The renewables risk genie is out of the bottle – and it isn't going back in
- September 21, 2016
- 1165 views
North American power markets are speeding through an evolution from the coal-centric past to a future reliant on natural gas and, increasingly, renewables for baseload power generation. The transformation has profound operational and commercial implications for electricity market participants.
Much of the change has been catalyzed by regulation at the federal, regional and state levels, particularly on emissions limits and renewable portfolio standards. These mandates have been largely answered by technology – cheaper and more efficient solar and wind generation, smart grid technologies that improve grid efficiency and reliability, and more efficient industrial and consumer appliances that reduce system load. Taken together the changes have had massive and ongoing impacts across the energy industry in the US, increasing complexity of operations and affecting the business models of many.
For power utilities, IPPs and traders, this new age energy market presents a number of challenges that have to be addressed quickly in order to operate profitably.
Renewables on the rise
Prior to 2000, new generation capacity in any year was a mix of coal, gas, hydro and nuclear. The mix of new generation has shifted dramatically since then, with gas, wind and solar forming the bulk of new capacity. Though coal still maintains a dominate position with as much as 70% of US total capacity, gas-fired plants are now operating at near parity with coal, while nuclear, wind, solar and hydro are adding about 30% on an average day.
"Utilities, IPPs and energy traders have to consider, analyse and forecast power supply and associated fuel costs much more rigorously as a baseline requirement."
In fact renewables now account for about 13% of the total US installed capacity. The majority of that is concentrated in California, Texas and the Southeast Power Pool (SPP) but the trend is for it to spread.
Given the highly variable nature of these energy sources, grid operators are challenged in managing grid stability as a significant portion of their capacity literally rises or falls with the weather – based on winds or during periods of cloud cover on any given day.
Take California’s grid operator, the CAISO, as an example of the complexity that renewables bring to daily business decisions.
California’s promotion of solar energy via incentives and tax credits has created a two-tiered solar infrastructure – utility-scale concentrating solar plants (CSP) and distributed roof-top solar. While the CSPs are operationally visible to the grid operator and are dispatchable, the roof top systems now common in the state are essentially invisible and unmeasurable on the system.
Without that visibility into a growing source of generation, the grid operator has difficulty predicting market demand, leading to significant locational marginal pricing (LMP) volatility and increased transmission congestion as the load changes unexpectedly during the day and throughout the year, particularly during the summer months when system loads are at their highest and the state’s wind generation tends to be at its lowest.
Texas too has experienced difficulties integrating the massive influx of renewables, as power from new wind generation farms in West Texas have occasionally swamped the states transmission lines and driven out other competing sources. With almost 18,000 MW in wind capacity at the end of 2015, wind accounted for 9% of Texas’s total generated power for the year. However, given the price advantage wind enjoys with production subsidies, wind farms have at times accounted for as much as 50 per cent of the total energy generated at any given time, creating negative prices in the real-time markets.
With a significant financial advantage, wind can continue to operate profitably in negative prices, forcing other sources, such as gas and coal, to quickly ramp down production or “pay to run”.
California is also seeing increasing periods of negative pricing as solar continues to invade that market region. In 2015, the CAISO saw about a dozen days of negative prices, reaching a low of ($23.87) MWH. In all these and other markets (like the Northwest region which is dominated by cheap-to-run hydro), the further integration of financially advantaged renewables such as wind and solar, despite their rather unpredictable nature, will result in increasingly frequent periods of negative pricing.
A new age with new challenges
With a rapidly changing generation mix, what were once largely one-dimensional markets, governed primarily by seasonal weather driven demand, have become increasingly multi-dimensional. Utilities, IPPs and energy traders have to consider, analyse and forecast power supply and associated fuel costs much more rigorously as a baseline requirement to ensure they remain profitable.
Any utility not facing up to the rapid changes and growing uncertainties by re-thinking their risk management processes are needlessly adding to a risk profile that’s intensifying across the sector. You can see that companies are taking greater care – trading volumes are declining and day-to-day activities have become more operationally centric. Traders are reducing activity to adjust to these new conditions, but even the power and other energy trades that are occurring need more analysis, investigation and due diligence to execute.
Volatility and constant risk mitigation are the new normal
For energy traders and utilities, profitability in this complex and evolving market requires a full and complete picture of assets, operations, positions and risk exposures. Too many utilities are still labouring under a painful burden of data management challenges, including lack of automation, multiple disparate systems and data formats. It prevents them from having a clear, transparent view of data to forecast and respond to changing market conditions, comply with regulation and develop effective strategies.
Utility companies need to be able to make sense of a multitude of data sources, including market data and bespoke or vendor supplied generation optimization, load forecasting, and transmission scheduling solutions. Only with those sorts of insights available when key trading decisions are being taken can valuations and control in trading, tracking and risk management financial positions be calculated with confidence.
I would urge power utilities and IPPs to take a hard look at their strategy for hedging risk and complying with regulations -- now. Make an inventory of your most used resource analytics, but also consult traders, risk managers and planners to understand what they need to be successful.
It’s absolutely essential if utilities are going to sustain or return to growth and profitability.