Strategies to save energy costs

What would the benefits have been, with spot exposure and Demand Response, in SA for January and February 2016

What would the benefits have been, with spot exposure and Demand Response, in SA for January and February 2016

1 January 2016 was the start date for the new “high price” contracts for SA business consumers that renewed their retail supply contracts in the second half of 2015. Quite a few consumers decided not to lock in the high fixed retail pricing but instead adopt a pool price pass-through arrangement with an accommodating retailer.

So how would have those consumers fared over the first two months of the year?


Figure 1 – Time Series Plot of SA Half-hourly pricing 1 Jan – 28 Feb 2016 (Data source: NEM-Review)

Figure 1 shows a time series plot for every half hour interval for the first two months of the year (excluding 29th February – the day of writing this article). It can clearly be seen that there was one “scary” spike above $5,000/MWh in mid January and several smaller spikes around the several hundred dollars per MWh at that time. The popular misconception about being exposed to the pool price was that that one half hour interval would have been disastrous had the consumer not be able to shed load during that period or if they didn’t have a price cap (financial instrument) in place. It is not disastrous at all as can be seen in Figure 2. Most of the time the half hour pricing is well below the fixed retail pricing and so the average is well below the fixed retail pricing.


Figure 2 – Box Plot of Half-Hour Prices in SA Jan – Feb 16 Excluding Outliers

Figure 2 shows that just 3 days in the two months had an average daily price (indicated by the connected symbols) above the typical fixed flat retail price of approximately $91/MWh (derived from recent price offers of Peak 11c/kWh and Off-peak 8 c/kWh). On a very high proportion of the days the average price was at or below 50% of the fixed retail price. This resulted in the following pricing results:

  • Over the first two months of 2016 the average SA spot price was $45.55/MWh (or 4.6 c/kWh)
  • The average spot price during peak periods was $64.95/MWh (or 6.5 c/kWh).
  • The average spot price during off peak periods was $33.84/MWh (or 3.4 c/kWh).

The savings over this period for a flat 1 MW load with a load factor of 100% would have been $64,772 versus the typical fixed retail contract. This would have been the savings had the consumer continued to run through all the high price events including the $5,000/MWh event and not shed load.

If that same hypothetical load (1 MW and 100% load factor) had been able to curtail its load during high price events then the savings would have been even higher as shown in Table 1.


Table 1 – Savings For Pool Pass-through and DR Strategy in SA Jan – Feb 16 (1 MW Flat Load)

Table 1 shows that the major savings came from a straight pool pass-through without DR and that DSM only provided modest additional savings. However, in this case there was only one price spike above $1,000. Had there been a greater number of very high price spikes obviously the savings without DR would have reduced and the savings with DR increased.

The 2016-2018 retail pricing is based around the Northern Power Station closing down shortly (scheduled for end of March, but there has been some talk of a bit later). The impact of this closure would therefore not be seen until the second quarter and probably not until the colder months of June and July.

There is much concern about what will happen to average spot prices once the Northern Power Station closes down (see also here for concerns during 2015, with Northern operating). The 2016 pricing would have been based on 2nd, 3rd and 4th quarter pricing being significantly higher than the 1st quarter. So it would be expected in our previous analysis that January and February average spot pricing was well below the typical 2016 retail offers.

So how can we construct a forecast for pricing once NPS closes? The answer is “with great difficulty”. The market is a competitive market and different generators either compete with each other to ensure that they are dispatched to meet their contracts and to minimise ramping load up and down or they offer uncontracted generation at high prices to make opportunistic profits. NPS is a coal fired power station and designed for operations at steady load. They bid low prices to ensure they are dispatched to meet their contractual requirements. When they exit the market the only other base-load generator left will be Torrens B which is a gas fired reheat boiler generator. Boilers are also typically designed for steady operation and so, to the extent that it is contracted, it will likely bid in low prices to ensure the contracted generation is dispatched without having to cycle up and down. The Torrens B plant has four boilers and so it will likely run the required number of boilers to meet its contracted demand and price the uncontracted capacity at very high prices, as it does currently.


Figure 3 – SA Half-hour Generation Load (MW) By Type Jan – Feb 2016

Figure 3 shows that NPS output was typically 400-500 MW over January and February. After March this generation will disappear from the generation mix and the gap will need to be filled by Torrens B (Gas Reheat Boiler), interconnector flows from Victoria, Combined Cycle Gas Turbine (CCGT) and “top ups” from Open Cycle Gas Turbine (OCGT), particularly when the wind isn’t blowing. AGL have announced the mothballing of Torrens A, which has really been acting as a peaking plant.

There will be two major impacts from this change:

  1. Torrens B will have a significant increase in market power being the only base load generation left. They are likely to increase the median half hour spot price by setting higher bid prices for offered generation and possibly withhold some available capacity (bid at very high prices) to facilitate price spikes.
  2. During periods of high demand and/or low wind the peaking OCGT and diesel will be required to meet demand resulting in an increase in the number of very high price spikes and an increase in the average price.

Without doubt, prices are going to increase and the retail offers reflect that reality. The question is by how much?

I have attempted, without success, to build regression models for pricing based on the generation mix, demand and wind. I therefore analysed the SA data over 5-years using data from NEM-Review to compare pricing when NPS was running and when it was not. The results were:

NPS Running NPS Not Running
N = 76,911 N = 10,737
Average Price = $47.20/MWh Average Price = $71.54/MWh

Table 2 – Impact on SA Spot Pricing With and Without Northern Power Station Operating 2011-15

The data is made more complex by the fact that there was a carbon tax in place between Jul 2012 and June 2014. The carbon tax increased average spot prices by $25.80/MWh when comparing the same set of data with and without the carbon tax.

The difference in pricing without NPS running was an increase of $24.34/MWh (about the same as the carbon tax) or a 52% increase. The retailers have factored in an almost 100% increase. Using this method we could estimate a future expected spot price annual average:

  • 2015 Average $49.58 + $24.34 = $73.92/MWh
  • 2015 Average $49.58 x 1.52 = $75.36/MWh

I also applied another method where I built a matrix of SA 2015 actual data with low, medium and high wind generation and low, medium, high and very high demand and determined the average price for each quadrant and the number of half hour intervals that fell in this quadrant. I then “shifted” demand by adding the actual output of NPS to each historical half hour demand and rebuilt the same matrix for the higher demand level and calculated a new weighted average price. Using this method the new forecast price with a shift in demand to the right was $75.68/MWh.

So my “peg-in-the-ground” forecast for annual average prices post NPS closure is around $75/MWh. I would encourage others to attempt to forecast their expectations for pricing to open up a discussion.

If SA annual spot pricing does settle around the $75/MWh mark, the savings for the hypothetical 1 MW flat load versus the current retail pricing would be of the order of (91-75) x 24 x 365 = $140,000 per year without any curtailment. I would rather those funds going to the business bottom line rather than the retailer.

If you would like to find out more about development and implementation of a pool pass-through strategy with and without DSM contact me at This email address is being protected from spambots. You need JavaScript enabled to view it.

The Levee Has Broken in SA – Save Yourselves By Jumping in the Pool

The Levee Has Broken in SA – Save Yourselves By Jumping in the Pool

I have written previously about the coming energy cost tsunami in WattClarity Well, the electricity levee in South Australia has finally broken after severe cracking and the resultant tsunami is now swamping business consumers coming out of contract in 2016. Prices have almost doubled from the already high level they had been previously and customers weren’t expecting it.

Figure 1 shows the Calendar Year 2016 base futures price history up until 31 October 2015. Businesses that negotiated with retailers and locked in an agreement in the first half of 2015 received pricing not too dissimilar to the previous year. Those businesses in negotiations in the last quarter of 2015 were subject to pricing offers 180% - 200% higher and were forced to make a hard call on what term they locked in. Some customers were able to negotiate terms as short as three months to wait until there was potentially more certainty in the market. Other locked in just one year.

Consequently, many customers were incensed at the increase and asked if there was another way of buying electricity to reduce their costs.

Well, there is. Avoid the worst of the tsunami by jumping in the pool.


Figure 1 SA Base Calendar Futures 2016. Source:

What is Happening in SA?

On the 11th of June 2015, Alinta Energy announced it would be closing the Port Augusta coal-fired power station at the end of March 2018 and possibly as early as the end of March 2016. This resulted in an increase in electricity futures price for the 2016, 2017 and 2018 calendar years. At the end of July 2015 it announced the closure would be no later than the end of March 2017 and on the 7th October, it announced that the power station would close at the end of March 2016 causing the jump in 2016, 2017 and 2018 futures prices in October 2015.

While the exchange traded SA electricity futures shown in Figure 1 are quite thinly traded; they do give an indication of what is happening with bilateral contracts between market participants. The fact that SA’s only coal-fired base load power generator is closing means that it can no longer offer contracts to other retailers, thus exposing them partially or completely to the spot market price.

The tightening of domestic gas supply is likely to cause an increase in both gas prices and volatility. Also, the high reliance on gas-fired generation, the intermittent nature of wind generation and the concentration of market power to one dominant generator means there is a very high level of uncertainty in SA electricity prices over the next three years and it's the customer who'll end up paying for that risk.

A customer buys electricity from a supplier (retailer) who then quantifies the various risks in supplying that customer. That customer can use more, or less power than they have used historically, they can modify their load profiles by using more or less electricity at different times of the day or days of the week or they can go out of business.

The retailer enters into contracts to try and best match their forecasts of their entire portfolio of customers but obviously, it is impossible to match the customer portfolio demand exactly. The retailer needs to quantify the risks and then assign the costs of those risks to the customers.

In simple terms, the price that the customer sees is:

Retail price = contracted energy price + uncontracted price risk premium + volume risk premium + load profile risk premium + retailer margin

The sum of the risk premiums can be significant and in the case of South Australia at the moment they can be enormous.

What Is It Like At the Deep End of the Pool?

Many customers are increasingly pocketing the risk premium themselves by buying electricity at the spot market price (pool price) and managing their own risks by employing Demand Response, a form of Demand Side Management (DSM).

For 15 years, there have been a small but growing number of electricity users purchasing their electricity at the half-hour pool price. Initially, these companies entered into these arrangements with great trepidation due to the perceived high risk of exposure to the maximum price cap at the time of $5,000/MWh (now $13,800/MWh). In time, they found there were very few half hour periods at this level, if at all, and these high price events still did not push the annualised spot price above the fixed price retail offers they were getting.

Most of the half-hour periods of each year approximate the short run marginal cost (variable cost) of generation of the last generator required to be dispatched to meet demand.

If demand is low, then low variable cost coal-fired generation is the dominant form of generation and the spot price reflects that low cost. When demand is high and coal-fired and large efficient gas generation can’t meet demand, then high variable cost generation is dispatched to meet demand (open cycle gas turbine and diesel).

The price spikes add up to increase the average annual price to theoretically reflect the long-run marginal cost of the base-load generator. In simple terms, most of the large generators only just cover their variable costs through most of the year and then rely on the price spikes to eventually recover their capital cost.

This provides an opportunity for the smart electricity consumer. If they purchase electricity at the half hourly pool price and avoid the inevitable low frequency, short duration price spikes through load curtailment (Demand Response), they can achieve very low annual electricity prices.

Figure 2 shows the actual annual time-weighted average spot price for South Australia for 17-years, along with an indicative approximation of fixed price retail offers in the market over the same period. Ignoring the market commencement year before large customer contestability, there has only been one year in 16 where the spot price came anywhere close to fixed retail prices. That year Australia was in the depths of a major drought and any generator (hydro or coal) using fresh water, reduced their output. It was a challenging year for those exposed to the spot price, but only because they had to pay what the vanilla retail offers were asking. In other words, the worst-case outcome is close to the low risk fixed retail price. Armageddon isn’t as bad as it is made out to be. The graph also puts the current 2016 retail prices in an historical context. Price offers are significantly above anything that has been over that 16-year period.


Figure 2: Historical average annual spot prices (data source AEMO) and general level of retail offers

Those consumers that had the ability to shed load during high price events were far less exposed to the time weighted annual high price. Most customers who employ Demand Response are able to achieve pricing outcomes 5-10% lower than the annual spot average by curtailing load during high price events.

Setting Up A Pool Price Pass-through and DSM Strategy

Before embarking on a pool price pass-through arrangement, it is important to understand how the market operates, the opportunities, the risks and the operational constraints. It is also critical to educate any staff and employees that are involved.

All businesses are different. Some operate 24/7 and any minor disruption has a high opportunity cost. Some businesses operate all of their equipment well under capacity and are not sensitive at all to short stops. Most are in between.

It is important to do a study on all of your major equipment. You will need to determine which equipment are bottlenecks (constraints), which are utilised below full capacity, the implications of shutting down a constrained asset for a short period, and the consequential break-even cost of shutting down. Some equipment cannot be shutdown at all; other equipment can only be shut down if stocks allow.

From this analysis, a load-shedding schedule can be constructed with a list of equipment to be shut down at different price thresholds. Some of these may have discretionary actions dependent on product stock levels or actions requiring escalation for approval before shutting down. Some businesses may choose to shut all equipment down at one price level, some will have different levels for different assets and some may choose not to shut down at all. If a business elects not to shut down at all, it will still likely see a 12-month average price at far less than their best retail offer.

When constructing the load-shedding schedule, it is necessary to have an understanding of the likely number of curtailment events and the duration of those events. Figure 3 shows a probability distribution curve for the half-hour SA spot prices over the two calendar years 2014-15. It shows that 99.5% of all prices were below $299/MWh and 95% of prices were below $74/MWh.


Figure 3: Probability Distribution Curve for the half-hour SA spot prices 2014-15

Another way of getting an appreciation of the distribution of half-hour spot prices is to plot on a histogram as in Figure 4. Note that the progressive change in the size of the price buckets for the histogram as prices increase. Quite clearly it can be seen that most prices are distributed below $100/MWh with a long tail of high prices beyond $100/MWh.


Figure 4: 2014-15 SA Half-hour Spot Price Histogram

So let’s have a look at what would have happened over 2014 and 2015 had a business been a 1MW flat load running 24/7 and exposed to the pool using DSM to manage risk. We'll assume perfect price forecast information and perfect load shedding execution.


Figure 5: Theoretical Savings at Different Price Thresholds for a 1 MW Flat Load

If the business did not curtail any load and were exposed to the spot price over the whole 2-year period, then the average price would have been $48.85/MWh (or 4.885 c/kWh). This average price for all periods is fairly close to what a lot of customers paid for off-peak over this same period.

If the business had a plant that was not fully utilised and had a reasonable amount of downtime through the year, then they may have chosen to shed load if price exceeded $100/MWh. This would have required the equivalent of 10 full 24-hour days off and theoretically reduced the spot price by 18.1% giving a theoretical saving of almost $78,000 over the spot price.

If $1,000/MWh was chosen as the price threshold for all equipment in the 1 MW flat load plant, with perfect forecast information and perfect load curtailment, the saving that could have been achieved versus the spot price was nearly $46,000 per year and “only” required annual downtime of 40 hours. This was still a saving of 10.7% versus the spot price.

The level of operational interruption if load shedding occurred at $1,000/MWh is shown in Figure 6. Over a two-year period, 71 of the 81 high price events were only of a half hour duration. Only nine events went as long as 1-hour and one event of 1.5 hours. The impact of curtailment is often minimal when compared with other causes of plant stoppages.


Figure 6: Duration of High Price Events in SA > $1,000/MWh 2014-2015

These savings are theoretical though and assume perfect forecasting of all events and immediate load shedding. The final settled half-hour price is the average of six 5-minute dispatch interval prices. This means that if a price spike occurs in the last 5-minute interval of the half-hour, then the settled price for the full half-hour will be impacted by that last price.

Even if the business sheds load immediately at the start of the last interval, the hour half price will increase and the average load over the half hour would still be high. In reality, forecasts can’t predict sudden generator or inter-connector failures that cause price spikes and load shedding is not perfect. The table does, however, give an indication of the size of the prize if load shedding is employed along with spot price exposure.

In a real example of a company that I used to work for, the annual consumption was around 180 GWhs per year. The savings in taking a pool price pass-through arrangement enabled us to save around $3.8m per year versus the best fixed-price retail offer with an additional $1.5m savings per year by employing Demand Response. This gave us total annual savings of $5.3m (equivalent to 2.9 c/kWh). In this case, there were several price thresholds for different assets and some large equipment was not shut down at all.

Real time, accurate market information is crucial to a Demand Response strategy. NEM-WATCH is a great tool enabling the operations staff to monitor the market, prepare for high price events and get alerts in the event of sudden high price events. It provides an overview of what is happening across the entire network and a more detailed picture of what is going on in the hub where the business operates with regard to forecast and actual demand, price and generation mix including wind and solar PV.

Pool Price Expectations for 2016 - 2017

With the impending closure of the Port Augusta Power Station, it is expected that spot prices will increase. Certainly it can be expected that there will be an increase in the number of price spikes and also the median price would increase. The average annual price would be expected to increase. However, retailers have already factored this into their risk premium and assumed worst-case scenarios. The 100% price increases offered are likely to be highly conservative, from their point of view.

Figure 7 shows the impact on electricity savings with increases in the annualised spot price. Even with a 100% increase, there are still modest savings before employing Demand Response. Demand Response would increase those savings.


Figure 7: Impact of SA Spot Market Price Increases

Load Planning

DSM not only involves a strategy to react to high price events (Demand Response), but also includes planning ahead to shift load to periods that are expected to have lower prices, and avoiding maximum load during periods that are expected to have high prices. This can include organising scheduled shutdowns in periods that have a higher likelihood of high prices. Figure 8 shows that high price events occurred largely in the months of January and July during the 2014-2015 period, great months to schedule major shutdowns. Figure 9 shows how these high price spikes then impacted the average monthly price.


Figure 8: High Price events in SA > $1,000/MWh By Month of Year 2014-2015


Figure 9: Average Monthly SA Spot Prices 2014-2015 (excluding outliers)

Figure 10 shows typical price distributions over the 2014-2015 period (excluding outliers). By maximising load during the night and minimising load during the day (particularly late afternoon and early evening), the average price can be reduced. Scheduling short maintenance outages on major equipment in the afternoons rather than back shifts can help achieve that outcome.


Figure 10: SA Half-hourly Spot Price Distribution By Time-of-Day (Excluding outliers)

Call To Action

Pool exposure and DSM is not for all businesses. Some businesses require absolute certainty in their cost inputs even if they are sure to be at a higher price. For some, the savings may be too small to spend time and resources in setting it up. Others may not be able to tolerate the risk or potential fluctuations in monthly bills.

For those businesses with significant electricity spend and are in the relentless pursuit of finding cost savings, a pool pass-through arrangement coupled with a DSM strategy may deliver significant savings.

If you are interested in employing a pool/DSM strategy to reduce costs and wanting to get a better understanding of the risks and potential rewards then contact me at This email address is being protected from spambots. You need JavaScript enabled to view it.

As I said in the October 2014 article:

“When the levee breaks, mama, you got to move”

To help you “move” contact Altus Energy Strategies at

When The Levee Breaks - 8th October 2014

When The Levee Breaks

Recently there have been many news stories and conference papers calling for the Government to save businesses from rising electricity and gas costs otherwise they will “go under”. In fact, all sectors of the Australian economy are starting to feel the effects of an energy cost tsunami coming towards them. The Eastern States are starting to see up a twofold increase in natural gas prices as a result of the burgeoning LNG export industry buying up domestic gas combined with a lack of competition (WA has already gone through a threefold increase). “Gold Plating” of electricity networks and the so-called Solar PV induced “Death Spiral” are conspiring to push electricity supply charges up. Overlaying all this is the policy objective of achieving reductions in CO2 emissions through the renewable energy scheme putting additional short to medium term costs on electricity.

Whenever I read these articles it reminds me of a song made famous by Led Zeppelin called “When the Levee Breaks”.

"When the Levee Breaks" is a blues song first written and recorded by husband and wife Kansas Joe McCoy and Memphis Minnie in 1929. The song is in reaction to the upheaval caused by the Great Mississippi Flood of 1927.

In the Led Zeppelin version the lyrics can be interpreted to have many meanings but I like to interpret it as a message to take action yourself to fix a problem and not wait for somebody else to do it such as the Government (because they wont).

"If it keeps on rainin', levee's goin' to break"

If gas prices and electricity prices continue to go up then businesses are going to be hit by a cost tsunami that’s going to inundate them.

"All last night sat on the levee and moaned, Thinkin' about me baby and my happy home"

Australia’s manufacturing competitive advantage over the last several decades has been access to low cost energy for electricity and process fuel. It is incredulous to us that we are losing that competitive advantage because we are exporting that advantage away to our competitors. We just don’t want to believe that it will happen, that the Government would let it happen and we think back to the happy past when energy costs were low and moan about our current predicament.

"Cryin' won't help you, prayin' won't do you no good"

This is my favourite line. Complaining about energy price increases and imploring the Government to do something about it isn’t going to do any good. The Government is not going to do anything tangible to reduce energy prices, certainly not in the short to medium term.

“When the levee breaks, mama, you got to move”

The message here is that you have to take action yourself to solve your problems, not wait for somebody else to solve them for you. Individual companies need to develop energy strategy to stave off the impact of the energy cost tsunami.

"Going, going to Chicago... Going to Chicago... Sorry but I can't take you..."

The smart businesses are already taking action. They know the “levee is going to break” and they are already taking action to reduce their exposure to the energy cost tsunami …. And they are not necessarily going to tell you what they are doing as they are planning to stay ahead of their competitors and watch them “drown”.

So what can be done to “move” and not be inundated by the energy cost tsunami?

First of all businesses need to develop an energy strategy with the vision of reducing costs or, at the very least, protecting themselves from the inevitable large cost increases. An energy strategy should consider at least the following topics to identify cost saving opportunities or abatements.

  1. Energy Efficiency
  2. Input Costs (fuel and electricity)
  3. Fuel Substitution
  4. Market Reform


  • Can you invest in new technology that is more energy efficient?
  • Have you audited your drives and quantified savings vs capital cost for more efficient drives?
  • Have you audited your compressors and quantified savings vs capital cost for more efficient compressors?
  • Have you conducted a compressed air leakage audit?
  • Do you monitor and control the electricity efficiency of your process eg kWh/tonne or kWh/unit
  • Have you quantified both network and energy cost savings when developing equipment upgrade business cases?


Process Fuel Mix

  • Can you vary the mix, convert to a different fuel, or develop alternative fuels? Many companies are already quietly adopting waste derived fuels very successfully
  • Do you monitor and control the electricity efficiency of your process eg GJ/tonne or GJ/unit


Input Costs

  • Gas Cost = Supply charges + commodity charges + retailer margin
    • Have you optimised supply charges for your load-factor? Are you paying too much for gas transport?
    • How much is the retailer margin? Can you do it cheaper yourselves as a wholesale purchaser of gas and cut out the middle-man?
    • Are significant cost savings achievable by allowing yourself to take a portfolio approach to gas purchases with one (or more) long term commodity supply agreements with the ability to buy spot gas though short term bilateral trades or from a trading market?
    • Can you partner with an explorer/producer?
  • Electricity
    • Electricity cost = Network charges + energy charges + environmental charges + other charges + retailer margin
    • Have you optimised network charges for your load profile ie ensure your maximum demand charges are not set too high?
    • Can you modify your load profile and get further reductions? Ie shift usage to off-peak periods
    • Can you take on exposure to the market price and eliminate the risk premium and the retailer margin?
    • Are you offering any Demand Side Management (DSM) and are you being fully rewarded for it?
    • Are you paying above the market for renewable certificates?
    • Can you build a business case for renewable energy supply such as solar, wind or small scale geothermal? If electricity costs are of a strategic concern then surely a 4-year pay-back should justifiable.

Market Reform

  • Are you a member of an energy user group that advocates market reform and rule changes to benefit consumers?

The author has helped several companies develop and implement Energy Strategy that have facilitated significant cost reduction, not just small savings here and there. These companies are staying well ahead of their competition and plan to be the last one standing.

Examples of successful cost reduction strategies include:

Electricity spot price exposure

A growing number of companies are taking exposure to the electricity spot market prices either directly by becoming market participants or indirectly by their retailers passing through spot prices for a management fee.

This means that the business takes responsibility for the market price risk rather than a retailer doing it for them and charging a risk premium on top of their retail margin for the pleasure of doing so.

Many companies can reduce their risk by monitoring live electricity prices through tools such as NEM-Watch and shed load if prices hit predetermined levels.

However, even if a business does not shed load, the annual average electricity price may still be lower than a retail fixed price offer. A smart business that actively manages its load can achieve very low electricity prices over the course of a full year.

One consumer with consumption of 180 GWh per year has estimated its savings to be $5m per year over ten years when compared with the best retail offers that it received when going to the market.

Gas Market Participation

A small number of large industrial gas users are gas Short Term Trading Market (STTM) participants. This enables them to significantly reduce their gas prices compared with fixed retail vanilla gas supply contracts.

An industrial gas user can contract for a proportion of their annual gas requirements with a producer or retailer on a commodity only basis and purchase their remaining requirements either through short term bilateral trades with other market participants or directly from the STTM. This enables the business to both manage its take-or-pay volume risk and also to achieve lower overall portfolio pricing.

STTM self contracting users can maximise net purchases from the STTM when gas prices are lower than their contracted gas prices and minimise their STTM net purchases when prices are at or above their contracted prices. They can even sell gas into the STTM if they have capacity available and STTM prices are above their contracted price.

STTM gas prices can be monitored using tools such as GAS-Watch to determine daily bidding strategies. STTM prices have been observed to be anecdotally $1.00 - $2.00/GJ below long-term end user contracted prices. A 5 PJ per annum gas consumer that purchases 20% of its requirements from the STTM when prices are low could be expected to conservatively save $1m - $2m per year.

Tariff Optimisation

There are often significant savings to be found in optimising supply tariffs. Often a gas retailer will look at historical gas demand data for a customer and then offer supply charges based on what it assumes the customer’s load profile will be during the contract period. The retailer is exposed to gas transport and distribution charges and seeks to fully pass these through to the customer. Important drivers of supply charges are maximum daily quantity (MDQ) and load factor (average daily quantity divided by MDQ). Consumers should analyse their own load profile and seek ways to minimise MDQ and maximise their load factor.

With electricity supply it is a little different in that the retailer passes though network supply charges rather than making a risk adjusted estimated of likely supply charges. The main driver in electricity supply charges is Maximum Demand (the maximum half hour load during a full year).

Network supply charges have increased dramatically over the last decade and are often now up to 50% of the total cost of electricity. This means that Maximum Demand is a major driver of the overall electricity price. The good news is that more often than not there is potential to reduce significantly Maximum Demand charges.

Consumers should analyse their load profile to determine whether the Maximum Demand charge is set at a level well above their actual Maximum Demand. If so, they can apply to have their Demand Charge reduced. The real opportunity in the load analysis is to determine what is driving the Maximum Demand level and identify methods to flatten the load profile and reduce Demand charges.

One client that I worked with discovered that their Maximum Demand was being driven by when they were recharging their electric forklifts. Another found that they were turning on all of their equipment in the morning at the same time. Until the load analysis was conducted they had no idea that this was driving their supply costs costs up.

Alternative Fuels

There are a few Clients that I work with that are leaders on the use of waste derived alternative fuels. They use this alternative fuel to displace gas and reduce overall fuel costs. Alternative fuels include processed waste wood, waste plastic, waste oil and landfill gas. There is also technology that is fast approaching commercial feasibility to produce synthetic gas from municipal waste. There are already commercially viable facilities in place to generate electricity from municipal waste.

Fast moving companies will get ahead of their competition if they secure these waste derived alternative fuels on a long-term supply basis.

Energy Efficiency

Energy efficiency initiatives are some of the easiest yet most neglected methods for reducing energy spend. The initiatives range from low cost compressed air audits to high cost equipment upgrades such as motor replacements. Quite often capital investment decisions these days require a pay-back of less than two years. However, if energy costs are a strategic issue then longer term payback periods should be considered. It is important to include the cost reductions that are achieved with a reduction in maximum demand along with the energy consumption savings when justifying an equipment upgrade.


If energy costs are a large proportion of a business’s overall costs then they should be approaching energy on a strategic basis. Gas and electricity should not be managed by simply tendering to the market every three years and then negotiating around the lowest price retail offer. Businesses should be developing Energy Strategy to stay ahead of their competition. This involves understanding how your business uses energy, where it can be optimised, what the market is doing and where you can take advantage of the market with your unique load profile.

Energy costs are rising rapidly and the energy cost tsunami is about to hit us all.

“When the levee breaks, mama, you got to move”

To help you “move” contact Altus Energy Strategies at

To help you see what’s going on in energy markets contact Global Roam

For a great cover of Led Zeppelin’s “When the Levee Breaks” go to