = 3.32 U.S.$/MWh; Fixed operating and maintenance cost = 1.95 U.S.$/MWh; Forecast natural gas prices; Fuel tax = 7%; Heat Rate = 6,863 MMBtu/GWh or 7,240 GJ/GWh HHV (higher heating value), average over life; Unit average availability = 91.3%; and Project life = 25 years. March 31, 2005 P A G E 6

7 4. Electricity Price Scenarios 4.1 General Two electricity price forecasts correspond to each of the three main gas price forecasts described in Section 2: a 100% capital recovery scenario and a 25% capital recovery scenario. The 100% capital recovery scenario represents the expected price forecast. The methodology for generating prices is described in Section 3. The following section describes the 25% capital recovery scenarios and the methodology for calculating prices. Figure 2 illustrates how the gas prices are converting to electricity prices % Capital Recovery Scenarios In these scenarios, the relationship between gas and electricity prices is based on a market heat rate that is lower than the other forecasts. The market heat rate is the simple ratio between electricity and gas prices, either actual or forecast. This is distinct from a generation plant heat rate, which is an indication of the efficiency of conversion of a hydrocarbon fuel into electrical energy. The purpose of these scenarios is to factor in the potential for unforeseen improvements in technology or extraordinary market conditions that might stress the expected relationship between market gas and electricity prices. This scenario embodies the following possible future outcomes: New, more efficient generation technologies; Retirements of older plants; Market prices not reflecting an all-in fully recovered cost of new generation; Regulatory/political market events (such as price caps); Effects of generation cross-subsidies and capacity charges; and Sustained overbuilds in generation. The electricity prices are calculated as follows for the period 2007 to 2025: the minimum of the MARKETSYM generated price and the unit energy cost of F-series CCGT with 25% capital recovery. This is done to recognize that markets are currently oversupplied. In the first few years, generators may be covering less than 25% of their capital charges. This methodology provides a lower market heat rate than the expected scenarios, and it provides a fundamentally different gas-to-electricity price relationship. March 31, 2005 P A G E 7

8 Figure 2 Conversion of Natural Gas to Electricity Prices 3 Gas Price Forecasts Confer Consulting (low) Energy Information Administration (medium) High Gas Translation BC Hydro Modeling BC Years Hydro : Modeling Henwood Model (Std. Assumptions) Years Year MARKETSYM 2013 and beyond: Model Standard LRMC based Assumptions CCGT 100% Capital Cost Recovery BC Hydro Modeling BC Years Hydro : Modeling Lower Price of Henwood Model (Std. Years Assumptions) or 25% Capital Lower Cost Price Recovery of MARKETSYM of a CCGT Model (Std. Assumptions) and 25% Year Capital 2013 Cost and Recovery beyond: of a LRMC based CCGTon CCGT 25% Capital Cost Recovery Electricity Price Forecast 1 Full Recovery X 3 Forecasts Forecast 2 Partial Recovery March 31, 2005 P A G E 8