When it comes to power production, the U.S. has at least 51 separate revenue policies. Revenue streams can be dramatically different from state to state. Texas is alone in having two policies, depending where the power producer's assets are located.
Generally, independent power producers such as Calpine (CPN), GenOn Energy (GEN) and Dynegy (DYN) seek to earn revenues for their power production, capacity and ancillary services. The largest variable among the regions is compensation for capacity.
Capacity is the ability to produce. Investors should see compensation for capacity as rent. Grid operators need to assure there will always be reliable sources of power. To assure reliability, operators keep a certain percentage of their fleet in reserve. If power plant owners find their assets on the sidelines, they will exit the market unless they are paid rent. Capacity payments keep them in the game and assure system reliability.
In regulated states where large integrated utilities such as Dominion (D), Duke Energy (DUK), Southern (SO), and NextEra Energy (NEE) operate, all payment streams are built into the states' rate bases. Power plants are built only after the state and the utility agree there is a long-term need for a particular resource. The process is called integrated resource planning and it covers time frames measured in terms of decades.
However, in deregulated and restructured states, capacity compensation is a different and often complex story. Look no further than Texas to understand the challenge.
Texas will soon have three geographically separate grid operators, each using completely different rules. The Electric Reliability Council of Texas (ERCOT) currently offers no compensation for capacity, which may explain why no new capacity has entered this market for last several years. Southwest Power Pool's (SPP) market is under development, but it will have a capacity market while also managing rate-based assets. The Midwest ISO (MISO) will have its Texas system operating by December 2013 and it will have a different capacity market.
PJM Interconnection is the granddaddy of all grid operators. An early adopter, PJM has a large service area and has developed a sophisticated market-based system for energy, capacity and ancillary services. It calls its capacity markets the "Reliability Pricing Model" or RPM.
According to its website, PJM's long-term approach, in contrast to other grids' short-term markets, includes incentives designed to stimulate investment both in maintaining existing generation and in encouraging the development of new sources of capacity -- resources that include not just generating plants, but demand response and transmission facilities.
PJM procures capacity through a competitive auction. The auction is regionalized to create locational pricing to reflect limitations on transmission systems and to account for differing needs for capacity in various areas.
PJM just completed its capacity auction for June 1, 2015 to May 31, 2016. The auction secured record amounts of new generation by clearing 164,561.2 megawatts of capacity. The reserve margin for the entire system is a healthy 20.2%.
An unprecedented amount of planned generation retirements (more than 14,000 MW) driven largely by new regulations from the Environmental Protection Agency drove prices higher than last year's auction.
Because of transmission constraints, capacity prices in two areas are higher than the rest of the system. The system price for annual resources is $136.00 per megawatt-day. A typical 1,000-megawatt power plant should expect almost $50 million of capacity payment revenues for the year. Atypical plants will see less. Solar should expect a 60% discount and wind should expect an 80% discount.
However, the price is not uniform across PJM's service area of 13 states and the District of Columbia. PJM's northeastern region area has price for annual resources at $167.46 per megawatt-day. This includes Pepco Holdings' POM service territory, Exelon's (EXC) eastern territories, FirstEnergy's (FE) eastern territories, PPL's (PPL) eastern territories, Public Service Enterprise Group's (PEG) territory and Consolidated Edison's (ED) Rockland Electric Company subsidiary.
In northern Ohio, the price First Energy can expect is a whopping $357.00 per megawatt-day. To provide readers perspective, a 1,000-megawatt nuclear or coal-fired power plant operating in northern Ohio would earn more than $130 million a year in capacity payments before a watt of energy is produced. The same plant operating in New Jersey would earn slightly more than $61 million a year. In Texas' ERCOT system, it would be zero.
North America has 10 regional markets or grids click here to see today's map. While the Federal Energy Regulatory Commission approves regional markets, designing those markets is largely up to each grid. When analyzing a generator's earnings, carefully consider which grid they use. It can make a big difference in your analysis.