QUESTIONS & ANSWERS

Automated DR is any measure that enables an automated response during the DR period. A thermostat would be one example. No human intervention is required. The utilities will typically pay the highest amount of DR incentives for automated DR measures.

Semi‐Automated DR is any measure that additional equipment (rewiring, dedicated switches, additional circuit breakers, lamps, etc.) is required to implement a measure that will make participation in a demand response event feasible and reasonable for the customer. An example would be putting in dual A/B lighting so that 50% of lighting could be shut off in a demand response event. It is manual in that human intervention is required, but it is automated in that it allows half the lights to be shut off that would not otherwise be possible. Human intervention otherwise, would be virtually impossible for shutting off only 50% of the lights.

Manual DR is strictly requires human intervention without changing the current system. An example would be having staff at a hotel go into each hotel room unoccupied to shut off HVAC and lighting. Utilities will pay the least amount of incentives for manual demand response measures. These are manual improvements/changes or customer behavior changes to existing equipment.

For a seasonal site the Customer Estimated Energy Baseline (CEEB) and Estimate of Demand Reduction (EODR), as described by Question 1 answered earlier do not apply. For the site described above, it is our opinion that the load that is available all summer should be added to a weighted seasonal average of available load in September.

Average Max kW = kW (available all summer) + kW (weighted seasonal average)

The weighted seasonal average of available load would be calculated by:

Weighted seasonal average load = (# seasonal Months available) / (Total utility’s summer months) * seasonal kW.

Weighted seasonal average load = (1/4) *(kW September ‐ kW summer month)

Average Max kW = kW (available all summer) + kW (weighted seasonal average)

A partial shutdown is perfectly acceptable. Utility companies have demand response programs that customers can participate in by simply shutting down for 2 hours during a demand response event usually between the hours of Noon to 6PM or Noon to 8PM depending on the program.

If the auditor identifies two different ways to reduce loads at two different times of the day (not overlapping) this is non‐coincidental loads and they cannot be added together when trying to determine how much load can be reduced.

Example of non‐coincidental load:

Reducing Air‐Conditioning reduced load 100kW from 1PM‐3PM

Reducing Lighting 50% resulted in 100kW reduced from 4PM‐6PM

The auditor should report the maximum load reduction of 100kW.

Example of coincidental load:

Reduced Air‐Conditioning reduced load 100kW from 2PM‐4PM

Reduced Lighting 50% resulted in 100kW being reduced from 2PM‐5PM

The auditor should report maximum load reduction of 200kW.

Again, that depends on careful evaluation of existing boiler(s). However, you may have the following alternatives in boiler efficiency improvements:

Boiler System Improvement Measures	Possible Efficiency Gain	Payback (years)
O2 Trim Packages	1% – 3%	4 – 11
Linkage-less Controls	0.5% – 1.0%	2 – 6
Economizers	2% – 5%	8 – 12
Flue Gas Recirculators	1% for 360 F incr. in combust air temp.	>10 yrs
Flue Dampers/Turbulators	1% for 360 F reduction in stack gas temp.	>10 yrs
Stack gas velocity reduction	up to 25%	< 2

You first need to make sure what the excess air amount is. Before I suggest anything on the boiler excess air, you need to ensure that the boiler load is matched at the proper firing level and that the boiler is cycling is not excessive (i.e. properly sized boiler). There are also so many other questions such as is the boiler properly sized for the load, was it commissioned when originally installed (if the boiler wasn’t adjusted for the load then it could be consuming as much as 30% fuel than it should)?, has there been any significant changes to load? Do you feel that the facility still need that type of steam or hot water production? Does the load vary significantly? Etc.. etc.. Having said all that all boilers should operate at the optimum excess air level. Please contact your licensed boiler service company for a further determination.

Yes. You will need to list it as “shut down refrigeration equipment” and also identify each component in an appendix.

Demand response programs require usage and/or interval data for a customer to participate. If the auditor wishes to proceed with a new construction project he should speak with the utility Program Manager if the new load can be made part of the utility’s demand response program.

Some utilities will allow the customer that is adding new load to the facility to participate in the program within 60 days of installing an interval meter.

Unfortunately, under the current DR program rules, program aggregation of service accounts for a given customer is not permitted. For this customer, they would be ineligible to participate in the DR program because each account must be greater than 200 kW to participate in the program.

Under the typical DR guidelines, the participation in a DR program is typically to customer accounts with interval data meters with demand of at least 200kW. Also, the demand from various accounts may not be aggregated.

Focus on both scenarios mentioned in the question.

TES is generally considered load shifting and not demand response. Typically demand response is the ability to respond to a trigger of some kind and reduce demand based on that trigger. TES systems are intended to remove load from the grid during all peak hours and not just during triggered events. While the on/off peak impact of TES is beneficial for the grid, generally, TES does not qualify as Demand Response.

Utility Considerations for TES:

1. There are no existing regulations approving the use of TES for Demand Response. However, this could change as these issues are currently being reviewed for future DR consideration.

2. There are possible exceptions to consider.

3. One exception may be if the TES is currently not being used at all. And the customer is willing to bring the TES on line only for DR purposes. Since demand response is based on providing day-ahead notices, the customer can charge their systems the night before to be used when needed during the peak hours on the following day. (The verification that the TES is only being used for DR purposes will be seen with the 10 day averages being used for baseline comparisons).

4. Another exception may be that the existing TES system is broken. The customer may possibly use the incentive to repair the system for DR purposes outlined in the previous answer.

6. Note that some TES systems are only partial storage and therefore only reduce partial loads.

If you are not already doing so, you may want to ask you pump contractor about using Ni-Resist impellers in place of bronze impellers. You will initially lose 1-2 efficiency points, but you will maintain a relatively higher efficiency over the life of the impeller. The impeller will also have a longer useful life.

Yes. There are many aspects within what is referred to as the “Energy-Water Nexus” which correlate energy and water to one another. Water is needed to produce the energy needed to distribute the water. But what does that mean? According to the EPA, every kWh of energy delivered demands the participation of 25 gallons of water.

A pump that sends treated water to your home is run on electricity provided by your utility. Let’s assume these kWh are created by a coal fired power plant, nuclear plant or a natural gas plant. All of these are combustion processes expelling heat to turn a turbine. This turbine then needs to be cooled, by water which is pumped in using electricity already produced. Power plants water use is shown in the table below in gallons per Megawatt-hour.

Furthermore, water is used in both coal and natural gas mining and extraction. Producing natural gas from shale requires about 0.6 to 1.8 gallons of water for every million Btu (MMBtu), less than 15 percent of the water needed to produce the equivalent amount of energy from coal (Chesapeake Energy, Media Resources: Hydraulic Fracturing Fact Sheet, 2009.).

What about transport of the coal or natural gas to the power plant? This uses diesel and gas, of which water is used in both the extraction and refinement processes! And for natural gas, booster pumps would be needed to transport the gas through the pipeline. And what do you think those booster pumps will be powered buy? You guessed it, more kWh created by the same process it is working to feed.

As you can see there is a significant correlation between water usage and energy usage. Even a small scale efficiency improvement will have a large ripple effect all the way down the line impacting the total water resource allocation for that gallon of water or kWh of energy you are using!

Source: ew3-freshwater-use-by-us-power-plants.pdf

While pump tests are the best indicators of pump efficiency, this information can be insufficient while dealing with a water distribution system. One of the indicators that can be used in these cases is total energy consumption per unit volume of water pumped. This metric is usually expressed as kWh/Acre Foot. This metric is very easy to keep track of since kWh and Acre Feet numbers are readily available. These numbers can be obtained without the need for specialized testing or equipment. For the CA region, well pumping falls within 700-1400 kWh/MG range. This is a rather wide range. There are a lot of factors which will influence system efficiency. Please consult with your local energy expert for further details.

As with a water distribution plant, water treatment plants have periods of high and low demand. During periods of low demand, VFDs can be used to slow down blowers to generate savings. Please refer to figure given below for additional details on a typical water treatment plant operation. As is evident below, water treatment plants have varying demands placed upon them throughout the day. In addition to this hourly variation of influent water in relation to the daily maximum flow rate for a given day, there is also variation of maximum flow rate experienced by water treatment plants.

While further opportunities are limited for agricultural or golf course type of customers, water districts have other potential areas where operational efficiencies can be improved. One of the biggest areas of improvement is in water treatment plants. Traditional water treatments plants use energy intensive mechanical aeration plants in aerobic digesters for water treatment. Newer plants make use of VFD controlled blowers used in conjunction with dissolved oxygen sensors. On a per million gallons per day (MGD) basis, blowers use much less power and hence energy when compared to mechanical aerators.

Installing VFD on pumps feeding water distribution lines allows tighter control of line pressure. Usually, amount of water pumped into a water distribution line is controlled based on line pressure. Using a feedback system with pressure sensors, VFD set points can be controlled to maintain required line pressure.

Sometimes, pumps are designed to operate in a wide range of flow rates. Therefore, the pump should be able to ramp up and down depending upon flow requirements. Motors powering these pumping plants are usually single speed, which means that pumps are also restricted to a single speed and cannot ramp up or down depending upon flow requirements. In such situations, the pump discharge is throttled to reduce pump discharge rate. Throttling is a very inefficient means of controlling flow rate.

Motors can be retrofitted with Variable Frequency Drives (VFD) to vary motor speed. By changing motor speed, pump speed can be varied. Pump discharge rate is directly proportional to the operational speed.

Having individual pumps in a system operating at good efficiency is only the first step in reducing overall plant consumption. Reducing total consumption can also be done by properly sequencing and staging pumps in your system. Usually a control strategy can help you realize more savings.

Pump test is the best way to gauge pump performance. Pump output is usually a function of it’s efficiency. By diligent record keeping of flow and pressure developed by pumps, pump performance can be gauged on a real time basis. This is not a substitute for a pump test, however, it is usually an indication of pump performance at a very high level. It is always a good idea to keep track of flow rate and pressure developed by pumps using properly calibrated meters. SCADA systems can automatically track this and many other variables encountered in a pumping system.

It is recommended that pump efficiency be checked with a pump test every two years

There two answers to this question. The first is that if your objective is to calculate utility incentives and the incentives are based on average rates, I would use the average rate since this is to your benefit. Second, if your objective is to accurately calculate the project energy cost savings for project feasibility and the utility rate changes with time of use or changes by the amount you use, I recommend then recommend for you to use the exact rate. By not using the exact rate, calculations may be off by as much as 30% that impacts the project payback significantly.

This is a very good question. The argument utilities will make is that the utility incentives are paid based on energy savings above a baseline standard. By merely switching to another fuel, you may not be saving any energy but merely replacing your fuel source. Fuel switching, however, is acceptable if the total fuel resource efficiency is improved as in the case of cogeneration in which a customer generates its own energy and uses rejected heat or hot water from the cogenerator for other purposes. So, the overall energy used by economical cogeneration is typically less than the utility generated power.

An Energy Advisor program is a strategic and a customer level program which provides energy efficiency analysis (usually performed by the customers by inputting energy usage details for their buildings) and provided options to reduce energy usage in buildings. Various utilities award their customers by paying them incentives to participate in these programs and by reducing their energy usage at peak demand times. There are various energy advisor programs focusing on both residential and non-residential building types and are a great tool which can provided customers with detailed information to improve on their energy usage thus reducing their utility bills.

The purpose of an energy audit is to analyze the energy flows in a building and to understand its energy performance dynamics. During an energy audit, the auditor looks for opportunities to reduce the amount of energy usage of the building without negatively affecting the performance parameters of the equipment’s such as lighting and HVAC load. Also, beyond simply identifying various sources of energy usage in the building, an energy audit seeks to prioritize the energy usage in order from the greatest to least cost effective opportunities/technologies for energy savings.

The process of conducting an energy audit can be very simple or complex depending on the type and level of calculations involved in the audit. First and foremost, the energy auditor obtains the annual energy usage bills for the building and then current energy data is monitored to create a baseline and establish what the current energy costs are. In the next step of this process the auditor conducts a space-by-space inspection of the building. During this inspection, the auditor examines energy consuming items (could be any plug load type for example lighting, HVAC or anything else) as well as areas that waste energy. With this new data obtained during the inspection the auditor then calculates the current energy usage and proposes new energy savings strategy and documents the findings into a summary report which is then provided to the customer

An Energy Efficiency program is a strategic/systematic system that continuously assesses and reduces the energy consumption (Both residential and non-residential) by implementing new technologies and by testing them in filed and by leveraging various utility level engineering and engineering firms to evaluate and determine best available technology options for their customers and provide technical supports to enhance market penetration.

There are usually three stages for each utility level energy efficiency program and each stage is delivered by respected community organizations and building contractors. The Three baseline stages defined per program are as follows:
1. Eligibility criteria and eligibility confirmation stage:

• All customers must provide proof of income
• Homeowners must provide proof of ownership
• Renters must provide the property owner’s written permission

2. Installation
Install appliances or implement other recommendations. The California Public Utilities Commission requires installers to:

• Meet or exceed existing codes and regulations (Title 24 and 20)
• Follow accepted building practices (LEED and other applicable titles)

3. Inspection/Audit
An inspection is performed before and after the installation of an energy efficiency project in the home/business development to confirm the baseline condition of the equipment prior to installation and new equipment following installation.

Yes, Pacific Gas and Electric provides an additional 10% incentive for Enhance Commissioning of Building Energy Systems. When your team is submitting the Pre-Application for the this project be sure to include a narrative of the Enhanced Commissioning plan to be considered for the additional incentive.

If your question is on the custom type of energy efficiency measures you are right on wanting to develop a robust calculation methodology that is reasonable and can withstand an independent review. Otherwise in a program based approach or even on single project basis your claimed savings may be substantially reduced. Check out the following robust process in developing energy savings estimates that Lincus applies:

1. Energy consuming equipment has a load profile and a performance profile. The load and performance profiles can be constant or variable. You need to consider the load and performance when estimating energy savings for a piece of equipment, especially when the load or efficiency do not remain constant throughout an entire year of operation.
2. You need to have a measurement and a verification plan for the load and performance following standard M&V methodologies for that specific measure. Typically, M&V cost should not exceed 10% of the energy saving benefit.
3. You also need to decide on your energy savings baseline above which you expect a reasonable savings. The baseline may be: a) replace on burnout, b) new load or equipment, c) retrofit add on and d) early retirement.

In general, energy savings calculations are done using either spreadsheet calculations or an hourly simulation model. Whether using spreadsheet calculations or modeling software, the energy savings are calculated by subtracting the post-installed energy usage from the baseline energy usage. This is presented in the equation below:

Annual Energy Savings = Baseline Annual Energy Usages – Installed Annual Energy Usages

When performing an energy efficient lighting retrofit an additional benefit is the reduced cooling load. On method for calculating the savings from reduced cooling load is shown below.

1. Determine the reduction in energy consumption by the lighting system. To do this you will need to know the baseline systems W or kW demand and the building schedule. The lighting schedule is where you will see the difference in load between building types. For instance a hospital emergency room (ER) that operates 24 hours a day, seven days per week versus a large office building that operate form 8 am to 6 pm Monday through Friday. If you were to replace a 60 Watt lamp with a 13 Watt CFL in the ER the difference in overall load would be as follows: ΔWattage = Baseline Wattage – EE Wattage = 60W – 13W = 47W

• kWh = ΔWattage x Annual Hrs of Operation / 1000 Watts/kW
• For the ER: 47W x 8760 hr/1000W/kW = 411kWh
• For the Office: 47W x 2607hr/1000W/kW = 122kWh

2. At this stage there are two applicable methods to calculate the interactive effects.

a. Use a previously calculated interactive effects ratio to find savings. For California the Database for Energy Efficiency Resources provides such interactive effects ratios. In this case the interactive effects are 1.17 for a hospital and 1.18 for a large office. To calculate the total saving from the retrofit the following equation can be used:

• Total kWh Savings = lighting savings (kWh) x Interactive Effects Ratio
• For the ER: 411kWh x 1.17 = 480.87kWh total savings
• For the Office: 122kWh x 1.18 = 143.96kWh total savings

b. Next you will need to determine what portion of the year is cooling season and continue with the steps below. One source for this information is The Advanced Lighting Guidelines from the New Buildings Institute.

 

3. Now you will need to determine the portion of the heat generated by the lighting system that needs to be removed by the AC system. A typical quantity is roughly 90%.

4. Determine the Coefficient of Performance (COP) for the HVAC system. To do this you will need to know EER or SEER for the system. Then you will use the following equation. A typical EER for existing units is 10.

• COP = EER/3.412
• COP = 10/3.412 = 2.93

5. Use the following formula:

• Savings from Reduced Lighting Load = Fraction of the Year of the Cooling Season x Heat Load from Lighting ÷ COP

Care should be taken to avoid over estimating or double counting savings. A good example would a project where heat pumps were upgraded to higher efficiency units and interior lighting was also upgraded. The calculations for the interactive effects between the lighting and HVAC systems should run with the new energy efficient heat pumps rather than against the baseline system. The savings from the HVAC retrofit will have already been captured in the calculations comparing the baseline heat pumps to the new heat pumps.

The total cost of an EM&V study can vary depending on many factors, including: the number of programs included, the amount of detail required, the types of measures implemented within the applications, the length of measurement required, the type of measurement required, etc. Depending on all of these factors, the cost of an EM&V study can be anywhere between about $10,000 and $100,000+.

Once all applicable program information is received, an EM&V plan can be put together in about four weeks. When the EM&V plan is put together and all other necessary information is received, the EM&V study can take four to twelve weeks to produced, depending on the length of measurement required. All together, a full EM&V study can be completed within eight to sixteen weeks.

Below is a graph showing the range of utility company levelized costs by measure/program. This data was taken from previous EM&V projects performed by Lincus. Using this graph and your own levelized costs, you can see how your utility company compares to others.

The Association of Energy Engineers has established the Certified Measurement and Verification Professional (CMVP) program with the dual purpose of recognizing the most qualified professionals in this growing area of the energy industry, and raising the overall professional standards within the measurement and verification field. Lincus’ EM&V staff has attended and passed this three day CMVP training.

The International Performance Measurement & Verification Protocol (IPMVP), first established by the U.S. Department of Energy, has become the internationally recognized protocol for performance of EM&V.

Impact Evaluation has two main objectives: document and measure the effects of a program and determine whether it meets its goals with respect to being a reliable energy resource, and help understand why those effects occurred and identify ways to improve current programs and select future programs.

Impact Evaluations determine the achieved energy savings of a program. This savings is determined by comparing the energy use and demand after the program has been implemented to what would have been used if the Program was not implemented.

A process evaluation is a process of EM&V that evaluates how program goals are met, how applications are processed, and how savings are determined. Recommendations are given to improve these areas going forward.

Process evaluations assess how efficiently a program was or is being implemented, with respect to its stated objectives and potential improvements for future programs. This can range from how applications are processed, how applications are stored, how calculations are performed, how customers respond to the programs, and everything around and in between.

Having an EM&V study performed is the first step. In having an EM&V study performed, process and impact evaluations will be conducted. These evaluations provide recommendations on how to improve energy efficiency programs and much more. The next step is to review the recommendations and decide which are able to be implemented. The final step would be to implement the recommendations as stated within the EM&V study report.

EM&V evaluates the process and impact of energy efficiency programs. This can include, but is not limited to, the evaluation of energy efficiency program success, program feedback, and recommendations for improvement. All of this is done to increase confidence levels of energy efficiency program results.

Generally most Public Utility Commissions require Public Utilities and IOUs to provide an independently produced report which evaluates, measures, and verifies energy efficiency savings and energy demand reductions achieved by their energy efficiency programs on an annual basis. For example, in CA, AB2021 requires both an ongoing assessment of the programs as well as an evaluation of additional potential savings within the POU service territory. IOUs in all states are required to have their energy efficiency programs independently evaluated.

Most utilities in their DR programs require a minimum duration of 2 hours for customers to participate in most of its demand response programs such as the demand bidding program. Therefore, use that as a guideline in response to your question above.

Using an existing emergency generator to reduce demand has potentially numerous implications and would be something the utility would have to review on a case by case basis such as the considerations listed below.

(A) If the backup generator is using diesel fuel, the Air Quality Management District (AQMD) in your locality may not allow its use for other than emergency situations or testing.

(B) Operation permits specifically state generators cannot be operated for profit.

(C) If the backup generator is natural gas, it is possible the permit may allow it to operate at any time. If this is the case, the auditing engineer must attach a copy of the permit for verification.

Customers and contractors have typically more knowledge regarding the rules of emergency generation operation.

The Utilities are aware of the potential to save significantly in the program budgets by integrating energy efficiency and demand response. The Utility must weigh into consideration requirements of the Public Utilities Commission and internal utility requirements. The integration of energy efficiency and demand response programs is something that utilities continue to look into. At this time most of the demand response programs are not integrated with energy efficiency.

The typical Utility program is geared toward assisting customers in price responsive programs such as Demand Bidding and Critical Peak Pricing, so that they can respond to a call or a utility signal to reduce load. The triggers for those programs are the utility or the Independent System Operator issued alerts, based on day-ahead forecasts of the demand and/or daily peak temperature at your location at or above a certain temperature. The triggers all have one thing in common ‐ usually high temperatures during the summer tariff months (June, July, August and September). Based on the criteria above, we would recommend that the DR auditing engineers use the following approaches to determine demand response potential in order to estimate the load impacts from demand response and use the following definitions to calculate the baseline.

Customer Estimated Energy Baseline (CEEB)

The CEEB is used to help determine the customer’s demand reduction for an engineering study to assess the potential for demand reduction. The CEEB is defined as the estimated baseline will be determined using a 10 day rolling average energy usage profile of 10 similar days during the summer season (June through August) that include the maximum average summer demand for that customer. Then, the three highest usage days consisting of the time periods from Noon to 8:00p.m. will be extracted from the 10 days for the CEEB. The CEEB will be calculated on an hourly basis from Noon to 8:00 p.m. using the average of the same hour for the highest three similar days. The CEEB will include Monday through Friday, excluding holidays, and will additionally exclude days when the customer was paid to reduce load on an interruptible or other curtailment program or when customers were subject to rotating outages. The CEEB will be determined by the engineering contractor conducting the study using the aforementioned protocol. The CEEB may vary for each hour and for each event.

Estimate of Demand Reduction (EODR)

The Estimate of Demand Reduction is the amount of kWh/hr that the engineer estimates could be achieved during a demand reduction event. This is based on the estimate of load reduction calculated as a result of the inspection of the site, nameplate and diverse demand values for equipment, operational hours and load factors, ability (and willingness) to shed load, and the ability to sustain the load reduction for the entire hour. The load reduction approach should not affect the health, comfort, safety, or productivity of the occupants, tenants, or persons affected by the strategies, and should be agreed upon by the customer especially in areas that may affect the production or sales of goods and services necessary for customer service and quality of environment.

When estimating the EODR, the DR engineer must also look at the ability of the customer to implement the strategy on both a manual and automated basis. It is typically the utility’s preference that the load reduction strategies be automated so the customer can take advantage of technology incentives to defer portions of the costs for these equipment and services. Manual approaches to load sheds are acceptable, but must be clearly and fully documented and agreed upon by the customer. The ability of the customer location to reduce load on consecutive days (and to what limits that response) should also be examined. The EODR will be calculated by subtracting the calculated demand value for each demand response reduction approach from the CEEB, on an hourly basis.

Customer Specific Summer Baseline (CSSB)

Some utilities are adopting a more accurate and representative baseline to be able to estimate the customer’s available demand response load during the summer weekday/non‐holiday timeframe. This alternative baseline is called the Customer Specific Summer Baseline (CSSB). This baseline is used to establish the available customer kW from which demand reductions can be estimated during the peak hours ending 12PM through 8PM.

The CSSB is a baseline that quantifies the customer hourly peak load that may be available for consistent and repeated dispatch throughout the summer months. The Customer Specific Summer Baseline (CSSB) is defined as:

For each hour ending h:

Where:

CSSB_h = Customer Specific Summer Baseline (summer average weekday, non-holiday, demand for the dispatch hour ending h).

h = the hour being calculated represented as hour – ending (e.g. 12 pm is the hour beginning at 11 am and ending at noon)

N = the number of summer weekdays that are not holidays (if a full summer of current year’s data is not available, include the previous year’s data for the unavailable month timeframe)

i = summer weekday, non-holiday, number being added to the sum by the current cycle of the counter (all summer weekday, non-holidays, must be part of the sum)

kW_i = Average hourly demand for the individual hours that make up the summer average demand for the dispatch hours (kWh)

Pump operational efficiency can decrease overtime due to pump wear or the pump operating out of its design parameters. In some situations, decrease in efficiency is due to both reasons. Therefore, it is always a good idea to periodically check pump efficiency.

Cost of pump overhaul can vary depending on your unique situation. It can be as little as $100/hp and as much as $1,000/hp. Local utilities work with

If you have a big pump (> 15hp) and the unit runs for more than 1,000 hours/year, then being proactive about pump operational efficiency will reduce operational costs significantly.

A recent survey of pumping operation in CA revealed that average pump efficiency is 53%. This efficiency number applies to the broad spectrum of pumps like vertical turbine, submersible etc. In most cases, this means an average gain of about 19% is possible per pump which translates to about 27% savings in energy savings.

In addition to reduced energy consumption, improving operational efficiency can sometime lead to increased pump capacity. Energy consumption by pumps can be as high as 30% of your total load in your plant. For Water Districts and Agricultural customers, this number will much higher.

The old adage “Prevention is better than cure” holds very well for pump operation as well.

Just as the correct aerodynamic shape influences vehicle efficiency, hydrodynamics within pump influences overall pump efficiency.

There are different types of pumps. The most important classification is based on pump specific speed (NS). Depending on pump specific speed, the pump can be classified as radial flow (Centrifugal), axial flow(turbine) and mixed flow.

First inquire with your utility if they have an assigned account representative for your customer segment. The account executive will be able to assist you in the proper direction. If there is no account representative, then here is a general guide for where to find assistance. If you are dealing with a New Construction project, start by exploring Savings By Design programs. These programs assist customers from the ground up. If you are dealing with retrofit projects, you can explore Core Customized or Express programs. If you have a larger project and/or need hand-holding and guidance, inquire about working with one of the utility’s authorized Third Party Implementers (note that they have actual contracts with the Utilities, unlike most authorized agents). If you are interested in exploring new technologies, an Electric Power Research Institute (EPRI) program may be able to assist you.

There are a number of voluntary, as well as state, federal, and international reporting protocols used to account for greenhouse gas (GHG) emissions with varying degrees of complexity involved in each. Before employing any of these methods, it is important to establish the driving factors behind your organizations need to account for these emissions. If your organization is obligated under statutory requirements to comply with a state or federal law, then your best bet is to develop an intimate understanding of the statutory requirements in that jurisdiction. In California, the MRR establishes clear methodologies used to determine GHG emissions, while federally, EPA 40 Part 98 is the method of choice. Internationally, the Intergovernmental Panel for Climate Change (IPCC) protocols or protocols developed by the Climate Action Registry (CAR) are also useful to many organizations. There are several other well-respected methods Lincus, Inc. uses to establish baseline GHG emissions inventories for a broad spectrum of industries depending of the scope, scale, and intended use of these inventories.

A Cap and Trade program is a market-based mechanism designed to assign monetary value to environmental impacts, such as greenhouse gas (GHG) emissions, with the intended goal of reducing those impacts over time. Developed under the guise of the AB32 Scoping Plan, California cap and trade program sets a yearly maximum allowance (or “cap”) for entities that have a compliance obligation to report their emissions annually. Under current program rules, the allowances established for each entity are reduced by three percent each year beginning in 2013. Entities that are not able to easily reduce emissions are then required to purchase excess emission allowances through an open market “trading” process. The intended effect of this mechanism is to establish a market price for carbon that will spur the growth and development of energy efficient consumption and generation technologies.

AB32 is a reference to California Assembly Bill 32. Enacted by the California Legislature in 2006, AB32, also known as the Global Warming Solutions Act of 2006, directed the California Air Resources Board (ARB) to develop a scoping plan as a roadmap to reducing greenhouse gas (GHG) emissions in the state of California to 1990s levels by 2020. ARB approved a scoping plan in 2008 (later revised in 2011), which contains a comprehensive set of policies designed to effectively reduce emissions while also maintaining economic growth. One major component of the scoping plan requires that state utilities source at least 33 percent of their electricity needs through renewable electricity sources. Another part of the plan strengthens the Low Carbon Fuel Standard (LCFS) intended to reduce the carbon intensity of transportation fuels. Aside from renewable energy and fuel standards, AB32 is most commonly associated with mandatory utility and industry emissions reporting in conjunction Cap and Trade market-based emissions reductions.

According to the regulation (95105 Recordkeeping Requirements), reporting entities must maintain all records for a period of ten years from the date of the emissions data report certification.

Demand Control Ventilation (DCV) is an energy saving mechanism designed to reduce the activity of ventilation systems when low occupancy conditions permit. DCV is used in parking garages, movie theatres and other large areas where traffic is cyclical or intermittent. DCV limits the runtime of fans, compressors and other HVAC equipment. Sensors in the variable occupancy areas monitor CO2 and turn equipment on once a certain threshold is reached. DCV is typically paired with economizer repair in energy efficiency programs and is a highly desirable measure because of the relatively high kW savings compared with other more lighting-intensive programs.

Variable Air Volume Systems in Air Handler Units are systems that offer the capability to vary the amount of supply air depending on the load conditions. A typical VAV system in a multi zone air handler unit comprises of a variable speed drive on the supply fan unit and air mixing boxes in the individual zones. At low building cooling load conditions, the VAV system reduces the amount of supply air going into the individual zones by ramping down the VFD on the supply fans proportional to the building cooling load. This reduction in the speed of the supply fans results in energy savings consistent with the affinity laws. For instance, a decrease in speed by 20% will result in a power reduction by 49% for the supply fans. It is also possible to achieve cooling energy savings on the chiller or DX unit compressor by incorporating controls that help in resetting the supply air temperature to a higher value at low load conditions. Such scenarios will require the installation of load reset controls on the HVAC unit (chiller or DX unit) along with variable chilled water loop controls (if in case of a chiller supplying chilled water) to efficiently optimize the complete system operation. Resetting the supply air temperature to a higher value often results in an increase in the fan energy usage due to lower possible temperature difference between the supply and return air from the space. A tradeoff between the fan energy and cooling energy savings is often established in such cases with a pre-programmed control sequencing strategy.

Typically HVAC systems are designed such that the difference between Supply Air Temperature (SAT) and room set point temperature is 20 degree F. If the set point temperature is 75 degree F, the SAT is 55 degree F. When the cooling/ heating loads in the spaces decrease, the demand can be met with increasing SAT during cooling season and decreasing SAT during heating season. This increases the operating hours of outdoor economizer, compressor/ chiller loading which help in saving energy. However, the supply air volume might have to be increased. The optimization of savings from reducing chiller/ compressor loads and savings in fan power helps decides when SAT reset has to be implemented. SAT is commonly reset based on one of the feedback from one of the following variables.

1. Room set point temperature: SAT is adjusted based on the feedback from zone temperature. This is an effective method since it is directly based on the zone loads; it has lower negative interaction with static pressure reset strategy.
2. Out Door Air Temperature: SAT increases with decrease in outdoor air temperature and vice versa. This is effective in zones having loads dependence on outdoor air temperature with similar loads like perimeter zones with similar occupant functions. This is not effective when the loads are primarily not dependent on outdoor air temperature.
3. 3.    VAV box damper position: As the zone loads increases or decreases in the spaces, the primary air dampers begin to open or close. Using the damper position, the SAT is adjusted. This method might be ineffective is static pressure reset control strategy is also based on VAV damper position.

SAT reset and static pressure reset control strategies have huge interactions and sometimes may not result in savings expected from individual strategies. As stated earlier, optimization of the savings possible from these two strategies has to be performed before executing the strategy.

Variable Air Volume Systems in Air Handler Units are systems that offer the capability to vary the amount of supply air depending on the load conditions. A typical VAV system in a multi zone air handler unit comprises of a variable speed drive on the supply fan unit and air mixing boxes in the individual zones. At low building cooling load conditions, the VAV system reduces the amount of supply air going into the individual zones by ramping down the VFD on the supply fans proportional to the building cooling load. This reduction in the speed of the supply fans results in energy savings consistent with the affinity laws. For instance, a decrease in speed by 20% will result in a power reduction by 49% for the supply fans. It is also possible to achieve cooling energy savings on the chiller or DX unit compressor by incorporating controls that help in resetting the supply air temperature to a higher value at low load conditions. Such scenarios will require the installation of load reset controls on the HVAC unit (chiller or DX unit) along with variable chilled water loop controls (if in case of a chiller supplying chilled water) to efficiently optimize the complete system operation. Resetting the supply air temperature to a higher value often results in an increase in the fan energy usage due to lower possible temperature difference between the supply and return air from the space. A trade off between the fan energy and cooling energy savings is often established in such cases with a pre-programmed control sequencing strategy.

There are a lot of facets to this question. The general claim that Water source air conditioners are more efficient than their air source counterparts is definitely true due to the improved condenser efficiency. However, this increased efficiency comes at a cost. Water Source AC units require a condenser water loop, pump and a heat rejection unit. Boilers may also be required in most (if not all) of the sites that operate with water source units so as to prevent refrigerant freezing issues during winter.

Lincus engineers have seen that water source heat pump units and their economics work well when the site requires multiple smaller HVAC units. An example would be condos where each unit requires anywhere from 3-10 tons. The average cost per ton for water source heat pumps between 3-10 tons is roughly $ 1,100 per ton. Another example would be facilities where packaged/split AC units cannot be installed due to space constraints. In cases where there are multiple units, the cost of installing the ancillary units (boilers, pumps, cooling towers, piping, etc) may also be justified due to the number of HVAC units that you could possibly connect in one common chilled water loop and the efficiency increase on all these units. Water source air conditions will definitely not pay off well in all other circumstances which is why, the air source AC units are the units that we commonly see.

Based on Lincus’ energy audit experience and measurement and verification (M&V) at audit sites (which required ASHRAE Level III analysis), we believe that a typical HVAC (packaged/split ACs/Heat Pumps) unit degrades from in efficiency by about 1.1% each year. Please note that this degradation efficiency percentage is only an average, conservative and reasonable estimate based on Lincus’ M&V on selected HVAC systems that operate in typical conditions (10-12 hours of operation on weekdays and a few hours during the weekends, typical maintenance (for instance, filter cleaning every 3 month at a minimum, etc). The HVAC degradation in reality, is dependent on a lot of factors ranging from how its operated to where its operated and could be exactly determined only with an M&V on that specific HVAC unit. Some examples of why a unit’s efficiency may degrade faster than Lincus’ experience are higher than average operating hours or poor maintenance. However, we believe that this estimate of 1.1% should be consistent and a safe estimate that one can use in lieu of monitored data.

The first part of maintaining light levels is to determine what is adequate and what is excessive. Adequate is defined by two components – customer preference and OSHA standards. As long as OSHA standards are met, adequate lighting is determined by preference although it is important to note unusually high lighting levels. In the case of unusually high lighting levels, setting expectations of lower light output (as well as providing an understanding of what is “standard”) is an important of part of long-term customer satisfaction and a way to avoid using less efficient high-output ballast replacements. After defining adequate lighting levels and setting reasonable expectations, two options are typically available: the aforementioned high-output ballasts and the preferred alternative, reflectors. High-output ballasts will safely overdrive the lamps to create higher light levels but consume more energy than standard ballasts. Reflectors are the ideal solution and project light emitted from the top half of the circular lamp back down into the workspace. This is good for dispersion as well as maximizing all usable lumens from the replacement fixture.

No other lighting has been cut out of the measure summary and CFLs are actually eligible for the ’13 to ’14 program cycle – as long as they’re non-basic (spiral). In addition, T12s are eligible for baseline savings calculations.

As you may know from your vendor that the KOBE system uses production fluid to transfer as the medium to transfer fluid rather than a steel rod. While accomplishing pumping using some of the production fluid back in the well, KOBE creates inefficiencies. KOBE systems require larger amount of electrical power as compared to rod beam pumps due to the inefficiencies of the fluid piping system. Since there is so much pumping and recirculation of the fluid with KOBE systems that creates a high level of equipment maintenance, rod beam pumps can reduce these repair and maintenance costs by as much as 50%. Typically, production is also increased with rod beam pumps due to the reduction in maintenance downtime. Simple payback time for KOBE to rod beam conversion should be less than 3 years.

Oil production well pumps are typically designed to meet and exceed the potential fluid production rate at a particular site which is reasonable for maximizing production output. However, since the pumps are constantly operational throughout the year with little downtime for maintenance, it follows that the pumps are always expending more energy than necessary. Additionally, during these times, pump operation is full capacity regardless of actual fluid production rates.

The first measure is a variable speed drive (VSD). This technology is a universal measure that has been applied to many processes that require modulating pump operation. A VSD provides the capability to adjust the speed of the pump motor based on the demand requirement. Note that the VSD does not take instantaneous readings that control the pump in real time. The speed must be adjusted manually or based on set schedules. However, by merely introducing the flexibility to run the pump at the desired capacity, energy usage per well is more efficient since the pump does not run beyond the demand requirements. This measure is NOT eligible for incentives since it is Industry Standard Practice (ISP).

Pump off controls (POCs) are real time controls that monitor the fluid production rate for each well. The “sufficient” flow rate is determined individually by the operator. Once flow rate drops below the pre-determined threshold, the well is automatically shut off to allow for fluid build-up until the fluid levels in well bore is sufficient for useful pump operation. This measure mitigates the pump operation during times when fluid levels are not deemed acceptable for operation and therefore are a tremendous source of energy savings. However, incentives for this energy measure are restricted to minor producers since POCs are now Industry Standard Practice (ISP) for major producers. The major producers are defined as Chevron, Exxon, Occidental, AERA, Plains Exploration, and Berry Petroleum and all subsidiary or parent companies.

Oil production wells are generally associated with high energy usage since the oil must be lifted from below ground to the surface by means of pump operations. Each barrel of fluid lifted typically exceeds 95% water with the remainder being the working fluid, oil/gas (discounting miscellaneous sediment that follows the process). SMART well technology presents the ability to limit the amount of water lifted and reduce pumping energy at multiple levels while maintaining oil/gas production.

SMART Wells are technologies that have recently been emerging in the oil production field. The scope of work for this measure entails drilling new wells or re-drilling existing “standard” wells (active or inactive) to incorporate SMART well technology. The “standard” well is defined as one that uses a slotted liner that is inserted into a casing with perforations over the entire length of the well bore, thus permitting unrestricted flow from all directions. As a result, excess water is lifted and unnecessarily expends energy. The proposed solution is “SMART” well technology that incorporates a casing with selectively placed perforations along the bore to allow oil-water mixtures to flow from sub-zone s that contain sufficient oil/gas producing content, while minimizing flow from water saturated sub-zones. This is achieved using geological surveying to custom design the bore for each individual well.

By reducing the volume of water lifted, energy savings are realized in (3) phases of the oil production process: artificial lift power, surface transportation power, re-injection power. The details of each process in defined as follows:

– Artificial lift – the process by which the underground fluids are drawn to the surface via introduction of pressure.

– Surface treatment/transportation – the process by which the extracted oil/water mixture is moved to a designated refinement/treatment and collection zones.

– Re-injection – the process by which the separated water is re-injected to the well/reservoir to help in artificial lift as wells as to comply with geographical standards stating that the displaced oil/water mixtures extracted for oil production must be replenished.

An energy metric is created using production data and site parameters which estimates the amount of energy required per barrel of fluid produced. Oil production can range from hundreds to thousands of barrels of fluid per day. Given this estimation, a substantial amount of energy can be saved by removing water throughput.

Reduction in energy consumption, in this application, is highly dependent on the oil-to-water ratio before and after the conversion to a SMART well from the current state. There are some highly complex geological modeling tools available in the market to predict oil-to-water ratio after the “SMART” conversion. Based on our experience with more than 500 oil production wells, the reduction in water content can be anywhere between 5% and 50%.

Energy savings will be achieved in: 1) Energy Required to Lift Product Fluid (Artificial Lift), 2) Energy required for surface pumping, and finally, 3) Energy required for reinjection. Annual kWh savings is the difference between the pre-installation kWh and the post installation kWh. Energy savings is calculated based on the oil and water flow rates for the well for baseline and installed condition.

It is important that the measurement period for the water and oil flow rates be a reasonably representative period for the current operation so that the savings may be reliably calculated. Additionally, well depth, surface discharge pressure, and the re-injection pump discharge pressure are required. Energy savings is calculated as the difference between the annual baseline and post installation energy consumption. The annual operating hours should allow for the maintenance outages as well. Since this type of pump operates 24/7, we recommend that you calculate the peak kW demand savings by dividing the annual kWh savings with the annual operating hours. This is reasonable because the pump operates 24/7 except for some maintenance time and the kW demand is expected to remain constant.

Turnkey programs are energy efficiency programs designed to provide single point of contact, all inclusive retrofit opportunities to customers. Usually coordinated through SCE account managers, a third party implementer will meet with the customer, explain the program, help fill out the appropriate paperwork, get approval, perform the installation, and get a sign-off for the work performed. While the customer may receive services from subcontractors, their only interface is with the primary implementer. Further, implementers will work with the SCE contract program manager, inspectors, and others but will maintain the face of the program and all parts from beginning to end. Currently, SCE provides Turnkey programs for schools and entertainment centers.

The focus of the Entertainment Centers Program is savings through Demand Control Ventilation (DCV) or repair of economizers. Customers must install DCV or repair economizers before receiving no-cost measures like lighting.

When developing new resource, it is helpful to provide an overview of the project or program that the new resource will be involved in. Drill down from the high level to the piece or pieces that the new resource will participate in, and share how the piece or pieces will impact the big-picture project or program.

Tell them what you are going to tell them, tell them, then summarize with what you already told them.

Schedule in time for training and estimate the time needed to manage the learning curve. Assign tasks, responsibilities, and milestone deadlines to assess performance and set expectations. As the new resource develops skills and comfort applying them, request feedback on their workload and ease them into similar tasks until they are fully loaded. Revisit their workload at pre-determined intervals (i.e. weekly) to assess if their work needs further development or if they are ready and able to take on additional tasks. Ensure that you constantly remind and reinforce the required protocols and procedures until it becomes second nature to the new resource.

Extensive research of existing water pumping inventory in CA indicate that an average irrigation pump efficiency is about 53% rather than 75-78% as in the original design condition. Agricultural/irrigation customers account for 7% of total statewide electricity use. Out of this total of 7%, 80% is used by pumping systems. If you consider that the average irrigation pump size of 75 hp (varying between 15 hp to 750hp) and the number of pumps within a water utility, a municipal distribution system, or agricultural irrigation pumps, your utility’s potential in energy savings could be substantial.

From the technical perspective, efficiency losses may come from motors, bearing and electrical losses (9%), column and shaft losses (5%), and impeller and bowl assembly losses (31%). As per the CA study, average energy savings per pump is about 34,000 kWh per year.

In addition to the pump efficiency improvements, a utility program may evaluate the use of variable speed drives (VSD) if the flow is or may be made variable based on the water demand.Please note that VSD applications are more complex and should be evaluated based on operating parameters. Energy savings for properly commissioned VSDs should be about 20-30%.

From the program design perspective, you need three main ingredients such as 1) selection and training of pump testers, 2) pre-qualification of pumps based on certain factors that will help you reach a benefit cost ratio of greater than 1.0, and 3) marketing and outreach campaign to ensure that your program will reach its savings and demand reduction goals. By the way, pumps are a great source for demand response as well, if you have a demand response program or if you are thinking about starting one. Similar opportunities are also available for blower systems used in wastewater treatment. At Lincus, we have designed and currently implementing pump and blower testing programs for three investor owned utilities and if you need further information on program details please contact us.

Like any technology, on demand water heaters (a.k.a. tankless water heaters) have advantages and disadvantages. The unit’s operation should be considered to evaluate whether it is the right choice for the application. On average, converting from an electric tank water heater to an electric tankless water heater generates savings of approximately 20%. Converting from a gas tank water heater to a tankless water heater can save up to 45%. This is due to gas tank water heaters being less efficient than electric tank water heaters. One major benefit on top of the savings is the tankless water heaters can provide an unlimited source hot water within their capacity.

While each system has their advantages, like any purchasing decision, the drawbacks should also be considered. For tankless water heaters, these include capacity, how quickly hot water will reach the point of use, and minimum flow rate to activate the water heater. With respect to capacity, tankless water heaters have limits to the amount of hot water they can produce at a given time. Another drawback of the tankless water heater could be that since there isn’t a tank of hot water waiting to be used, it takes a little longer for water of the desired temperature to leave the water heater, approximately 10 – 20 seconds in some cases. Some models have a recirculation pump option built in, which allows for hot water to constantly be circulated through the lines, so you will have hot water instantly whenever you need it, however there will be line losses (loss of heat) during the recirculation. That being said, you will no longer experience heat loss from a tank, and with the higher efficiency of the tankless water heater, it is likely the result will be a net benefit. A third potential drawback is the minimum flow rate required to turn the heater on. The flow rate to activate the heater ranges from 0.5 to 0.75 gallons per minute. This is only an issue for occasions when a very low flow of hot water is required.

When selecting a tankless water heater you will need to consider how many devices will be using the water at any time and also the flow rate of those devices. Add up the flow rates of your devices and select based on that capacity. You will also need to take into account the temperature of the incoming water. Typically, incoming potable water is around 50 degrees Fahrenheit. Cooler incoming water temperature will require additional heating capacity to reach the desired temperature.

Tankless water heaters can be a good investment considering the savings that can be achieved through efficiency, as long as the water heater is sized appropriately for the application.