By David Haarmeyer, PowerAdvocate
Owners must take a more active, informed and disciplined approach to managing contract and project execution.
The U.S. nuclear renaissance is in full gear. With more than 30 new units proposed, the revival has turned into a race to secure Nuclear Regulatory Commission (NRC) Combined Construction and Operating Licenses (COL), obtain Department of Energy (DOE) loan guarantees, purchase long-lead-time materials and meet other critical milestones.
Already three groups—led by South Carolina Electric & Gas (SCE&G), Southern Co., and NRG Energy—have signed engineering-procurement-construction (EPC) agreements with engineering and construction (E&C) companies (Table 1). These early movers are followed by a growing number of other groups.
Five separate reactor technologies are competing to be the U.S reactor of choice. These include three Generation III+ technologies: Westinghouse AP 1000, GE ESBWR, AREVA USEPR; and two Generation III technologies: ABWR and USAPWR. The AP1000 is the only generation III+ reactor to have achieved NRC Design Certification. GE submitted its Design Control document in late 2005 and AREVA submitted its design in December 2007.
Early cost estimates are significant and increasing. For example, SCE&G’s EPC contract with Westinghouse and Shaw Group, which is one of the first contracts to be completed and publicly documented, puts its portion of the project at around $4,400/kW. Southern Co. is estimating the cost for two AP1000 1,100 MW reactors at its Vogtle site to be in the $2,500 to $3,500/kW range. More recently Constellation, a partner in UniStar’s venture, came out with $4,500 to $6,000/kW estimate reflecting “added security and safety features of the USEPR model,” as well as rising costs of concrete, steel and other key materials. Good reasons exist for the steep and rising costs of next generation nuclear power plants. Constructing multibillion dollar, highly complex, first-of-a-kind infrastructure projects with long construction cycles involves tremendous risks and uncertainties.
In previous infrastructure build cycles, owners depended on fixed price (“lump sum”) EPC contracts to shift most, if not all, engineering, procurement and construction risk to contractors. This contract strategy is still prevalent, but mostly only in name. According to SCE&G, only about half of its EPC contract scope is subject to fixed prices. This means that less than 50 percent of the contract scope is variable price. Therefore, tremendous amount of scope is left without price certainty for multibillion dollar projects. Certainty around a project’s final price is a critical precondition for both obtaining rate recovery in regulated environments and financing in merchant environments.
The reality of many large complex capital projects today is that they rely on a hybrid of fixed and variable pricing structures. Fixed pricing can be applied to portions of the work scope that can be well defined, including equipment and work with detailed scope. Variable pricing is necessary, however, where scope is not well defined or involves increased price and schedule risk or contingency. This approach is especially applicable for nuclear projects, which involve selecting vendors and procuring long-lead components before owners get regulatory approval.
Active, Informed and Disciplined
How should owners proceed in this environment and with so little price certainty? Clearly, they must take a more active, informed and disciplined approach to managing contract and project execution. For example, contrary to the traditional fixed-price EPC contract model that required minimal owner oversight of procurement such as subcontractor approval, the significant amount of scope that is variable price in today’s contracts necessitates owners and their suppliers to be more knowledgeable and active. Moreover, the small portion of a plant’s total fixed price makes it critical for owners to vet and verify escalations applied to contract costs and to ensure that the appropriate indices are chosen and used.
One approach owners use to gain visibility and market insight into the target price (as well as in making sure risks and costs are properly allocated) is the Open Book Pricing Process (OBPP). With this process, an owner can work with an E&C to get transparency into each major cost line item, including contingency and escalation assumptions. The owner and E&C can also arrange to put the contractor’s fee at risk based on cost and technology performance. Working in collaboration, the owner and E&C are able to reach a target price that reflects an appropriate risk profile for each party.
Challenges Translate into Risk
Standing in the way of actual construction and project completion of the next generation U.S. reactors are numerous and substantial hurdles, which translate into significant risks and uncertainties for owners that are driving escalating cost estimates. Taken together, these translate into risks and uncertainties that make applying traditional fixed-price, lump sum contracts impractical in today’s market environment.
The chief hurdles to new build include:
- NRC design certification
- Tremendous capital investment
- Uncertainty on actual project costs
- Uncertainty around workable contract approaches
- Today’s sellers’ market for services, components and materials.
Obtaining NRC Design Certification is one of the most critical first steps in the new build process. Owners that have selected the Westinghouse AP1000 or GE ABWR reactor designs have cleared this hurdle while those seeking the AREVA EPR and GE ESBWR have not. Obtaining design certification has major implications for owners and EPC contractors. In general, early NRC design certification approval provides a firmer foundation for defining and pricing the scope of work. Hence, without NRC approval, owners and EPC contractors are left with a larger portion of the scope that remains variable price and with risks that are not properly allocated.
The tremendous upfront investment required to build the next generation nuclear plants is rapidly becoming multiples of existing generation investment. New combined cycle plants, for example, cost around $900 to $1,200/kW. This is considerably less than the upwards of $2,500/kW or more estimated for new nuclear capacity. These values can quickly overwhelm the market capitalization of many electric utility companies. Consequently, owners are joining together to build multiple units and E&C firms are partnering with reactor vendors; with their relationships and obligations clearly defined in EPC contracts.
New nuclear plants’ significant capital needs can have negative implications for utilities choosing to build. In a recent report, the credit ratings group Moody’s indicated that a utility building a new nuclear power plant may see 25 percent to 30 percent deterioration in cash-flow-related credit metrics. In particular, the ratings groups show that cash flow from operations as a percentage of debt may fall as much as 40 percent.
Not only are nuclear capital project cost estimates high, they are also uncertain. There are four drivers of cost uncertainty.
First, it has been more than 30 years since the last nuclear plant construction start in the United States, indicating a loss of specialized skilled labor and institutional engineering and construction knowledge.
Second, project costs are especially hard to estimate when the construction time period spans seven to10 years, a length of time when the market environment can undergo considerable changes.
Third, project costs will be subjected to significant foreign exchange risk given that the largest cost components (reactor vessel forgings and turbine generator forgings) will not be manufactured in the United States.
Fourth, significant uncertainty surrounds the ability of owner supply chains to access the market for nuclear components. In April, Gerd Jaeger, a member of RWE Power AG’s executive board, suggested that the supply crunch caused by the rush to buy critical components could price nuclear out of the market and thus, vendors need to “de-bottle the bottlenecks.”
According to PowerAdvocate’s Capital Cost Indices tool for tracking cost changes, the cost of construction for utility facilities, including combined and simple cycle, wind and coal plants, as well as transmission lines and environmental retrofit scrubber projects have shown increases between 70 percent and 106 percent since 2000. As indicated in Figure 1, nuclear power plants show an even higher run up in costs—125 percent since 2000. Most of the increase has taken place since 2005.
A significant bottleneck is the ultra-large forgings for nuclear power plants in which Japan Steel Works (JSW) is the sole global supplier. Consequently, nuclear plant EPC contractors are queuing up to make hundreds of millions of dollars of down payments and face lead times in high single-digit years. For example, several U.S. early movers have reserved slots with JSW, helping to fill its order book until 2010. This bottleneck will remain at least in the near term until firms such as Sheffield in Britain, Dooson Heavy Industries in South Korea and emerging companies in China have the necessary capacity to become competitive.
Cost uncertainty for new nuclear power plants is not limited to the U.S. market but also Finland, which along with France, is the only “developed country” presently constructing a new nuclear facility. According to reports, the 1,600 MW Olkiluoto-3 EPR nuclear power plant is two years behind schedule and perhaps a third or more over its original €3 to €3.2 billion ($4.7 to $5 billion) budget. Although significant construction activity is taking place in Asia (especially China and India), building a plant in developed countries such as the United States, Finland or France is significantly more difficult and costly given the much more stringent and detailed regulatory requirements.
The contract strategy chosen for building new nuclear plants is a key driver for project costs as it determines how risks will be allocated between the owner and contractors. As indicated, a fundamental shift has occurred from fixed-price (lump sum) EPC turnkey contracts to hybrid contracts with variable (cost reimbursable) and fixed-price components. This shift to hybrid contracts has major implications for owners given that the traditional fixed-price EPC approach included project risks that were allocated to the EPC contractor. Under the hybrid approach, the owner will shoulder more risk and thus must take a more active role in managing the contract. How owners will address this major challenge is a big uncertainty.
The contract strategy chosen and the owners’ role in executing it will be closely scrutinized by institutions that look to finance the new nuclear plant build because these institutions will have the reasonable expectation that their investment can be financed. A key financing player in the early build cycle is the DOE, which has set up an $18.5 billion loan solicitation process for ranking owner applications. As structured, DOE will rank applications based on the following criteria:
- 50 percent based on project’s long term investment worthiness
- 30 percent based on technology choice, and
- 20 percent based on EPC partnership structure and risk assumption. Thus, in allocating funds, DOE is putting substantial weight on contract strategy.
SCE&G, Southern Co., NRG Energy and their partners have signed EPC agreements with E&C and vendor partners, in which they leave significant portions of the total plant price open to escalation. Consequently, owners face tremendous challenges in demonstrating to DOE and financial institutions that they have a credible strategy for pricing the variable portions of project scope and ensuring risk is appropriately allocated. Simply declaring that their contracts are “fixed price” will not be sufficient to comfort investors; owners must also overhaul their definition of “vendor involvement.”
Finally, the current sellers’ markets in services, components and materials have significant risks and cost implications for building new nuclear plants. The global construction boom, which includes building facilities in the electric power industry as well as in the oil and gas, metals, manufacturing and other sectors, is putting unprecedented pressure on commodity, component and service prices, adversely impacting owner supply chains. Demand for E&C services is so great that firms can be selective in the projects they take, lessening competition for projects and the owner’s ability to shift risks to contractors. Thus, the current sellers’ market puts owners at a distinct disadvantage when negotiating contracts, which can lead to owners shouldering more risk. Moreover, without taking sufficient safeguards, owners may even pay EPC contractors more—higher EPC premiums—to assume less risk.
Cost Visibility and Predictability
The hurdles discussed here demonstrate that constructing multibillion dollar, highly complex, first-of-a-kind infrastructure projects with long construction cycles involves tremendous risks and uncertainties. What these projects have in common is substantial portions of work where scope is not well defined or involves significant price and schedule risk or contingency. This raises tremendous problems of price uncertainty, which becomes an obstacle for gaining regulatory approval and financing.
How will the owners of the next generation nuclear power plants address price uncertainty and ensure risks and costs are properly allocated? The simple answer is that, compared to the past, owners must take a more proactive, informed and disciplined approach in the capital project process. To accomplish this, owners must take advantage of approaches and tools that enable them to facilitate collaboration among all parties, leverage competition whenever possible, increase transparency and capture project procurement information.
Open Book Pricing Process (OBPP) is one proven approach owners have used in complex capital projects to gain the cost visibility and predictability necessary to establish the project price. In a quarterly earnings call earlier this year with analysts, David Crane, president and CEO of NRG Energy, responded to a question about the inherent price uncertainty in its EPC contract with Toshiba. Crane said, “The process that we’ve entered with Toshiba. . . is to establish price now as if the plant was going forward. (The price) is built around, again for the EPC, the $2,900/kW. We will then have an open book process with Toshiba on the key elements of the price until such time as we get the combined operating license from the NRC, which we expect sometime in late 2010 or 2011. At that point, the price will be fixed.”
Key to making this approach work is an open collaboration between the owner and contractor to get transparency into each major cost line item, including contingency and escalation assumptions. This requires extensive active “due diligence” by the owner into the contractor’s costs estimates. As a fluid and open process, the successful application of OBPP involves continual benchmarking, analysis and estimate reviews to establish a target price that reflects an appropriate risk allocation between the owner and EPC contractor.
SCG&E has publicly issued information on its EPC contract, which suggests it is taking steps in the direction of OBPP. For example, it has identified four fixed price categories and three variable price categories, based on actually accrued EPC costs. The fixed pricing is applied to portions of the work scope that are well defined including equipment, work with detailed scope, scheduling, manufacturing and procurement. Target prices are applied where scope is not well defined or involves increased price and schedule risk or contingency.
SCE&G notes that there are five indices that will be applied for cost escalations or used for budget and target price forecasts. With about 50 percent of the total price variable, the choice and use of the indices is critical. Consequently, owners must actively review and apply specific indices. Best practice experience has shown considerable difference between the use of contractor preferred cost indices and independent, customized indices. On an annual basis, these differences may appear insignificant, but on a cumulative basis they can become material. For example, Figure 2 provides a look at PowerAdvocate’s cost escalation of past and prospective construction services, a major component of nuclear plant build. The range in forecasts indicates how meaningful the different forecasts can be.
With projects the size of new nuclear plants, it is prudent for the owner to customize its index to the unique component breakdown of the plant technology selected in the intended construction region. Each individual plant component should be aggregated into similar component categories. By weighting each component and assigning an index, an accurate escalation can be derived. This should be performed on both materials used for construction and for labor.
As first of a kind, multi-billion dollar capital projects with long construction cycles, the next build of nuclear plants face significant risks and uncertainties. These risks are helping move strategies for contracting engineering, procurement and construction firms away from the traditional fixed-fee approach to hybrid models that can better address the significant scope and risk allocation challenges of these complex capital projects. These new models make it imperative for owners to take a more active and informed role throughout project execution, or be left shouldering disproportionately more risk and paying higher costs.
To achieve more cost visibility and predictability, owners should rely on the OBPP to harness competition and benchmarking data, which are crucial for developing fair and reasonable target prices. The relatively small portion of future nuclear plants’s total price that is fixed means it is critical for owners to understand the indices’ development and application. The significant risks and uncertainties raised by the next generation of nuclear plants require owners to adopt a new level of active capital project engagement that puts them squarely in the driver’s seat.
Author: David Haarmeyer is a director at PowerAdvocate, a Boston-based sourcing and supply chain company focused on the energy industry. He would like to recognize his colleagues Paul Schuster, Tom Hickey, Ian Kalin, Michael Cohen and others for their input to this article.