While the Midwest now appears set on competitive bidding for the electricity commodity, taking from PJM such tried-and-true elements as locational marginal pricing, financial transmission rights,...
A hypothetical look at moneymakers across regions.
Given the high degree of ongoing electric market uncertainty, it can be challenging to get a reading on the current and future health of power markets. One way to gauge the health of the generation segment of the electric sector is to simulate the financial performance of a new gas-fired, combined-cycle unit. To perform this analysis, we start with the cost and performance characteristics of a new combined-cycle unit. Let us use these characteristics across all regions. We assume a 7,000 Btu/kWh heat rate, a $575/kW total project cost, a fixed operations and maintenance (O&M) cost of $15/kW-yr, and a variable O&M of $2/MWh. To achieve national coverage, we can examine 6 regional price points:
SP15 and MID-C in the West, ERCOT Houston, Cinergy (INDI) in the Mid-Continent region, TVA in the South, and NYC (NNYC) in the East. For these price points, we extract energy and capacity prices from the most recent Platts Research & Consulting (PR&C) Power Outlook Research Service forecast, and natural gas market prices from the PR&C GPCMDat natural gas data service.
Figure 1 shows the annual gross margins of the combined-cycle unit for each market from 2003 through 2015. The thick back line Figure 1 represents annual capital cost (assuming a 15 percent carrying charge) and fixed O&M expenditures, such that each regional line must surpass the horizontal back line to achieve before-tax profitability.
This analysis shows that new combined-cycle gross margins currently are well below annual capital and fixed O&M expenditures in all six regions. Profits are lowest at the TVA price point, and market returns are most robust in NNYC, driven by the region's perennial generation capacity deficit. Even here, though, before-tax profits are elusive when capital and fixed O&M costs are considered.
This analysis indicates that some power markets will begin to recover by 2006. Southern California (SP15) is the first market expected to recover, highlighting the need for new capacity by 2006. Combined-cycle returns in four of the six markets, however, are expected to remain well below the before-tax break-even level in 2006. Although average gas prices expected to drop to $4.50/MMBtu in these markets by 2006, sub-$30/MWh annual power prices, combined with undersized capacity payments as a result of the lingering capacity glut, translate into sub-par returns for a hypothetical new entrant.
This analysis indicates that gross margins in most regional markets are expected to be high enough to cover capital costs and fixed O&M expenditures by 2012-a timeframe that is of little comfort to generation asset owners today. By this time, national average annual power prices are expected to approach $40/MWh, and natural gas prices are expected to settle in the $5.00/MMBtu range.
This yields a positive spark spread for units with 8,000 Btu/kWh or better heat rate (since $5.00/MMBtu x 8,000 Btu/kWh - $40/MWh = 0). Energy revenue, combined with an average capacity payment of $80/kW-yr, yields positive before-tax profits for a hypothetical combined-cycle unit.
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