Climate Policy Risk Management in the Electricity Industry

by Richard Sandor and Michael Walsh, Chicago Climate Exchange

For electric power companies facing climate policy risk, the message is clear: If you are not proactively managing your exposure, now is the time to start.

The U.S. House of Representatives has passed carbon cap-and-trade legislation that would impose carbon dioxide-emission limits in 2012 and steadily increase thereafter, and the Senate is considering similar mandates.

Given the major economic implications, building knowledge of your company’s emissions inventory and developing intelligent compliance and risk management strategies are critical. This means understanding the full scale of your economic exposure, assessing compliance options and implementing compliance and trading procedures that will help you cost-effectively meet any federal emission limits.

Many energy producers can develop a good strategy by leveraging their previous experience in market-based, environmental management. While many power generators have more than a decade of experience in managing within emission-allowance systems, the nature and economic scale of the proposed carbon caps is unprecedented.

Electricity producers met and solved the acid rain problem when the federal government regulated sulfur dioxide and nitrogen oxide. Creation and implementation of management plans and cost controls for this unprecedented task were challenging initially. After more than a decade of experience under the Clean Air Act Amendments of 1990, we see that major cuts in acid rain emissions have been realized at moderate cost, public health benefits are substantial and managing SO2 and NOx has become another part of doing business.

Our family of U.S. exchanges–the Chicago Climate Exchange (CCX) and Chicago Climate Futures Exchange (CCFE)–hosts rules-based and transparent trading for environmental markets. Reductions achieved through CCX are the only reductions made in North America through a legally binding compliance regime providing independent, third-party verification by the Financial Industry Regulatory Authority (FINRA, formerly NASD). CCFE is a Commodity Futures Trading Commission-regulated market that offers standardized and cleared futures contracts on emission allowances and other environmental products and provides counterparty, risk-free transactions.

In operating these exchanges, we work with a range of electric power generators: rate-regulated investor-owned utilities such as Tampa Electric Co. (TECO) and American Electric Power (AEP); merchant generators such as NRG Energy Inc. and Reliant Energy; municipals such as American Municipal Power Inc. Ohio; and co-ops such as Hoosier Energy and Associated Electric Cooperative Inc. in Missouri. Along with a diverse, multisectoral group of industrials, governments and universities, these members of CCX’s cap-and-trade program have taken on voluntary, legally binding commitments to reduce their carbon emissions 6 percent below 2000 levels by 2010.

We also get to see implementation of best practices through our work with energy companies that use our federally regulated futures and options contracts to manage price exposure for emission allowances in the Environmental Protection Agency’s (EPA’s) SO2 and NOx programs.

Active hedging through use of CCFE’s futures contracts for the newly launched northeast U.S. Regional Greenhouse Gas Initiative (RGGI) have made the CCFE market the industry price reference for this first mandatory U.S. CO2 cap-and-trade program.

Responding to customer demand, CCFE recently launched the only futures contract covering CO2 emission allowances for a national U.S. regulatory environment. The contracts, for expiration dates in January 2013 and later, require delivery of U.S. emission allowances established in a federal, mandatory, cap-and-trade program. If there is no federal mandate when a contract expires, sellers must deliver specified emission allowances established under other mandatory programs (including European Union and RGGI allowances).

As the debate in Washington, D.C., continues, companies are left waiting in holding patterns for details while they consider how to integrate carbon management into their overall business plans.

Basic unknowns remain: What will emission limits be? How much might my emissions exceed the cap and necessitate mitigation through market transactions?

In considering emerging risks, however, some things are known. If a mandatory carbon cap becomes law, the electricity industry will face a new cost center that impacts budgets, shareholders and customers. These knowns signal it is time to organize and test options for near-term implementation of risk-management strategies.

Legislative Direction

The U.S. House recently passed the American Clean Energy and Security Act of 2009–the Waxman-Markey bill. While the content, timing and political fate of final legislation hinges heavily on Senate action, the major economic implications of carbon and renewable energy goals make it important to understand the bill’s core elements.

Like the existing SO2 and NOx cap-and-trade programs, each power plant would be responsible to obtain and retire emission allowances (or project-based offset credits) in amounts equal to its total calendar year emissions. When free allowance issuance ends in 2030, all regulated entities will be required to purchase 100 percent of the allowances needed for compliance.

To assure that the value of freely issued allowances results in customer benefits, the allowances dedicated to the sector are issued directly to local distribution companies (LDCs). Public utility commissions (PUCs) are assigned overseeing disposition of the allowances issued to LDCs. Emission allowances will not be issued to an LDC until the PUC completes a ratemaking process addressing how it will use the allowances and reports that plan to the EPA.

The quantity of allowances issued to each LDC is based 50 percent on its power generator’s historic emissions from power generated for retail, and 50 percent on its share of total national electricity deliveries. The latter calculation is updated every three years. Unused allowances can be banked for use or sale in later years. As one of several cost-containment features, regulated entities can borrow allowances from their next year allotment at no cost and from years beyond that with interest. A limited early-action crediting provision allows owners of verified early industrial emission reductions and emission offset projects to receive federal allowances.

Initial analysis suggests many coal-based utilities would start short by 25 percent in 2012. Applying this shortfall to a generator that emits 10 million tons a year would imply a purchase obligation of 2.5 million tons of emission allowances. At an allowance price of $20 per ton, (price scenarios are discussed later), this would add $50 million to annual operating costs.

Like the electricity sector, oil refiners are covered starting in 2012. Refiners are responsible for the carbon footprints of their sold products (gasoline, diesel, jet fuel, etc.), but receive essentially zero allowance allocation.

This carbon footprint of 2.5 billion metric tons of CO2 would have to be covered through purchase of allowances at the federal auctions or from other sectors that are given allowances for stimulating objectives such as end-use energy efficiency (e.g., allowances are issued to state governments that will sell allowances to fund efficiency programs).

A rough estimate of fuel-price impacts is 1 cent per gallon for each dollar of allowance costs (e.g., a $20 allowance price converts to a 20 cent per gallon gasoline price increase).

Manufacturers are covered starting in 2014. Their allocations are relatively generous in part to protect international competitiveness of trade-sensitive industries. Starting in 2016, natural gas distributors must cover the carbon content of the fuel they deliver (except to power plants). As with all sectors, allocations to these sectors phase down to zero by 2030.

Allowances imports are allowed from approved comparable foreign cap-and-trade programs. Credits from approved domestic and international mitigation projects, such as methane capture and tropical forest protection, can be used for compliance.

Up to 1 billion domestic and 1 billion international offsets can be used each year. Costs, technical capacity and the multitude of detailed rules and required international agreements, however, will make it difficult to realize these quantities.

The bill also sets CO2 emission performance standards for new electricity plants. The standards, which would take effect after carbon capture reaches specified installation levels nationally, would effectively require new plants to capture carbon or use combined-cycle natural gas.

To stimulate carbon capture and sequestration, the bill authorizes an industry-led and funded Carbon Storage Research Corp. and allows considerable allowances to be used as a bonus to plants that install such systems.

A $10 minimum auction price and reserve allowance auctions at $28 (these prices rise annually by 5 percent plus inflation) suggest an initial range of possible allowance prices. The EPA’s economic analysis yields near-term prices of $11-$17 per metric ton of CO2, rising to around $20 in 2020 and the mid-$20s in 2025. The modeling generates prices considerably higher if international offsets do not flow in at maximum allowed levels.

Climate Policy Risk-Management Best Practices

Working with leading energy companies, we have seen a suite of practices that drive superior results in cost-effectively complying with requirements of emission cap-and-trade programs. Some of the best practices include:

  • Making climate risk management strategy a board-level issue,
  • Implementing board strategy through a team involving the chief financial officer, general counsel, environmental and fuel specialists and energy and emissions traders,
  • Monitoring legislative activity, weighing in directly with your Congressional delegation and through industry associations,
  • Immediately initiating coordination discussions with your PUCs and LDCs,
  • Evaluating costs and risks of internal mitigation options, comparing internal costs with possible allowance prices: Are fuel switching, modified dispatch order, end-use efficiency, new nuclear and expanded power purchases effective options for your organization?
  • Using holistic environmental management to integrate the carbon strategy with your approach to renewable energy requirements and other regulated pollutants,
  • Identifying possible upside opportunities from trading: new revenue sources, strategic allowance and offset purchase activities directed to enhance business relationships and your local economy,
  • Developing emission-trading capabilities by establishing access to relevant markets and building and testing internal procedures for approving, processing and accounting for allowance trades,
  • Evaluating your options for selecting an optimal, historic emission baseline from the range of allowed time periods,
  • Assessing the economics of carbon capture and sequestration in light of potentially significant financial support from a final legislative package,
  • Weighing the merits of gaining practical experience through participation in voluntary initiatives such as the Carbon Disclosure Project, CCE and EPA’s Climate Leaders program,
  • Understanding the benefits and risks associated with buying credits from existing early offset projects and emission-allowance programs that can be converted into federal allowances, and
  • Working together with generators, LDCs and PUCs now to understand and plan optimal implementation plans.

Federal greenhouse gas regulation is another in a long line of business challenges faced by energy producers. It is yet another challenge for businesses that have solved such daunting problems as rural electrification, production of ever-cleaner fuels and the reduction of SO2 and NOx emissions.

Energy industry leaders will use existing tools and innovate new ones to provide cleaner energy in years to come while keeping energy affordable. This issue is no longer in the distant future.

The time to learn how to manage, reduce and trade carbon is now.

Authors

Dr. Richard Sandor is founder, chairman and CEO of the Chicago Climate Exchange and the Chicago Climate Futures Exchange.

Dr. Michael Walsh is executive vice president of the Chicago Climate Exchange.

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