Electric Utilities Face Expanded Responsibilities, Opportunities

By Mike Hormell and Barbara Sands, PA Consulting Group

The year 2008 redefined uncertainty.

  • Oil prices set historic highs above $140 per barrel, dropped $100 by year-end and declined into 2009.
  • Appalachian coal prices also set record prices, peaking above $120 per ton and declining 45 percent by year end.
  • Natural gas prices exceeded $12 per thousand thousand British thermal units (mmbtu) before falling below $6 in December.
  • Staple food prices soared more than 80 percent above prices three years previous and sparked riots across the globe.
  • Demand for steel drove prices above $1,000 per metric ton and then dropped.
  • Capital costs were well above historic levels by midyear, then financing sources virtually evaporated.
  • The Environmental Protection Agency’s proposed cap-and-trade program for mercury was rejected for command and control.
  • Sixty-six coal plants totaling about 46 GW were cancelled in 2007 and 2008.
  • Utilities OK’d payment arrangements as housing prices plummeted and unemployment skyrocketed with 2.7 million jobs lost.
  • State and regional governments passed new and expanded existing renewable portfolio standards (RPS) while a federal renewable energy standard became a presidential priority.
  • Regional greenhouse gas (GHG)-reduction programs gained state, regional and local participation, and federal political changes likely will drive more serious action sooner than later.
  • Energy efficiency (EE), previously a large element of utility business cases’ analyses, has become part of the national conversation about economic recovery.

 

Economic recovery debates gravitated toward the size, shape and timing of a government-induced stimulus package that recognizes energy as a sector ripe for increased spending.

Today’s power generation sector is in the crosshairs of controversy, driven by an evolving mix of fact, perception and concern about climate change. As policymakers attempt to separate scientific fact from fiction, regulatory changes will heighten market uncertainty, challenge traditional business practices and create new opportunities.

Given the uncertainty over future regulation and incentives in the market, what is the most prudent way to meet the needs of customers, regulators and shareholders?

Utilities around the world are confronted with and challenged by divergent sets of constraints and opportunities. The clarity is greatest, however, in operating environments where climate policies have matured. The economic crisis has heightened interest in regulatory changes for climate change issues and part of the larger solution to economic recovery.

In North America, where future regulation and related cost-recovery mechanisms are particularly uncertain, this is especially complicated. As these issues are addressed, an emerging set of facts is building a case for preparatory action.

Utilities have recognized this shift as demonstrated by the rise of sustainable business practices from a secondary requirement to a top-tier strategic objective. Industry interpretation on how to achieve this goal varies, however. In many cases this is for good reason as customer demographics, geographic characteristics and generation portfolio composition exhibit a range of characteristics.

A common theme exists among leaders who succeed during uncertainty, whether relating to innovation trends across industries, the evolution of market regulation and business cycles in general or preparation in the face of expected but uncertain change. The common theme centers on a need for improved access to market intelligence and decision-making capability where the impacts of change are expected to be greatest.

Utilities that act now to understand and tackle change will be better equipped to achieve greater earnings at a reduced risk.

These utilities also will be better informed to enhance shareholder value and customer satisfaction over the long term than those that postpone decision-making until more regulatory uncertainty is resolved.

Forward-thinking utility executives are making commitments now.

The implications of inaction are rising, and fence-sitting will become increasingly risky: 

  • Perceptions as opposed to fact will drive policy.
  • Market participants including banks, power generators and investment funds already are acting on revised outlooks.
  • Changes in commodity prices and material costs are affecting the economics of day-to-day operations.
  • Views on prudent action are beginning to diverge.

Adherence to traditional practices likely could lead to undesirable results:

  • Carbon is a factor in long-term contract negotiations.
  • Emissions management decision-making is changing as regional initiatives evolve.
  • Simple organizational silos can impede communications and lead to poor outcomes.

Leaders are building decision-making capability to better address today’s perceptions in preparation for more transformational decisions. Elements of these readiness initiatives include:

 

  • Improved analytics to address the impact of carbon, increased renewable generation and reduced load from EE programs on power and fuel markets,
  • Aligned functions to ensure that traditionally separate functions like compliance, load forecasting and commodity operations are synchronized,
  • Informed and active participatory involvement in the regulatory arena,
  • Exploring innovative partnerships and investment strategies as windows of discovery on technology and other market developments, and

Tracking achievements and communicating to shareholders.

 Path to Improved Decision-making

Building decision-making capability can be difficult to describe in concrete terms. It can be helpful to apply the capability maturity model concept to map a path rising toward decision-making maturity by focusing on the practices that achieve improved performance. Figure 1 represents an example of working toward improved decision-making during regulatory and market change. Utilities that have taken leadership roles on sustainability and have communicated an aggressive strategic repositioning are represented on the right side of the scale. Others that have adopted a less aggressive strategy focused on greenwashing fall to the left of the scale.

The pathway from left to right exhibits unique attributes for each utility. The general stages of maturity, however, apply to any utility. The model is designed to help utilities self-identify where they reside on the scale and how to chart a path forward. Initial steps center on clarifying scope, defining metrics and developing plans to achieve greater engagement and coordination across the organization. For utilities with major coal-fired generation portfolios, the most significant benefits likely will be achieved by focusing first on emissions impacts in their primary service areas. For northwestern utilities with substantial hydro generation capacity, the focus area of greatest impact likely will be EE and exploring additional renewable sources. Secondary to these top-line areas of action would be more traditional corporate sustainability program targets such as corporate energy consumption, reduction in fleet emissions and waste management.

The most effective strategy to address the future regime will depend on the individual utility’s regulatory environment, baseline asset composition and customer interests, as well as its strategy execution capability. North American utilities have the benefit of learning from their EU counterparts that operate under more advanced carbon dioxide regulation. Within this backdrop, utilities face a range of possible actions.

The most significant opportunity regardless of the possible differences in drivers noted above centers on emissions related to serving customer power requirements.

The primary areas of activity to address this key challenge align with two main tracks:

  1. Supply side: actions affecting emissions per unit of power utilities provide that reflects both unit operating efficiency and resource portfolio mix, and  
  2. Demand side: actions impacting total load and the shape of customer demand.

From a strategic planning perspective, these tracks are closely linked. From a tactical implementation perspective, they are less related. Effectively projecting and modeling potential scenarios and then evaluating the risks and benefits of ways forward is complex enough during certainty but is significantly more complicated today.

Supply Side: The Economics of Managing Emissions

Despite regulatory uncertainty, there is some commonality. Current proposals set a target of reducing electricity sector emissions by 20 percent by 2020 and 80 percent by 2050. PA proprietary market analysis indicates that without global warming legislation, U.S. generator CO2 emissions will increase 14 percent between 2008 and 2025. This outlook incorporates widespread implementation of state RPS, public challenges to siting coal generation and development constraints related to bringing additional nuclear generation on line.

For this same period, PA’s business-as-usual (BAU) analysis suggests CO2 emissions per gigawatt hour will decline by 11 percent. Extracting further declines in CO2 emissions to meet contemplated reduction targets creates a sizable challenge for the industry. This challenge is further complicated: A single policy will create a different set of risks and opportunities for each utility in the form of allowance allocations, renewable energy prospects by state or region and lead times for growth options based on existing sites and steel in the ground.

From a cost-implication perspective, potential outcomes for power generators vary by orders of magnitude. PA’s market analysis in mid-2008 on the annual cost for total CO2 allowances for U.S. power generation (before allocations) under the Lieberman-Warner bill total $80 billion in 2012, doubling to $160 billion by 2025. The level of offsets allowed and the reductions in CO2 emissions required can have an impact on total cost in the hundreds of billions over the first 10 years. Proposed CO2 allowance free allocations to fossil power generators under Lieberman-Warner are valued at almost $600 billion from 2012 to 2025.

Drilling into hypothetical portfolio implications, the impact of stringent CO2 legislation on 2020 generation levels of the top 10 U.S. generators when modeled as merchant generators ranges from an increase of 50 percent to a decrease of 25 percent relative to BAU levels. At the same time, the gross margins of those same power generators range from an increase by 55 percent to a decrease by 20 percent. Nuclear, natural gas and renewable portfolios are shown to be winners.

With this nascent scenario emerging, questions related to serving public needs and protecting stakeholder interests are attracting industry attention.

Addressing these questions related to scope, metrics and planning from a maturity model perspective is worthwhile.

  • How can the generation asset portfolio be changed to address existing or potential RPS standards and reduce CO2 and potentially also contribute to rate base growth?
  • Are there regulatory mechanisms in the event the CO2 allowance costs are reflected in gas or coal prices or if the utility itself has to purchase allowances?
  • Are long-term, purchased-power contracts structured to enable full cost pass-through?
  • Are trading and environmental compliance organizations in synch with one another such that excess allowances are being monetized effectively and timely purchases are being made?
  • When the utility commission begins to question the utility’s emissions costs and allowances purchasing strategy, how will the utility be positioned?
  • What is the optimum balance for the stakeholder’s benefit among banking, buying, hedging and trading?
  • What clean technologies are being developed, and how can they change the game?
  • What are the nonregulated market opportunities that will leverage in-house expertise and improve shareholder returns?

     

    Addressing these questions will improve day-to-day decision-making capability in the supply arena. Equally important, better market and operational intelligence stemming from these early actions can lead to more effective action and a more mature and sustainable organization.

 


 

Evidence of Action

 

    li>Our analysis of one client contract portfolio indicated that with a change in the point of CO2 regulation, the potential allowance costs the company risked not being able to pass through were reduced by more than $3 billion. Regulatory shaping efforts were modified accordingly.
  • For another client, we analyzed its utility customers’ risk of not being able to promptly pass through their fuel cost increases and their financial risks and cost pass through potential from GHG cap–and-trade legislation.
  • Several utilities (such as FPL and Iberdrola) have invested heavily in renewable generation with their nonregulated businesses. These investments create shareholder value and provide greater market intelligence for future decision-making.
  • Other utilities have established small, clean-tech venture fund mechanisms to support nonregulated business development and serve as a window on rapidly growing business sectors that have the potential to significantly impact the utility industry.

 Demand Side: Efficient Energy Consumption

Similar to emissions management, energy conservation long has been part of utility strategy. Not until recently, however, has it become a headline issue. Today there is widespread awareness that the pursuit of EE is much more than a sign of personal virtue: It is becoming a business imperative in the economy. EE programs are a key thrust of the Obama administration and many state utility commissions in keeping with the recommendation of the Energy Policy Act of 2005. Advanced metering infrastructure (AMI) programs have the potential to reduce peak demand and total consumption and reduce total utility GHG emissions. To support these and other demand-side programs, we are developing a model that will enable forecasting of the emissions impact of shifting demand between hours in a range of geographies and on a plant-specific basis to enable better program planning.

EE objectives are surfacing in several forms:

  1. Southern California Edison (SCE), one of the leaders in piloting an advanced metering system, submitted a business case to the California Public Utilities Commission requesting approval to deploy 5.3 million smart meters by 2012 with a projected capital cost of $1.3 billion. The utility anticipates that the program will reduce GHG and smog-forming pollutants by at least 365,000 metric tonnes per year. Numerous other U.S. utilities are following SCE and pursuing smart meter networks in their territories.
  2. States and utilities are beginning again to study the quantification and valuation of EE. In New York, PA designed and implemented programs that capture plug-load energy savings, a significant and growing source of energy consumption from the explosion of business and home-based plug-in electronics. The best estimates show that the amount of electricity used in equipment plugged into wall sockets—not a part of the building—approximates 25 percent of a business’ energy consumption.
  3. California is evaluating the most aggressive EE programs in the U.S., following the directives of Gov. Arnold Schwarzenegger to capture all cost-effective EE in the state. A portion of monthly California gas and electric bills goes into a statewide fund called the Public Goods Surcharge (PGS) and pays for EE programs, measures and consumer education.
  4. Other states that have heretofore resisted taking action are watching closely and showing signs of movement. These include the seven-state region covered by the Tennessee Valley Authority, where electricity costs have traditionally been lower than other parts of the country due to TVA’s extensive federal hydroelectric system. TVA is embarking on an aggressive project to assess current end uses of electricity and determine the potential for retrofitting and installing new technologies in its region with the aim of achieving a 1,200-MW reduction in peak demand by 2013. That reduction would offset the need for no less than two power plants. PA was recently engaged by TVA to conduct this assessment during 2008.
  5. In the Midwest where coal has provided a cheap fuel source for generating electricity, states are rethinking their overall mix of resources and increasing the percentage of EE in their portfolios. FirstEnergy Ohio and other FirstEnergy subsidiaries in Pennsylvania and New Jersey are adopting consumer programs aimed at helping customers better manage electricity consumption. In addition to changing state policies, evolving customer interests combined with rising commodity costs are contributing to an expanded EE footprint.

In the past, using less energy (electricity, natural gas or oil) was good for consumers and often was perceived as bad for utilities and fuel oil dealers that had been reluctant to promote strategies to sell less of their products. Regulatory initiatives implemented during the 1980s to help reduce dependence on foreign oil compelled energy providers to press for providing federal- or state-mandated programs that helped consumers reduce winter consumption. Attention shifted to electricity during the late 1980s and 1990s as peak demand for electricity grew dramatically at the same time that the electric industry pulled back on plans to build more power plants. Utilities began offering demand-side management programs to reduce peak usage, thereby allowing utilities to postpone new plants.

Today there is widespread acceptance that identifying and harnessing all cost-effective EE options will be a key difference between companies that generate superior vs. inferior returns. So, too, with commercial real estate, homes and residential buildings; real estate markets in the U.S. and U.K. are seeing that buyers and renters (particularly of new construction) increasingly factor energy consumption into their decision-making. To respond to this growing interest, there are an increasing number of financial products such as green mortgages and home energy-rating systems that help address this consumer need for information. In the U.S., Leaders in Energy Efficient Design (LEED) buildings are becoming the new standard nationally, as energy-efficient design becomes mainstream in many markets.

The combination of a large-scale, federal stimulus package, more active state policies, reinvigorated utility programs and thriving consumer demand for more efficient energy usage create significant efficiency impacts. Understanding these impacts and connecting this analysis to the supply side offers significant upside for managing regulators, customers and shareholders.

Corporate Readiness in a New Light

Traditionally, being prepared has been a fundamental principle of utility strategy. This strategic element captures the need to ensure adequate supply, deliver reliable electricity and respond to customers impacted by severe events, at the same time delivering such services cost effectively across the enterprise. Sustainability and perceptions related to climate change have reshaped the traditional definition of preparedness.

Expectations related to corporate readiness for this bedrock industry have changed. Reliable delivery of power will remain the top priority. Stakeholders, however, will expect a new set of considerations to be addressed to meet that goal. This form of readiness begins with developing the capacity to make better tactical decisions today and strategic decisions in the future. Depending on where a utility sits on the maturity scale, key actions for building decision-making capability include: 

  • Gain a thorough understanding of the potential impact of legislation on operations and the implications for stakeholders.
  • Test permutations of potential legislation for their varying impacts on the business and customers.
  • Begin a dialog with regulators about potential cost exposure and related impact on credit ratings.
  • Assess possible market implications on long-range fuel and power-purchase needs.
  • Ensure new contracts include language appropriate to the risks.
  • Review organizational constraints to internal communication.
  • Acquire an ownership interest in a new technology (such as a wind or biomass plant) to understand permitting and operational issues associated with these technologies.
  • Communicate with peers with successful advanced metering programs about how such a program might benefit one’s own ratepayers and shareholders.
  • Investigate (or dust off old studies) EE and load-management options.

Taking such actions will provide tangible benefits. Almost more important is the experience gained from building capability for the longer-term outcome. Whether it is improved engagement across the organization or identification of an unexpected asset or risk, preparing for a complicated future will create significant benefits.

Author

Mike Hormell is a member of PA Consulting Group’s management group in the firm’s Global Energy Consulting practice. He has worked primarily in strategic repositioning, risk management, asset valuation and retail business launch in the energy industry for 12 years.

Barbara Sands is a managing consultant in PA Consulting Group’s Energy Capital Markets practice. She has more than 15 years of experience in the evaluation of the electricity markets throughout the United States and Canada and oversees the modeling analyses prepared as part of market assessments and generation asset valuations.

Previous articleImproving Outage Management With Smart Grid Technologies
Next articleSpreading Value: How Environmental Policy Changes the Calculation
The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

No posts to display