New Trend: Combining Gas with Wind and Solar Projects

New Trend: Combining Gas with Wind and Solar Projects

September 01, 2012

By Paul Kaufman

First Wind proposed a change in August to the 500-megawatt Baseline wind farm that it is developing in Oregon. The company proposes to add up to 200 megawatts of natural gas generating capacity. The combined wind and gas capacity will remain at 500 megawatts. The company gave notice in a public document posted to the Oregon Energy Facility Siting Council website.

Is this a new trend or are such projects likely to remain rare?

Compelling Economics

Four factors could make such combinations a trend.

The first such factor is the decreasing price that offtakers are willing to pay for as-available energy, a result of lackluster electricity demand and low natural gas prices. A short-term forecast produced by the US Energy Information Administration shows natural gas spot prices at the Henry hub are expected to increase by only $0.39 per mmBtu in 2013 over 2012 prices that averaged $2.95 per mmBtu. EIA has forecast a similarly weak increase in retail electricity prices of 0.9% from 2012 to 2013. In its “2011 Wind Technologies Market Report,” the Lawrence Berkley National Laboratory shows substantial decreases in power purchase agreement prices for wind in power purchase agreements executed in 2011 (when compared to those executed in 2010). LBL prepared this report for the US Department of Energy.

While many factors have led to this decrease in prices, the effect is that wind-generated energy has become a commodity in the marketplace. While utility purchasers are requiring a greater level of proof and security that developers can deliver on their obligations under a power purchase agreement, utilities are nonetheless looking solely to price as a way of distinguishing one wind project from another. The characteristics, experience and qualities of the developer are secondary.

Wind-generated energy is intermittent. By firming wind energy (through the addition of a thermal resource), a developer can distinguish the product sold from that wind project from the intermittent product produced by other wind projects that have not added thermal generation. The “firmed” wind-produced energy can thus be distinguished from the commodity of intermittent wind-produced energy. The specialized, “firmed” product should fetch more in the marketplace than the intermittent wind-energy commodity.

The second factor is market size. In the “2011 Wind Technologies Market Report,” LBL presents forecasts from a number of different sources that collectively indicate that wind capacity additions in 2012 will be between 7,280 megawatts to 12,000 megawatts. The same report shows forecasted capacity additions for 2013 in the range of 1,000 megawatts to 2,400 megawatts and 600 megawatts to 3,000 megawatts in 2014 (if one assumes that Congress fails to extend the production tax credit or investment tax credit for wind past its current expiration date of December 31, 2012). In addition to the possible expiration of tax credits, LBL identifies a number of other limitations on the size of the market, including low natural gas prices, low wholesale electricity prices, inadequate transmission and modest electricity demand. Assuming these predictions are realized, the obvious conclusion is that renewable markets will shrink. In a shrinking market, differentiating what you have to sell is a good thing.

 The third factor is cost. Wind projects sell their electricity solely for energy payments that are a function of the output. They do not also receive capacity payments. Thus, wind developers generally want more electricity over which to allocate the fixed costs of their projects. The more megawatt hours produced by a project, the lower price per megawatt hour the developer has to recover from the utility purchaser and the higher the likelihood that the developer will meet (or beat) its financial targets. By adding a thermal resource to a wind project, the developer can produce more energy over a given amount of capacity and time.

The fourth factor is the ratio of revenue to the fixed costs of a project. Adding thermal generation to an existing wind project, or, in the reverse, adding wind generation to an existing thermal generating plant that is operated as a peaker, will increase the ratio of revenue over the fixed costs associated with facilities that can be shared, such as an O&M building and interconnection facilities. By combining a wind resource and thermal resource, the developer can generate energy with one resource while the other resource is not operating.

Interconnection costs can be a major hurdle to jump in meeting financial return expectations. Interconnection facilities tend to be “lumpy” as their capacity to transmit energy is generally greater than the electricity produced by the associated generating plant. Even with a robust wind source, wind projects will not use all of the takeaway capacity provided by the interconnection facilities generally required by the utility. In the same way, a thermal peaking plant will generally not use all of the takeaway capacity provided by its interconnection facilities.


All of these considerations lead to the conclusion that the combination of resources is a positive development as it may improve profitability, differentiate wind projects and the energy produced by them, and improve the efficiency of the capital deployed by a developer. However, there are other factors to consider when considering whether the combination of a thermal resource and a wind resource makes sense.

First, adding a turbine or reciprocating engine to a wind project means that you will have to address the myriad of issues involved in developing and permitting a thermal resource. The developer’s wind project may have a superior wind resource, but may be located far from the gas pipelines necessary to supply fuel to the thermal portion of the project. Building a long lateral pipeline to interconnect the project to the interstate pipeline system creates yet another fixed cost to allocate.

The security and nature of the fuel supply are also issues. Developers know well the increasing scrutiny applied to wind resource studies and the deductions to net capacity factor that have been imposed by third-party consultants in recent years. What requirements for security of the project’s fuel supply will lending institutions impose on the thermal portion of the project? Will lenders return to the requirement of prior years where a firm fuel supply and transportation were required for the full term of a power purchase agreement? Or will they recognize the different operating characteristics expected of a thermal resource that may be used only to firm wind generation?

A developer acquires site control for a thermal project in a different manner than site control is acquired for a wind project. These differences are driven by a number of factors. For example, while wind projects require, in total, more land to accommodate setbacks and other land use restrictions per megawatt of installed capacity, land leased for a wind project is available to the lessor for other uses such as farming or grazing. The American Wind Energy Association reports that wind projects require the exclusive use of only 5% or less of the land leased for a wind project. While the total acreage used for thermal project development is less, the thermal project will require exclusive use of that land. In turn, this implicitly leads the developer to purchase the land as the prior owner will no longer be able to use or have access to the property.

Second, even in states that have adopted “one-stop shopping” for permitting new power plants, a developer of a combined wind and thermal power plant will be working with two entirely different permitting regimes. Thermal generating plants have to meet air permitting requirements, get approval to use water if the thermal resource is water cooled, and potentially address issues regarding cooling water disposal. While the complexity of permitting a thermal power plant varies depending on the specific type of generation deployed, its water requirements and its emission control technology, the fact remains that thermal generation has a different permitting regime than wind.

Even where a particular characteristic of power generation, for example, noise, is present in both wind and thermal generation, the noise characteristics and, thus, permitting parameters, of a thermal plant will be different than those of a wind facility.

Third, the addition of a thermal resource to a wind project may trigger new permitting requirements if the addition of the resource pushes the project over a permitting threshold. Thresholds are established in a number of different ways under state and local law.

In some states, permitting of wind projects is within the jurisdiction of county or city land use agencies, while permitting a thermal resource is not. For example, the Washington Energy Facility Sitting Council has jurisdiction over any stationary thermal generating facility with electrical generating capacity of 350 megawatts or more, including associated facilities. Yet, Washington EFSC review of wind projects is discretionary with the developer. Will states that have similar state-wide regimes as Washington look at the wind project as an “associated” facility when determining the size of the thermal generating plant? Or will the addition of a thermal generating plant result in mandatory, rather than discretionary, state-level review of a wind project?

Even in situations where primary jurisdiction for permitting is with a county or city land-use agency, the addition of a thermal resource can trigger additional review and resulting delay. A number of jurisdictions have adopted wind resource areas in which wind is an approved use of the land subject only to either a conditional use permit or, as in Riverside County, California, a commercial “wind energy conversion” systems permit. The benefit of these wind resource areas is that the process for reviewing wind projects is clearly spelled out and most of the conditions for wind projects are also found in the agency’s rules or ordinances. The question is whether the addition of a thermal generating facility will exclude the entire project from the processes and benefits intended by creation of these zones or whether two separate processes will be required for review and permitting of the project.

Fourth, the addition of thermal generation may trigger additional interconnections studies and require an additional interconnection application. There are a number of iterations related to interconnection that should be considered.

As a general matter, if you are adding thermal generation to a wind project, or wind generation to a thermal project, and the total capacity of the two resources is within the capacity reserved in the original project’s interconnection agreement, then you will still be subject to additional studies and may also be subject to additional interconnection and upgrade costs as well as restrictions on the operation of the two facilities. The mechanics of how this will be determined vary among transmission providers and independent system operators (ISOs).

Net Zero Interconnection

The mechanics of adding more capacity adjacent an operating power plant are expressly addressed in attachment X to the Midwest Independent System Operator’s tariffs, which provides “net zero interconnection service.” This form of interconnection service allows a new power plant to use the existing interconnection capacity reserved for a power plant that is already operating, so long as the total interconnection capacity used by the two power plants does not exceed the amount of capacity reserved for the power plant that is already operating. The tariff provisions apply equally to wind generation that is being added to operating thermal generation and thermal generation that is being added to operating wind generation.

Before providing net zero interconnection service, meaning allowing a new power plant to use part of the interconnection capacity dedicated to a power plant that is already operating, MISO will conduct a number of studies, including reactive power, short circuit and fault duty, and stability analyses. The tariff says that steady-state (thermal and voltage) analyses may also be performed as necessary to ensure that all required reliability conditions are studied. The tariff clearly contemplates the potential imposition of additional interconnection and transmission upgrade requirements.

To qualify for net zero interconnection service, the generator must submit an application for service and include in that application a memorandum of understanding that shows the applicant intends to enter into a “transmission utility monitoring and consent agreement” upon execution of an interconnection agreement. In addition, the applicant must include an executed copy of an “energy displacement agreement” with the owner of the operating project that must specify the term of operation for the operating and new projects, the total generating capacity of the two projects and the mode of operation for energy production for both projects. The energy displacement agreement is subject to negotiation with the operating project and is not required if the applicant is the owner, or an affiliate, of the operating project.

Behind the Meter

In its “behind-the-meter” rules, the California Independent System Operator allows operating wind and solar generators to add capacity under their existing interconnection agreements and avoid much of the interconnection process. However, this can be done only in limited circumstances. A key limitation is that the incremental generation, when added to the operating capacity, cannot create additional deliverability over that studied by CAISO for the operating capacity. Further, the sum of the total nameplate capacity of the existing facility plus the increase in capacity cannot exceed in 125% of the previously-studied capacity, and the incremental capacity cannot exceed 100 megawatts.

In circumstances where the actual nameplate of the original facility is at or near the nameplate capacity studied by CAISO, these limitations will severely restrict the amount of incremental capacity that can be added. There may be greater flexibility to use the behind-the-meter rules in cases where the nameplate capacity studied is greater than the nameplate actually built. CAISO has other rules regarding partial completion of generating plants.

The behind-the-meter rules also require that the incremental capacity be placed in service under a separate breaker so that it can be metered separately at all times. The tariff gives CAISO the authority to open the expansion breaker if the total output of the combined generation exceeds the originally-studied capacity. The limitations on deliverability of the combined resource, when combined with the risk that CAISO will open the breaker on the project, will create problems if the duration of the disconnection is long and the notice for disconnection is short.

Of course, the generator always has the ability to file a separate interconnection application for the incremental capacity. This outcome may promote greenfield development of combined resources over the addition of incremental capacity to an existing facility. In both cases, the interconnection applications will be considered in the study process.

The MISO and CAISO tariffs are less than clear about what happens to greenfield combined resources. The MISO and CAISO are not alone. The transmission tariffs of other ISOs and transmission providers also lack a clear statement of how combined resources will be studied and authorized for interconnection. Differing ownership of the resources that may be combined adds ambiguity to this topic. Whether this is an issue will depend on the express language of the tariff and the interpretation of those tariffs by the relevant ISO staff.

Fifth, there is an open question whether the combined project will continue to be considered wholly or partly an intermittent resource. As a result, there is an open question whether a combined project will continue to qualify for programs that offer some protection against imbalance charges provided to intermittent resources. The “participating intermittent resource program” provided by the CAISO is one such program.

Under the California program, qualifying intermittent resources are allowed to net their imbalances on a monthly basis, and the intermittent resource owner is charged for net negative imbalances by taking the net amount of the imbalance and multiplying it by the average locational marginal price for the node at which the resource is interconnected. This substantially reduces the imbalance charges for intermittent resources when compared to the rules for other resources, which are charged against real-time LMP prices and not allowed to net over a month. While the overall effect of combining a wind and thermal project should reduce imbalances, will the California ISO allow a developer to remain certified as an intermittent generator if the wind project is now a wind-thermal project? If it does not, then how will it allocate the scheduling penalties that are assessed against non-intermittent facilities if schedules do not match actual deliveries?

Finally, will the addition of a thermal resource allow the developer to increase the price of its differentiated product above that of as-available wind energy? Utility offtakers may welcome a more predictable source of electricity, but will they price the electricity produced by the thermal resource as if it was purchased on the spot market or recognize the capacity value of the combined resource? The market for a combined wind and thermal power plant will have to be tested before anyone can answer this question.

Other Issues

Developers of combined projects will also face construction and engineering challenges if they choose to use a contractual vehicle other than a full engineering, construction and procurement contract for construction of the combined plant. While a disaggregated engineering, procurement and construction model is currently market for wind farm construction, will the same be true if a thermal resource is added to the project? One can expect that the number and type of indemnities required of a contractor and, perhaps, the developer will increase if a developer adds a thermal resource to an operating wind farm or vice versa. While phasing wind projects is common, the combination of the two resource types adds some complexity to what has become commonplace.

Whether or not combining resources becomes a trend, one hopes that the issues identified in this article can be resolved in a manner that makes such combinations easier. While this article has focused on the combination of wind and thermal generating resources, developers are also moving ahead with combined wind and solar projects and combined geothermal and solar projects. Such combinations avoid the concern that combining wind with thermal turns what is otherwise a green resource into partly a brown resource.