Roasting the Duck

Roasting the Duck

Lon Huber – Senior Director

With modeling by Anirudh Kshemendranath and financial research by Dominic Garetto

Recent news about the solar plus storage project by Tucson Electric Power (TEP) has grabbed a good deal of national attention.  

In case you missed it, TEP’s power purchase agreement (PPA) covers 100 MW of single-axis tracking solar, plus 30 MW of four-hour energy storage. According to Utility Dive, the solar portion of the deal is priced around 3 cents/kWh. The total bundled price, including storage, is less than 4.5 cents/kWh for 20 years.  Given Strategen’s work in related policy development and scenario modeling, we decided to look at how this solution could be applied to California’s famous “duck curve”.  

Locking in semi-dispatchable clean, renewable energy for 20 years at that price from a top developer is a big change from the recent past, when standalone solar costs were more expensive. While solar prices are now more widely published, publicly-available storage prices remain rare. As such, the news about the low price of this combined package was a pleasant surprise to many in the industry.  

However, for those who follow the storage industry closely, the pricing wasn’t an eye-opener. What’s astonishing is why policy and renewable energy procurement in many states is so far behind on these developments. It’s a lost opportunity for ratepayers. 

Low Carbon Grid Study

To capture these opportunities, Strategen, on behalf of the Arizona consumer advocate, put forward the policy concept of the Clean Peak Standard. The premise is simple: Chasing the cheapest available renewable energy credits (RECs) may not sufficiently reduce costs elsewhere on the system, such as those needed for integrating renewables or meeting peak demand. However, renewable resources could be leveraged to reduce these additional grid costs by coupling some procurement of new renewables (or the retrofit of existing projects) with other technologies such as advanced inverters or energy storage. To be sure, this may add to the costs of an individual project (i.e. the REC price), but these costs must be weighed against the substantial benefits that could be realized by taking full advantage of today’s technologies. Doing so will help to ensure money that could be benefiting ratepayers is not left on the table.

The focus on low-priced RECs, without regard to the timing of energy output, is an outcome of policies created when renewable energy was only a small fraction of the overall generation mix, and more expensive, relative to status quo alternatives.

Breaking away from a narrow focus on pursuing the lowest-cost RECs will save ratepayers significantly. The time-shifting capability of TEP’s new project allows a region with strong solar resources to deliver competitively-priced renewable energy at the most expensive time of day - creating more benefits to the grid than simply pursuing the lowest possible cost per kWh without regard to the timing of the delivery of such energy.    

As states contemplate higher renewable targets under old frameworks, it is ever more important to understand the opportunity cost of status quo renewable energy procurement. The Low Carbon Grid Study demonstrated that ratepayers could save more than $1 billion per year in California if renewables were deployed in a smart and portfolio-balanced fashion.

Moreover, a balanced portfolio reduced emissions more than a status quo approach; and some states are beginning to realize this. NYSERDA added a 10% weight to Operational Flexibility and Peak Coincidence for New York’s Clean Energy Standard Procurement, which is a positive step, but not enough to make any meaningful impact.

Opportunities to revise policies for greater grid and consumer benefits are not limited to energy storage.  NREL collaborated with First Solar to test out what a solar plant could really offer if the power electronics were used to their full potential. After test episodes indicated the solar plant provided frequency regulation services at higher performance standards than traditional generation operators, NREL concluded: “The test demonstrated that the advancement in inverter technology now allows renewable resources to provide essential reliability services similar to traditional resources using fossil fuels.”

Arizona’s political leadership has given utilities the space to move beyond focusing on the cheapest-price RECs. Back in 2008, APS signed a 280 MW solar plant with six hours of thermal storage, and SRP just procured solar plus storage. In addition to the recent project led by TEP, the company procured 20 MW of storage in 2016 with some solar attached.  A key benefit for these combined projects is the ability to apply the solar investment tax credit to the storage as well, provided that certain charging requirements are met.  Not all states are pursuing this strategy and as the ITC winds down, starting in 2020, near-term opportunities to take advantage of this valuable federal benefit may be missed.  For example, with solar and storage economics at such competitive levels and these technologies availing themselves of a combined tax credit, this could be a superb window to reduce cost pressures on ratepayers, improve grid stability and demonstrate leadership in advanced energy policy.

The TEP project offers an impressive public proof point. Strategen has modeled the financial viability of offering utility-scale solar plus storage at this price level. Given tax credit benefits on both solar and storage systems, current industry insights on storage costs, and assuming locations with strong solar resources, the fundamental economics are working today.

As a simple rule of thumb, the current price reflects an additional cost (above a solar PPA price without storage) of approximately 1.5 cents per kWh for total annual output to shift 30% of nameplate capacity for four hours, with a sunny capacity factor. 

Think about that: A state could shift a good portion of its utility-scale PV production and turn this into four hours of flexible, dispatchable resources for a 1.5 cent adder to a portion of their PPAs.

What if California did this?

As a thought experiment, Strategen examined what would happen to the famous California “duck curve” if it included energy storage as a component of all its utility-scale PV projects. Strategen used CAISO SB350 study assumptions[1] as we considered two scenarios[2]: 1. All current and future utility-scale PV is paired with 30% of nameplate capacity four-hour storage; and 2. Only future PV is paired with the same-size storage. The results speak for themselves:

Scenario 1: All Utility Scale Solar Paired with Storage at 30% Nameplate (4hr)

Duck Curve2
Duck Curve3

March Average

July Average

Average Peak Reduction

5.42 GW

6.5 GW

Reduction in Ramping by Volume (15:00 to 20:00)

7.51 GW

8.6 GW

Reduction in Ramping by Percentage (15:00 to 20:00)

34%

46%

Scenario 2: Only New Utility Scale Solar Installed from 2016 to 2030 Paired with Storage at 30% Nameplate capacity (4hr)

Duck Curve Scenario 2
Duck Curve Scenario 2 July

March

July

Average Peak Reduction

3.707 GW

4.47 GW

Reduction in Ramping by Volume (15:00 to 20:00)

4.51 GW

5.58 GW

Reduction in Ramping by Percentage (15:00 to 20:00)

20 %

30%

Levelized Avoided Costs

We moderated the slope of the duck’s neck and chopped the head of the duck off for 1.5 cents/kWh added to PPAs. Readers may ask, “Is that a good deal”? Ignoring ancillary service benefits and reduced curtailment, could the capacity value alone make it pencil out for ratepayers? According to the E3 public tool model the CPUC commissioned, increasing the capacity value of solar to reflect the addition of 30% of nameplate storage resulted in two cents/kWh in additional benefits.[1] Again, this is very high level and would need a full study to accurately gauge the benefits that would likely have diminishing returns. A further study would also have to account for key benefits, such as reduced curtailment and flexible capacity services.

So, if we determine that this pencils out for ratepayers, what about retrofits? Indeed, it represents a large multi-billion dollar retrofit investment opportunity, more than 30% of which would currently be supported by Federal tax credits and accelerated depreciation benefits.  

But what are the challenges?

1. The retrofit strategy would doubtless raise questions about addressing contractual, ownership and operational issues for the broad mix of PPAs, under which so many California solar plants are currently delivering their power. Some of these issues are mitigated with DC coupling, which utilizes the existing solar inverter and grid connection, and reduces or eliminates the need for grid impact studies and revised interconnection arrangements. More importantly, parties would benefit from shifting solar energy generation to better match grid demand. Given the capability of storage retrofits to achieve time shifting with significant technical and economic benefits for all stakeholders, these issues could be addressed with a clear and robust policy mechanism (which is a separate discussion).

2. What about the ITC? While the industry has not yet achieved a full history of publicly available precedent transactions on this topic, energy storage retrofits are already underway, with owners utilizing the ITC and MACRS incentives based on IRS Private Letter Ruling support and legal opinions from major law firms.  The technical aspects of a DC-coupled system, assuming standard configurations that cannot charge from the grid, simplify the ITC claim status. While any specific project would require review and confirmation by professional tax advisors, the potential for capturing tax benefits for retrofit systems is real – provided all parties take action on this opportunity in a timely manner before the existing federal tax credit decreases. 

What about standalone storage?

Despite the benefits of solar plus storage, it should be noted that there can be significant benefits related to standalone storage given the ability to deploy the storage assets at high value locations deep within the grid. The localized services offered by these standalone facilities can outweigh the cost saving benefits of solar plus storage coupling through the avoidance of expensive line upgrades and providing high value flexible services within congested load pockets.  Indeed, most of the recent procurement and installation of new storage capacity in California is standalone. Thus, policymakers should not ignore the benefits of hyper-localized or geographically targeted standalone storage –this is why the Clean Peak Whitepaper specifically addresses this issue. 

Moving Forward

Moving forward, states have a huge opportunity to pursue a comprehensive approach to renewable energy procurement on behalf of all ratepayers. This by no means indicates that the answer is exclusively solar plus storage. Other technologies and policies must be pursued, but with California’s rapid progress toward achieving its RPS, the state is already experiencing impact episodes earlier than anticipated - in some cases by four years, including ramps topping 15 GW with curtailment levels increasing each year.  1.5 cents/kWh to mitigate these challenges seems like a good deal (although only a complete cost-benefit analysis for each state can provide the answer with enough accuracy to guide a specific policy).

Policymakers must act soon in order to allow operators and investors to take full advantage of the ITC. One thing is certain: As states such as Massachusetts and New York seek to reach higher renewable targets, the pursuit of the lowest-price REC may not yield the greatest benefit to ratepayers; and it will certainly not advance renewable technologies. Ratepayers and all stakeholders deserve to capture the benefits that are already available with today’s energy technologies, including increased grid reliability. This will go a long way toward paving a greater renewable energy future (and mitigate solar eclipse-related heartburn).

As this thought experiment illustrates, with a modest adder to PPAs to encourage storage coupling, an intermittent must-take renewable project can be transformed into a flexible and reliable resource. The modeling shows that when this coupling is applied at a large scale, a state can realize a significant cut in ramping and a multi-GW reduction in peak demand. In this case, you can consider the duck roasted. 


Footnotes

[1] Scenario 1A

[2] Model Assumptions:  Currently Installed Utility Scale Solar: 6726 MW (2015) (Source) E3 New Solar Installed Between 2016-2030 7601 MW (Source)

  • Assumes 1% load growth and 16 GW of additional DG by 2030
  • Assumes by 2030, the Biomass/ Biogas and Small Hydro increases by 1% annually
  • Solar plants are paired with co-located storage systems, including retrofits to existing plants and co-installed with new plants under Scenario 1, and only with new plants under Scenario 2
  • Full ITC and Depreciation benefits assumed for solar and storage systems in both scenarios.

[3] E3 NEM Public Tool Assumptions:

  • Stock model assumptions utilized except 50% RPS scenario selected
  • Assumes Single Axis Tracking systems have an ELCC value 20% greater than fixed systems based on historic values. (Source)
  • Solar- Tracking ELCC: 38% in 2017
  • Solar + 30% Nameplate Storage ELCC:  68%