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Colin Rickert, Founder & CTO at Digital Wind
Aligning Renewable Energy Supply and Demand Amid Rapid Market Growth
Renewable energy markets are rapidly expanding in terms of installation, capacity, and consumption. This growth is largely driven by prosumers striving for a carbon-neutral economy, as seen in the rise of Renewable Energy/Portfolio Standards (RES/RPS). Achieving this goal involves both increased grid electrification and expanded renewable capacity. However, the variability in energy supply from Renewable Capacity Providers (RCPs), along with fluctuating demand from factors like electric vehicles, seasonal consumption, time-of-use pricing, blockchain mining, and storage, makes it difficult to align future supply with demand. The misalignment between projected supply and demand leads to increasing gaps between real-time nodal energy prices and the prices offered from existing offtake contracts used by RCPs, which aim to swap volatile Locational Marginal Prices (LMPs) for stable long-term prices.
In this and future write-ups, we demonstrate that such gaps exist because currently available offtake contracts, such as Power Purchase Agreements (PPAs) and energy hedges, are inefficient at directing capital toward aggregate renewable energy production.
Our hypothesis is that…
The inefficiency in capital allocation to renewable energy projects is due mostly to increasing “risk-off” price deductions to offtake contracts as new projects are added to the grid, contributing to an overall loss of market liquidity and increased reliance on energy traders and other market adjustments such as RECs. This is a direct consequence of linear price/cost assumptions that conflict with real-time prices in either under-delivered or over-delivered actual vs. expected volume periods. A growth strategy is only as good as its ability to adapt. While having a clear roadmap is essential, flexibility is key to sustaining growth in a constantly changing business landscape. Market conditions, customer preferences, and technology are all in flux, and businesses must remain nimble.
The inefficiency in capital allocation to renewable energy projects is due mostly to increasing “risk-off” price deductions to offtake contracts as new projects are added to the grid, contributing to an overall loss of market liquidity and increased reliance on energy traders and other market adjustments such as RECs.
Volatile Electricity Prices and the Shift to Renewables
Electricity prices in grids using economic dispatch are determined by the balance of supply and demand. In regions like North America, this is often done through Locational Marginal Pricing (LMP), where the lowest-cost bid that meets demand sets the price for all participants at that location. Traditionally, these prices were driven by fuel costs, but in many Western countries, carbon reduction is now a priority. As a result, renewable energy is prioritized before non-renewable sources are scheduled to meet demand. This shift, along with the variability of renewable energy, has made electricity prices more volatile, leading to frequent changes in what’s called the “floating price” at the point of interconnection. However, most consumers are shielded from this volatility, as utilities or electric cooperatives manage the risk on their behalf, providing stable rates.
Power Purchase Agreements (PPAs) serve as risk-management contracts, where the buyer such as a utility agrees to buy electricity at a stable price from producers (e.g., wind farms) and sell it to consumers at another fixed price. The utility takes on short-term price risks, smoothing out volatility for both producers and consumers. This swap structure allows utilities to manage price fluctuations and make a small profit by accepting this risk. They balance supply from multiple producers to minimize the shape risks, which refers to uncertainty about when supply and demand will align. By managing this and other associated risks (see definitions below), utilities ensure a stable flow of energy and shield both producers and consumers from volatile market prices. So the utilities are in a sense, providing liquidity in return for a stable supply of energy — much like an industrial agricultural company can offer a stable supply of food delivered from the farmers they contract with to the consumers who purchase at grocery stores.
Energy hedges are another form of offtake contract where the bank swaps a fixed price for the floating price at the point of interconnection on behalf of the RCP. This is done for a fixed portion of energy, typically up to the 90th(+) percentile of expected production exceedance adjusted for seasonality. The RCP will be paid the fixed price times the fixed volume at all times lest they fail to meet the volume component at which point they owe the counterparty the missing amount at the market price — more on that later.
Ensuring Price Stability in Renewable Energy Markets
These swap arrangements, or offtake contracts, act as ‘price smoothers,’ allowing market participants to benefit from stable forward prices. The stability created is critical for activities such as operations and maintenance (O&M), remuneration, mergers and acquisitions (M&A), and other long-term planning. Without it, energy markets would struggle to function efficiently.
To illustrate why, we can borrow terminology from futures markets. Imagine a consumer needs to buy a certain amount of corn for the next summer or fall. Without knowing the future price, they would hesitate to allocate funds, since there is uncertainty about how much they will need to spend. However, if a producer can offer to sell the corn at a fixed price for future delivery, the consumer is more likely to commit to purchasing in advance and in larger quantities. In this way, the swap arrangement benefits both parties — ensuring bulk demand meets bulk supply at a stable price.
This price-stabilization mechanism is essential for markets to function at scale. The producer gains security through a predictable future income, allowing them to cover current expenses, while the consumer gains reliable access to a steady supply of goods. In cases where the producer cannot deliver (such as crop failure), the contract typically includes provisions for reimbursement, which can involve secondary markets like insurance. Similarly, in renewable energy markets, such price stability is crucial for the market to function effectively and meet renewable energy/portfolio standards (RES/RPS). Without forward price stability, it becomes much harder to scale renewable energy production and consumption.
Feasibility of RES/RPS Goals in Renewable Energy Markets
That brings us to the current point in time where there is a need to assess the forward price stability of current renewable energy markets in light of RES/RPS standards that require an increasing supply of renewable energy.
We pose the following questions to the industry at large:
- Are forward prices stable enough to ensure long-term RPS/RES growth goals? How much of this risk is “priced-in” in terms of currently available offtake contracts for RCPs and how costly is it in terms of price “adjustments” when offering into the PPA, energy hedge or other similar P2P markets?
- To what degree are current market prices for offtake contracts of renewable energy adequate for long-term producers to offset costs and also allow for marginal long-term profits?
- To what degree have current offtake contracts and other market interventions such as RECs been successful in providing adequate liquidity in exchange for covering liquidity gaps in the forward price? Are these measures transparent or opaque thus resulting in “greenwashing”?
- To what degree does energy trading help to establish a stable price by providing liquidity for aggregate trades vs profit seeking?
At Digital Wind we are exploring these questions as part of our ongoing research into current renewable electricity markets which will be accounted for in the financial products we will soon be offering to market participants. That said, we will touch upon some of our initial hypotheses and solutions for the general public in this article.
These questions may understandably raise some concerns regarding the feasibility of current RES/RPS goals for the industry at large. However, before we discuss possible solutions, lets examine the subject in more detail: a paper by Wood Mackenzie released this year that gets at the root of the issue with risk pricing in available offtake contracts in the form of PPAs:
Here we see an illustration of how PPAs (i.e. offtake contracts) are priced. First, they perform a price model derived from energy futures (i.e. the current market price for the delivery of energy, in any form, at a given time in the future), and power price forecast models (i.e. statistical or machine-learning based predictions). Next, we see there are several “adjustments” made, the largest of which are attributed to shape risk and price risk respectively. The proportion of adjustment is likely to vary, but from this article we can estimate its significant — roughly 20% or more is deducted for price uncertainty alone and we can likewise assume that the larger the shape risk and price uncertainty, the larger the deduction. After these initial deductions, there are additional industry calibrations to the PPA made to account for miscellaneous corrections such as aggregate corporate demand, levelized-cost-of-energy, contracts-for-difference etc.
These deductions/adjustments make sense from within a certain framework that assumes a linearized cost/price of energy. However, this assumption is largely incorrect. Energy prices are not linear either in terms of cost or in terms of price. To explain, we must go back to Economics 101, and view offtake contracts through the lens of a cost curve. A cost curve for energy tells us how much in dollars we can expect Financial Liquidity Providers (FLPs) to pay in the form of an offtake contract (FLPs acting on behalf of consumers or utilities themselves) if offered a given aggregate amount of energy from a multitude of producers (RCPs).
In the example above, a hypothetical single PPA is shown as the dashed green line in the lower left. This example PPA is priced in terms of [$]/[MWh] with the brackets indicating the digital representation of the amounts. The flat line implies that no matter how much energy is expected to be produced, in the given period of delivery, delivering any more or less than this amount of energy will not affect the price for the amount delivered. This is because the derivative d[$]/d[MWh] of the line (change in dollars to change in MWh delivered) is constant and equal to the price.
If we move this PPA line upwards to the right along the price-ratio line (yellow dashed line), it would match the high-liquidity PPA which only exists in theory as a combination of multiple PPAs all at the same price. In this case, the expected delivery amount of MWh is double that of the single PPA liquidity case (where the yellow dashed line crosses the green line). However, the derivative d[$]/d[MWh] is the same at all points meaning that there is no economy of scale or disincentive to deliver more or less than the expected amount. The “curve” therefore has the same meaning no matter where it is placed in the graph provided the slope of the line is the same. The price/cost ratio is thus invariant to the amount of MWh delivered (x-axis).
Next, we examined the two curved blue lines that represent a Distributed, Dynamic Hedge or DDH (i.e. our proposed solution at Digital Wind). Notice the dashed line curve in the lower liquidity case (think single wind farm) is more concave than the solid line curve in the higher liquidity case. The derivative d[$]/d[MWh] is the same only at the yellow dashed line representing the price ratio of $ to MWh between the two scenarios. Any deviation from the expected price ratio line results in a distortion of the derivative d[$]/d[MWh] vs the flat PPA line. This implies that delivering more than the expected amount is regressively incentivized (i.e. the RCP is incrementally paid less and less per additional MWh delivered) while delivering less than the expected amount is progressively disincentivized (i.e. the RCP is incrementally penalized more and more per MWh not delivered).
If we follow the price ratio line from the low liquidity to the high liquidity case we notice a fundamental feature of the DDH — the increase in overall liquidity results in a flattened price/cost curve. The more liquidity offered at the same price ratio, the flatter the curve approaching a PPA. Any deviation from the expected price ratio (for instance if the expected energy is exceeded or under-delivered) results in a “price slippage” or a change in d[$]/d[MWh]. A DDH is thus invariant to the price with respect to a constant price ratio where the derivative d[$]/d[MWh] is equal to a specific PPA price only at the point of the future expected amount of MWh to be delivered. There is a deviation from this price whenever the actual/projected amount delivered changes — the deviation is proportional to the overall liquidity. As such, it is price elastic and responds appropriately to market supply and demand principles.
Understanding Asymmetric Risk in Energy Hedges
Finally, we examine the case of the energy hedge illustrated as the dashed grey line. The energy hedge is peculiar concerning cost/price in that the same amount is paid irrespective of what was delivered under most conditions — this results in a horizontal line at the price offered for the fixed volume. The main condition is that the hedge volume of energy is to be exceeded during the given period which typically happens 90+% of the time. The amount paid by an energy hedge is thus invariant to the amount of MWh delivered under such conditions (x-axis). There is no price curve because there is no price outside of the hedged amount of MWh expected to be delivered.
A potentially costly scenario for the long side of an energy hedge (RCP) occurs when the hedged volume is not exceeded in actuality. In that case, the swap terms imply that the short side (seller of the hedge or bank) is owed back the amount equal to the missing volume at the coincident market price — a price that could be much higher due to regional scarcity of renewable energy at the time of delivery. This implication is not obvious but rather implied through the algebraic rearrangement of the swap terms which we will not examine here (please ask for our white paper for details).
Thus, the risk is asymmetric and hence it fails to qualify as a “hedge” which would imply offsetting risks for both the long and short sides of the contract. It is rather similar to a naked put option in traditional financial market terms — the hedge volume is similar to the “strike price” in that, if this amount is not realized, the risk to the long side is exponential. To illustrate this, we refer to the following chart from Investopedia demonstrating the profit-loss potential of a naked put. If we replace the “Strike Price” with “Hedge Volume” the profit/loss outcomes are nearly identical.
We can surmise from all this that offtake contracts such as PPAs and energy hedges lack price elasticity for supply and demand to incentivize the delivery of an expected amount of energy. To the degree that they are further adjusted to incentivize profits and stabilize the price, they require energy traders, RECs and contracts-for-difference adjustments which represent the overhead market infrastructure designed to ensure the price paid for renewable energy is within a predictable range. However, when combined, these structures are inefficient at allocating capital to energy as they come at a premium cost and lack seamless integration with existing forecasting services from long-term to short-tern. In many cases, these services and adjustments act as risk management attempting to de-risk and/or add additional “alpha” to the offtake contracts — contracts whose prices have already been deducted from to account for known market risks associated with renewable energy projects when there is an over/under delivery of expected volume.
A full spectrum breakdown of all off-take contract market risks is listed below:
1. Price Volatility Risk:
Renewable energy production, particularly from wind and solar, is highly dependent on weather conditions, leading to fluctuations in energy supply. This volatility means the short-term market prices (like the floating price in LMP markets) can swing dramatically.
- Impact on Offtake Contracts: To account for this price risk, utilities or intermediaries may offer producers a lower price in PPAs than would be possible in more stable markets. This discount compensates for the uncertainty in future energy prices based on the real-time variance in the difference between supply and demand. For producers, this means less immediate revenue, but the trade-off is a long-term stable price that shields them from extreme price dips in the spot market.
2. Shape Risk:
Shape risk refers to the uncertainty about when renewable energy will be available to meet demand. For example, wind may generate more energy at night when demand is typically low, or solar may not produce during cloudy days. This mismatch between aggregate supply and demand timing creates shape risk, especially for intermittent renewables.
- Impact on Offtake Contracts: Utilities managing this shape risk will typically incorporate a discount in the price offered to producers, reflecting the cost of balancing supply with demand — in other words, they make an adjustment for the net bias of supply relative to demand. In essence, the utility might need to procure additional energy (often from non-renewable sources) to meet demand when renewable generation is low, and this adds cost. Similarly, they may have to adjust demand (i.e. demand response) when renewable generation is high. This cost is factored into the PPA pricing structure, reducing the upfront price paid to the producer.
3. Credit Risk:
In some cases, renewable energy producers may face credit risk if their offtaker (e.g., the utility or corporate buyer) cannot meet their payment obligations over the long-term contract period. This risk grows as contracts are signed for longer durations (10–20 years).
- Impact on Offtake Contracts: To mitigate this, offtake agreements often include premiums for securing a reliable buyer, which can impact both the price the utility offers and the overall contract structure. Buyers with higher credit ratings will likely pay lower premiums and get more favorable rates, while buyers with more financial uncertainty may face higher contract prices.
4. Regulatory Risk:
Changes in government policies, including tax incentives, carbon pricing, or new renewable energy mandates, can significantly alter the economics of renewable energy projects. A sudden shift in subsidies or penalties could make an offtake contract either far more or far less valuable.
- Impact on Offtake Contracts: To hedge against regulatory uncertainty, offtake contracts often factor in this risk through flexible pricing clauses or require a higher price to cover potential future regulatory shifts. The result is a higher PPA price, with buyers paying a premium to lock in energy in uncertain regulatory environments.
5. Liquidity Risk:
Especially in early-stage projects or emerging markets, liquidity gaps may exist in energy trading markets, meaning that not enough buyers and sellers participate to stabilize prices. This creates liquidity risk, where buyers may find it difficult to hedge their positions or producers might struggle to sell all their energy.
- Impact on Offtake Contracts: Somewhat counterintuitively, a lack of liquidity will often increase the price of a PPA, as utilities or buyers will demand higher compensation for the risk that they won’t be able to resell the energy — i.e. the consumer or government is charged for the oversupply vs the producer. This liquidity premium is usually passed down in the form of higher rates in off-take contracts. Such policies help explain why PPAs were so generously priced in the early days of renewable energy projects such as wind farms in the early 2000s. At the time, market demand for renewable energy was too thin/illiquid to stabilize a forward price in anticipation of future market growth. Hence higher prices were offered by utilities on behalf of federal entities willing to subsidize wind and solar energy as a reward for creating aggregate renewable supply — in other words, it was a market-making incentive.
In conclusion, risk pricing affects both the price that producers receive from PPAs/energy hedges and the price consumers pay, with utilities/banks acting as intermediaries to manage and distribute such risks. Producers often accept a lower price in exchange for stability, while buyers may pay a premium for fixed long-term rates — i.e. “risk off”. The better the market is at managing and mitigating these risks, the more favorable the pricing becomes for both sides.
In general, in emerging or volatile markets using economic dispatch, risk pricing can add substantial costs to renewable energy contracts. Due to the increases in RES/RPS quotas, most energy markets in developing countries with a large portion of renewable energy in their supply stack are becoming increasingly volatile due to large variances in the projected differences between supply and demand that are associated with such quotas.
Lastly, as mentioned regarding liquidity pricing, renewable energy can also be priced “risk-on” as a premium supplier and market-maker in nascent, thinly traded or illiquid markets when demand does not yet exist simply to bias the market towards future consumption in anticipation of market growth. It all depends on the maturity of the market and appetite for renewable energy. This need is reflected in the lower end of the cost curve of a DDH when supply is low and the price ratio is high thus incentivizing full market participation.
At Digital Wind, we believe there is a better way to manage these risks: if price elasticity is reflected in the offtake contract itself, via a DDH, far more of the price, shape, and credit risk can be managed upfront. We further hypothesize that many of these services can be automated per a smart contract run off a blockchain. In upcoming articles, we will describe how P2P markets work and how a DDH can help to distribute price risk among its participants by functioning as a distributed, multilateral, and fully automated P2P service.
