By Bill Schneider
“My own personal experience turned me from being ‘mildly agnostic’ about intermittent renewable power to being a strong opponent of such schemes. And outside of some ephemeral political argument about ‘saving the planet’ … intermittent power schemes, whereby the generation capacity is linked to either a regional grid or large power user that relies upon predictable energy, should be avoided at all costs.”
This is an energy story, a personal one – and it begins back when I first saw the option on my utility bill while living in a suburb of Boston back in 1999. I could elect to pay more for “green” power, about 20 percent more. “Buying a cup of coffee to save the planet” seems reasonable. I checked the box.
This was how an “Average Joe” thought~23 years ago. By some reckoning, that’s an entire generation. Since then, media have literally carpet-bombed the internet, airwaves, and print, with story after story after story of how, if we don’t DO SOMETHING!!!™ the world will heat up, the oceans will rise, and all the poor island nations in the Pacific will flood and cease to exist.
My views have changed a lot.
So how did I go from being mildly agnostic towards the notion of man-caused
global warming climate change – but still friendly towards various “green energy” schemes such as wind, solar, and tidal power – to become a staunch defender of dense energy, including <shudder> fossil fuels? And a foe of items labeled “green energy” by media and advocates?
A Wind Power Project
In early 2008, I was asked by the Asset President of the steel mill I worked at in New Zealand to review a proposal for a PPA (power production agreement). At a high level, the proposed PPA was straightforward. Key terms included:
- Term: 15 years, with renewal clause
- Cost per delivered MW: NZ$79, with escalator clause
- Supply basis: take or pay, 100% of generation site power
- Proposed generation site: 21 turbines at 2 MW nameplate capacity each, total nameplate capacity 42 MW
- 12-month wind study result: “less than pristine” ranking; anticipated annual average generation capacity, 14 MW
- The task was deceptively simple: review this proposed PPA.
100 MW total demand, sourced as follows.
- 60 MW delivered from two melter gas-powered cogeneration plants
- 20 MW contracted under a hedge agreement
- 20 MW remaining, sourced via the spot market
The 14 MW average capacity from the proposed site seemed like it would be able to replace the spot requirement, with a little left over that would have to be onsold to the grid. Easy! My company gets to tick the box of being seen to support renewable energy. Oh, and the site the wind farm was to be built on, was adjacent to a mine site that the company leased from indigenous people (Maori) and was owned by the same people that leased the mine site.
Let’s review how the stage is set.
- At 100 MW power demand, the mill was one of the largest power users in the country
- Political pressure from government for large energy users to support renewable power was palpable
- The generation station development site was owned by an indigenous group from which the mill also leased a mine site (more political pressure to ink a deal with the PPA developers)
But that starting price is far higher than the site annual average. I started reviewing the proposal documents, instantly realizing I needed help.
Wind Project Review
I engaged two knowledgeable folks: one who had worked at the site for 16 years and was available to consult on the project from a site demand perspective (“internal demand consultant”); and another who had experience in both building and operating various types of generation stations (“external supply consultant”).
Each of us tore into our respective portions of the proposal. I reviewed commercial terms, and the two consultants reviewed project risk, cost risk, and supply risk issues. A persistent pair of headaches were pricing & escalator clauses, and security of supply risks. This review took almost four months to complete and included several meetings with the developers of the wind farm (the same folks who proposed the PPA to my employer).
Problem 1: “Sole Client” and “Take Or Pay” From a commercial perspective, being the only “customer” to a seller comes with significant risk. What happens if the seller experiences financial or operational challenges? From an operational perspective, we’d go back to buying on the spot market. Politically, however, the seller would be tied to us, like a David being tied to a Goliath (for anyone reading this who knows about the ANZ Bank/Opes Prime incident that happened in Australia during the GFC, you will of course relate). So perhaps this arrangement could be considered to be operationally “ok”, but politically it carried a considerable negative in the court of renewable energy public opinion.
Next, let’s consider the requested contract term, 15 years. The proposed power purchase agreement (PPA) is a long-term one, where my company has been solicited to purchase all of the energy the counterparty has to offer – on a “take or pay” basis. For those of you who are not familiar with the contract term, this means that if the seller has electricity to offer, the buyer must either buy all that is offered or pay the value of what was offered but not accepted, at any given time. Therefore if the generator is offering all 42 MW at a particular time and the site cannot accept more than 20 MW (given the other supplies and obligations listed above), we would either have to onsell it or else pay for the quantity that we were not able to accept.
If we do not accept all the available electricity generated by the supplier at a particular time, we pay out for energy not used – potentially a significant overspend issue – and if we do not receive enough energy (again at a particular time), we have to source it from the spot market. Or, we could accept the surplus energy and attempt to onsell it, quite likely at a significant loss.
In any case, this means we would have to employ a person who would manage power deliveries and possible sales against this PPA, or else risk paying significant fees where “too much” power was generated. Most regional grids manage power deliveries in five-minute increments or less, and of course, wind velocity varies. So on this issue alone, there would be significant potential for overspending and/or having to deal with overhead costs of at least one (1) FTE.
Problem 2: Generation Efficiency/Wind Profile What about that “less than pristine” ranking of the 12-month wind study? It meant that despite the wind farm generation site having a nameplate capacity of 42 MW, the annual average it could generate was ~14 MW. On an annualized basis, the capacity factor for the site was ~33%. Not very efficient, but the contract only requires the customer to pay for power delivered, right?
But the cost of building that facility has to be amortized across its anticipated power sales. A 33% capacity factor means that there are far fewer electrons to earn back the investment to the consortium and allow the developers to earn a profit – hence the high initial strike price.
Here’s where the next discovery comes up. Often, one sees wind farm developers and advocates claiming that wind is a good backup if other power sources fail (for baseload generators, this means that there is an “unscheduled outage” where for whatever reason, the generation station is supposed to be online but is not sending power to the grid).
But for the country of New Zealand, its baseload power was over 60% hydropower, in schemes varying from small river-based hydro all the way up to the massive Manapouri Power Scheme in the South Island near Fiordland. In 2008, at the time this proposal review was conducted, NZ was experiencing a significant drought, and spot power prices were >NZ$500/MW. Upon examination of meteorological data, our team learned that in New Zealand, “wind follows rain” – meaning, if it isn’t raining, the wind isn’t blowing much either.
Rather than being able to rely on wind acting as a reliable alternate source of power during drought conditions, it was statistically very likely that the proposed wind farm would not be generating much power during a drought.
Given that “wind follows rain”, our company would have been at considerable risk of being forced to pay contract rates for power generated from the wind farm far in excess of the 14 MW average, while losing practically every single dollar of these overpayments by selling into a flooded spot market. Oh, and don’t forget, that initial strike price included an annual escalation clause, which had no bearing on market prices.
Of course, this was because the project needed to make a profit for its investors, and even with an NZ government program that allowed it to treat costs as tax losses, a review of investment data showed that the project would not break-even for the first ~7 years of its existence, and would not be profitable at an investment level without government tax subsidization until the end of the contract term.
Final note: when our team met with the developers, we asked them what they were prepared to do (if anything) to manage downside supply risk. The one and only answer we received at each discussion was a variation of, “well you can always buy power on the spot market”.
For the “privilege” of buying renewable energy, our company was going to have to manage the following costs/risks:
- High initial strike price, with annual price escalation (and the initial strike price was “significantly higher” than either the cogen power contract, the hedge contract, or the long-term average spot price)
- A “less than pristine” wind source that on average would generate ~33% of nameplate capacity
- A “take or pay” clause that could, in five-minute increments, have our company paying for anything between 0 MW supply and 42 MW supply, where anything less than 20 MW would have us exposed to buying on the spot market, and anything in excess of 20 MW would have us exposed to selling into the spot market (or else just paying for power that we didn’t use)
- Managing wind power supply shortfalls in a spot market that would be driven up by lack of rainfall
- Employing an FTE to manage deliveries and purchases/sales from undersupply or oversupply
- Zero responsibility on the PPA counterparty to assist with oversupply or undersupply
Political Correctness Issues
But saying “no” to the proposal came with both renewable power political risk and indigenous relationship political risk. So there was no way our team could suggest the company simply decline. The company was a member of the NZ Major Users Energy Group (MEUG), comprised of the country’s largest energy users. MEUG members were under enormous political pressure to support renewable energy.
Yet as was alluded to above, the proposed strike price of this PPA was far and away “out of the money” (which in those several discussions between our team and the developers, the latter flatly refused to budge on either strike price or cost escalator metrics, citing this pricing as absolutely necessary for the project to gain financing from investors).
Truly, we were in a bind. But we had to deliver a recommendation to the Asset President that would both split these very fine hairs, and at the same time be something that would gain approval from him and his leadership.
And recommending “Yes” to the proposal, or recommending “No” to it, was not in the cards.
This quandary is a classic negotiating challenge, where at first glance one finds themselves in the strange position of neither a negotiated proposal nor a BATNA being achievable. So our team turned to see where we could potentially create leverage despite not having anything obvious.
Planning the Escape
The team began with the fundamental question, “Why Our Company?” Why not anyone else?
The answer: because there was no other single company in the region large enough to be able to take that much power (assuming of course, their site was generating at or above the wind profile projection).
Approaching us was therefore not only logistically easy (selling 100% of their generation to one customer) but also had the perceived “insurance” of our site being a large enough power user to be exposed to the political risk of not being “seen to support renewable energy”.
In that regard, the site selection was equally shrewd, since their site would be leased from the same Indigenous group that our company leased a mining site immediately adjacent to that facility (side note: this facility was later sold in the wake of the GFC, but at the time there were no plans to offload it).
But consider: upon review of this situation, we surmised that the developers went to so much trouble to try to force my company to go along with the proposal, because, as it turned out, they had no other viable option:
- No other company large enough to stitch together a single “deal” in the region
- Demand and grid limitations and line losses meant that the developers would have to approach several other possible clients to sell their power if we said “no” to the scheme, and those smaller companies would neither face political/reputational risks of “saying no” to renewable power or generation from indigenous-controlled land
- Smaller companies would not be able to afford the asking price, which the developers absolutely had to codify in contract across the entire potential supply to gain funding
- And finally, selling into the spot market came at a significant downside risk over the long term (which was why my company allowed itself to purchase 20% of its requirements on the spot market)
Still, we needed something to provide cover to take advantage of this vulnerability from the counterparty, rather than “just say(ing) no”.
Enter the sole source/sole provider arrangement and “Supplier Management 101”: every single purveyor of supplier management and supplier risk management principles will say, in unison, that being a supplier’s sole source of income is never a good position to be in, especially as a larger company being the buying party.
I took inspiration for the counterproposal that I offered up to the Asset President from one of the famous Trials of Hercules: in this example, Hercules was told to drain a little cup of water. What Hercules did not know was, the cup was linked to the Seven Seas, so no human could possibly drain the cup.
So when the time came, I sat down with the Asset President and outlined a summary of all of the above, along with the possible political and indigenous reputational harm/risk that would go along with “just say(ing) no”, as well as with an acknowledgement that from both cost and security of supply points of view, neither could we “sign on the dotted line”.
Next, I outlined the developers’ position, as to why they were essentially married to our company as a client and no one else.
Finally, I requested his permission to offer up the following counterproposal, on the basis of avoiding the 100% sole customer risk.
- Our company would be willing to purchase 50% of power generated from the scheme
- We would honor the previously proposed strike price, price escalator, and take or pay requirement (of 50% of their generation)
- But with this caveat: they would have to on-sell the other 50% of their capacity first, and show us copies of duly executed agreements with other counterparties covering that entire 50% prior to our company signing up for the remaining 50%.
This counterproposal was approved by the Asset President, as stated above, as we were quite certain that the developers would never be able to meet the test contained in the caveat.
Outcome and Epilogue
In mid-Q2 of 2008, our team presented the counterproposal outlined above to the developers of the Taharoa Block C Wind Project. We shook hands with their team and left the meeting not long after.
An online search of this project will turn up several attempts to develop this wind farm, but to-date none have done so much as broken a single spade of dirt on the site.
As our team met with the developers of this project over the term of the review, it became clear to me that their entire business case rested on the presupposition that, as a large energy user, we would be forced to “sign here please” and essentially be the large corporate victim of a scheme of energy graft. Like so many proposals where companies are led to believe that “supporting” the current government zeitgeist (one can name any number of poisons here, from environmentalism to renewables to diversity) will give them some kind of reputational advantage, where the real advantage is limited at best and the downside – never talked about up front – is considerable (in both financial and reputational damage).
There are many other reasons why so-called “renewable power” – that is, intermittent power schemes where the “fuel” is purported to be “free” and “clean” but cannot be stored or controlled by humans – are unreliable and utterly wasteful as capital investment programs, except by various mandates and subsidies doled out by governments. Perhaps I will write more on these items in the future.
My own personal experience turned me from being “mildly agnostic” about intermittent renewable power to being a strong opponent of such schemes. And outside of some ephemeral political argument about “saving the planet” (that comes long on belief but very short on detail), intermittent power schemes whereby the generation capacity is linked to either a regional grid or large power user that relies upon predictable energy, in my opinion and experience, should be avoided at all costs.
Bill Schneider is a Procurement and Contracts leader with more than 30 years’ experience across multiple industry verticals and countries. With dual citizen of the United States and New Zealand, as well as a permanent resident of Australia, his career has involved assets owned and operated by Procter & Gamble, Boeing, Rio Tinto Aluminum, Bluescope Steel, BHP Billiton, and Glencore, as well as companies in the banking, power generation, and facilities management spaces.
A native of New Orleans, he originally studied Christian Education at East Coast Bible College as an undergraduate, later attending Tulane University to earn an MBA in General Management.
His comments represent his own opinions and not those of any company, contract firm, or client with which he may be associated.