On a Personal Note…

Published to LA Confidential, Winter 2017

Recently, the Luthins traveled to Southern California and spent some time in the desert. We visited the Salton Sea, one of the largest lakes in California. It is 45 miles long, 25 miles wide and at 234 feet below sea level, it is one of the lowest spots on Earth. The sea is in the middle of Southern California’s fertile agricultural land in the Imperial and Coachella Valleys.

In 1905, spring floods escaped irrigation canals used for agriculture, and flooded the ancient lake bed. By the time the flood was under control, the Salton Sea was born. Today, the sea is landlocked with only a trickle of fresh water flowing in and none out, except by evaporation. As it dries up, it becomes 30% more salty than the Pacific Ocean, and is being filled with fertilizer runoff from the surrounding agricultural counties.

Managers of the Imperial Valley’s water district demand that California officials prepare a realistic “roadmap” to ease the sea’s erosion of wildlife, dust, air quality and health issues to those that live within the region. Experts say the declining sea threatens the air quality of Southern California and Northern Mexico, unless a plan is adopted to reduce the evaporation as a result of a warmer climate and the loss of water from the Colorado River. Hopefully, action will be taken in the near future to reverse this trend.

While developing these articles, it was apparent that time is a key variable in the effort to reverse climate change. Many of the impacts of climate change will not occur for more than twenty years. Yet, these articles paint a timeline that is much more immediate. Public policy is changing faster than the weather and according to our analysis of the election results, programs that are currently in place may have changed by the time you read this newsletter. The Roller Coaster article describes how El Niño and the Polar Vortex have had a sudden impact on the energy landscape, although they took decades to morph into impactful natural phenomena. The Salton Sea example is an issue requiring a more instant response, although “the environmental crisis” has been developing for quite a few decades. Many long term issues will require technological solutions such as the sCO2 power plant described in the Factoid.

The challenge is to slow down change while accelerating solutions. This brings to mind the Rolling Stones’ lyrics, “Time, time, time, is on my side, yes it is.” I certainly hope that is true.

Factoid: Supercritical Solutions

Published to LA Confidential, Winter 2017

As we look at opportunities to impact climate change, out-of-the box thinking may help us bridge the gap until fossil fuel plants are out of the picture. Those of you who enjoy the beach may have noticed   the “Fudgie – Wudgie” guy (that is what we called him in the 20th century) selling ice cream on the beach out of shopping bags or pushing a cart. Rather than using ice which will not last the full day, he uses a solid form of carbon dioxide (CO2) known as dried ice. Did you know that CO2 also occurs in liquid form? Well, somewhat.

CO2 raised above its critical temperature and pressure, enters a supercritical state in which it exists as both a liquid and a gas. Not quite like, but similar to, Schrodinger’s Cat. In this form, the molecules are much denser than those in a standard state. This enables the CO2 to be fed into a turbine and turn a generator much more efficiently. Supercritical CO2 (sCO2) has proven to be able to generate electricity more efficiently than fossil plants and may do so with plants much smaller in size. However, this has previously been done only at small load levels.

Now, it is time to step it up. The U.S. Department of Energy (DOE) is awarding up to $80 million for a six-year project to design, build, and operate a 10-MW sCO2 pilot plant test facility in San Antonio, TX. The project will be managed by a team led by the Gas Technology Institute, Southwest Research Institute®, and General Electric Global Research. It is estimated that plant energy efficiency may be improved by up to 50% while the plant size may be reduced by 75% compared to traditional fossil plants.

Potential Impacts of Near-Term State and Federal Energy Policies Related to Climate

Published to LA Confidential, Winter 2017

With the election of Donald Trump, federal and state energy policies may sharply diverge in the near future. Some states, such as New York and California, are trying to reduce carbon emissions, while President-elect Trump appears to have other priorities.  Trump’s campaign proposals are preliminary, but a few general directions are clear. Here is how those divergent strategies and transition plans may impact energy policy.

A major focus of the Obama Administration had been to replace coal with a mix of natural gas, renewables, and energy efficiency. The primary federal effort to that end was the Clean Power Plan (CPP) now being contested in a federal court. The plan could be rejected by the Supreme Court, especially if the current vacancy is filled by an unsympathetic justice.  However, even if CPP is struck down, various other established federal regulations already limit coal use. Currently, low and future natural gas prices make it the preferred power plant fuel, regardless of environmental regulations.  Possible easing of rules restricting production of natural gas on federal lands or by fracking will only extend the current price advantage of natural gas.

On the state level, New York’s Clean Energy Standard seeks to source 50% of the State’s power from renewables by 2030, with almost all the remaining to come from nuclear and gas-fired plants. The nuclear component of the plan was recently called into question when three upstate nuclear facilities (Ginna, Nine Mile Point, and Fitzpatrick) notified the New York Independent System Operator (NYISO) of their intention to shut down at the end of their fuel cycles. This was due to low energy prices resulting from low natural gas prices. To avoid that possibility, New York created a new subsidy – Zero Emission Credits (ZECs) – to reward nuclear’s ability to make power without carbon emissions. All load serving entities (LSE) including utilities would annually buy about half a billion dollars (opponents claim more) of ZECs from plant owners for at least six years. That cost would be added to bills.

That could boost electric rates by an average of $0.003/kWh, although some believe it may be higher.  That translates to a ~2% increase in the average Con Edison commercial rate, or about as much as a typical annual rate increase. On the positive side, the increased supply will only depress wholesale electricity prices.  Several lawsuits are underway to block or modify the ZEC plan, with resolution not likely until early 2017.

Nobody has a crystal ball when it comes to what a Trump administration may seek to do, but extrapolating from campaign statements, any or all of the following may be in the cards:

  • Cutting existing and proposed federal energy regulation including those related to federal land use for extraction
  • Halting or rolling back pending energy efficiency standards
  • Accelerating the phase-out of tax credits for wind and solar resources
  • A new Carbon Control Credit to keep more coal plants running
  • Increasing the cost of natural gas to make it less competitive with coal by instituting a tax on wastewater disposal from fracking
  • Taxing oil imports from nations such as the Middle East, Venezuela, and Russia

Other programs include:

  • Reducing fuel oil demand by replacing it with natural gas
  • Building/extending gas pipelines also fits into Trump’s infrastructure and jobs promotion plan
  • Pushing U.S production of electric vehicles
  • Resurrecting the Keystone XL pipeline and push other pipelines

To boost our domestic natural gas and oil resources, he may:

  • Open federal lands and offshore areas to drilling
  • Accelerate approvals of liquefied natural gas (LNG) export terminals thus improving the trade balance while using natural gas as a strategic trade weapon against some nations

Some of Trumps plans can also positively impact climate change. His administration could support efforts that focus on business and jobs via infrastructure upgrades that also cut carbon:

  • Providing tax breaks for replacing aging gas distribution systems that leak methane
  • Building large incinerators to convert waste to energy, while reducing landfills that emit methane
  • Expanding power transmission lines to improve access to power from Midwest wind and fossil energy.

Other possible changes that could affect the energy landscape include:

  • Rescinding the recent Paris accord on carbon emissions (although some feel that could take several years)
  • Relaxing/eliminating financial regulations (e.g., Dodd-Frank) to expand trading of energy commodities
  • Raising interest rates that push up energy stock prices while limiting renewables heavily dependent on low rates for their capital intensive projects
  • Shifting federal research and development (R&D) support from renewables to carbon capture systems and fossil fuel opportunities.

Depending on how they are financed, some options may decrease average wholesale pricing, while others boost price volatility and alter the balance between fixed and variable energy charges. Whatever happens, future energy purchasing strategies will require a sharper pencil to successfully navigate those changes.

Riding the Weather Roller Coaster

Published to LA Confidential, Winter 2017

Climate change may gradually alter the landscape of energy production like tectonic shifts, but seasonal weather variations yield much shorter and obvious changes, a bit like riding a roller coaster. During the winter of 2015-16, much of the U.S. rode it to the warmest winter on record. In the Northeast, December 2015 had 27% fewer heating degree-days (HDD) than the 30-year average, while January-February saw HDDs 12-17% below normal. Two years before, we had the Polar Vortex winter, one of the coldest on record. Such short term variations cause ripple effects on energy pricing that may be felt for a year or more thereafter.

The gas supply industry has for decades depended on storage of large volumes of natural gas in underground seams such as spent oil wells, salt caverns, and its vast higher pressure pipeline system to mitigate wide price swings and supply issues. Shortly after one winter ends, that storage is gradually replenished through spring and summer so that an abundant supply is available for the next winter. Our annual national gas consumption is about 27 trillion cubic feet (Tcf), and storage holds about 4 Tcf. That is usually sufficient to handle the widest weather swings. Without that stored capacity, the Polar Vortex winter could have caused a calamity. However, what happens if all that gas is not needed when a winter turns out to be unusually warm?

Gas producers then find themselves competing with stored gas they thought would be consumed. The resulting “overhang” temporarily forces gas prices down. As a result, that pushes power prices down as gas-fired generation is the price maker in wholesale markets. Gas producers may shut in wells until the excess gas is burned off in order to restore balance. That action may, in turn, drive gas and power prices back up to their normal levels. Say hello to the price roller coaster.

This January, the U.S. Department of Energy’s (DOE) Energy Information Administration (EIA) forecast rises in both gas price and usage for this winter, with retail prices rising by 13% and consumption for heat rising slightly. Pricing at the wholesale commodity level (which does not include retail’s pipeline and distribution costs) is expected to jump by 41% compared to warm 2016. EIA stated that, “falling natural gas production during 2016 and increased use of natural gas for electricity generation” are combining to influence the short term wholesale market.

One of the main drivers of that roller coaster is a recurrent weather pattern that cycles every two to seven years called the El Niño Southern Oscillation (ENSO). We are now coming out of a relatively strong El Niño caused by warm air over the Pacific that moderated two consecutive winters in our area. The opposite pattern (La Niña) stems from cooler Pacific air that, for several consecutive years, may yield colder and wetter winters. This winter may see a shift from one pattern to the other.

Markets are also trying to digest and adjust to some multipliers that may nudge the roller coaster faster and higher. Coal-fired power plants are being rapidly converted to, or replaced by, gas-fired units in the Northeast and Mid-Atlantic States. Some cities (e.g. New York) are pushing to replace fuel oil for heating with natural gas. Exports of liquefied natural gas (LNG) may also soon compete for gas supply. Resultant gas demand in some regions is rising faster than pipeline capacity can be expanded to meet it, causing winter gas and power pricing to spike.

That process resulted in extraordinarily high energy pricing in January and February during the 2013-14 Polar Vortex winter. Forward pricing for those months then remained high for two years thereafter until moderate weather forced traders to cut their pricing.

Knowledge of such supply vulnerabilities is now “baked” into future pricing. Less than a decade ago, wholesale forward power pricing during the winter was the same or lower than during the summer. Due to the increased dependence on gas to generate power, the reverse trend now exists in New England, downstate New York, New Jersey, and much of Pennsylvania.

Potential Impacts of Climate Change on Energy Costs

Published to LA Confidential, Winter 2017

Weather conditions, such as occasional daily and annual variations in temperature and moisture, have obvious temporary effects on energy bills. Heating costs rise when it is cold and dry, while cooling costs rise when it is hot and humid. Weather changes associated with climate change are expected to have long-term permanent impacts on those costs by causing weather extremes and changes to how power is produced.

Imagine a pendulum swinging left to right. If someone nudges it just a bit each time it was all the way to the left, the swing in both directions gradually increases. In this analogy, weather cycles to and fro on a steady recurring basis. The finger pushing the pendulum is the increased concentration of greenhouse gases (e.g., carbon dioxide, methane, refrigerants) due to human activity. They slightly increase the insulating ability of the atmosphere, reducing the rate at which heat is lost to space. Global, and sometimes regional, temperatures rise which push the usually balanced weather pendulum further toward greater extremes each year.

Coping with summer extremes means more air conditioning, which causes higher power demand, requires more power plants, heavier transmission lines, and larger transformers, all of which must be paid through our electric bills. While seasonal shifts may boost short-term energy costs  requiring the use of more expensive fuels or purchased power, long-term increases in grid load may boost peak demand charges to cover extra fixed costs of that power generation and delivery equipment. While renewable sources of energy may provide free fuel, accessing that energy requires installation of capital-intensive equipment.

Renewables are also not immune to climate-related price impacts. When winters (on average) become warmer, the atmospheric moisture balance that produces rain and snow may be upset. In the U.S. Northwest, a winter’s snow is needed as it melts in the following spring and summer to power hydroelectric power plants. A reduced amount may result in burning more fossil fuels to make up the difference, further aggravating climate change. The prolonged west coast drought provides a local example: loss of snowpack in the mountains led to the lowering of reservoirs at hydroelectric dams. In nations heavily dependent on hydro, such as Africa and South America, significant changes in the moisture balance has led to power cutbacks and greater fossil-fueled power generation.

Impacts may also be indirect. Many large power plants depend on abundant and cool river water to remove the waste heat they produce. Several, including nuclear plants, have had to shut down when water levels dropped and water temperatures rose during extended droughts. As power supply dwindled, power prices soared.

Wind turbine power output has also been impacted by extremes. In both Texas and along the west coast, extensive lulls in wind speed last year cut turbine output by over 40% for weeks at a time, requiring power from non-renewable sources to make up the deficit. An unusually strong September 2016 storm in Australia caused turbines to automatically shut down to avoid damage. The sudden loss of their output caused a large power imbalance that blacked out the grid for the entire state of South Australia for nine hours. To avoid a repeat, the utility is considering expansion of fossil-fueled backup generation. Electricity storage technologies such as batteries are currently being installed to provide power when wind or sunlight are lower than expected. As these occurrences increase in number and severity, increased storage per kW generated will become necessary which will add additional costs to the systems.

Other impacts of weather extremes on energy pricing may be more subtle, but nevertheless appear on the bottom line of energy budgets. Nudging the weather pendulum too far may harm the energy infrastructure and increase maintenance as well as repair costs. These costs may eventually become part of future energy pricing. In 2005, Hurricanes Katrina and Rita put more than 100 oil platforms out of commission, while damaging 558 pipelines, causing fuel prices to spike. Winter extremes freeze rivers for weeks in coal country, which block barge shipments to power plants. These extremes also cause coal piles to freeze to a point that jackhammers may be needed to loosen them.

As the pendulum continues to be nudged, the costs due to such extremes will continue to rise.

LuthINformed – NG Exports to MX

Published to LuthINformed, Issue 10 (September 7, 2016)
In this issue, we take a look at the impact of natural gas exports to Mexico. We hope to provide our readers with guidance and actionable information that will be both valuable and useful. As always, your feedback is welcome…
Natural Gas Exports to Mexico…
Fewer imports from Canada – and greater exports to Mexico – mean that the U.S. is poised to become a net exporter of natural gas either this year – or next. In fact, the amount of natural gas that the U.S. transports to Mexico has risen precipitously since 2000 – and more than quadrupled since 2010 (chart below). By 2019, fourteen new pipelines will more than double current capacity to nearly 15 Bcf/day. And while selling natural gas at higher prices on the world market increases profits for U.S. producers, the price gap between the United States and the rest of the world shrinks, eroding some of the benefits to U.S. consumers and manufacturers.
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Falling MX Power Rates…
As the chart above shows, electricity tariffs for industrial users in Mexico are falling relative to US rates. In 2015, the premium has fallen from 47% to 29%, with the gap expected to narrow further still in the years ahead. Mexican energy prices may fall further since some manufacturers will soon access natural gas from their own pipelines, allowing them to produce their own electricity. Cheaper natural gas and lower power prices can only be good news for Mexico’s manufacturing sector and overall economy.
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The Impact of Greater Exports…
The dynamics of precisely assessing the impact of higher natgas exports are complicated. In a recent report, the Center for Energy Studies found that, in every case, greater exports raised domestic prices “somewhat” and lowered prices internationally. The report goes on to say “the positive impact of higher U.S. gas production exceeds the negative impacts of higher domestic prices associated with increased exports.” The chart above shows these higher export prices. Good news for U.S. producers after last years warm winter, a glut in storage levels and projections for sustained low prices.
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Natural Gas Outlook…

The latest inventory report (above) shows a net increase of 51 Bcf vs. the previous week. Stocks were 238 Bcf higher than this time last year and 334 Bcf above the five-year average. Current natural gas strip prices are listed below:

12 month strip = $2.999

24 month strip = $3.001

Cal Year 2017 = $3.054

Cal Year 2018 = $2.949

(all prices NYMEX only; A/O 9/6/16)


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For an in-depth discussion on markets, purchasing strategies and other topics, call us here at Luthin Associates. We offer our clients regular market updates and our Energy Procurement Group is staffed with certified experts on energy market conditions.

Luthin Associates



Although care has been taken to ensure the accuracy, completeness and reliability of the information provided, Luthin Associates, Inc. (Luthin) assumes no responsibility therefore. The user of the information agrees that the information is subject to change without notice. Luthin assumes no responsibility for the consequences of use of such information, nor for any infringement of third party intellectual property rights which may result from its use. In no event shall Luthin be liable for any direct, indirect, special or incidental damage resulting from, arising out of or in connection with the use of the information.

LuthINformed, Issue 9 – Energy Losses

Published to LuthINformed, Issue 9 (August 22, 2016)

In this issue, we offer a look at energy losses. This sometimes overlooked factor plays an important role in power pricing and, as it turns out, our climate too. We hope to provide our readers with guidance and actionable information that will be both valuable and useful. As always, your feedback is welcome…

What Exactly are losses?

Electricity losses are the result of technical inefficiency and theft. During electricity transmission, some power is lost through wire resistance, transformers, and other physical causes. This “line loss” occurs at two levels: during transmission at high voltage to a utility, and again at lower voltage as the utility distributes power to customers. In addition, Unaccounted for Energy (UFE) refers to unexpected unmetered electricity use and electricity lost to ground due to equipment failure, faulty wiring, etc. Just how much energy is taken up as Losses and UFE depends greatly on the physical characteristics of the system in question – as well as how it is operated. Generally speaking, Transmission and Distribution (T&D) losses between 6% and 8% are considered normal. See chart below for a state by state breakdown of losses.

Transmission losses are typically included in a zonal price. However, it may not be included in a retail power supply price. This is one very important reason why losses matter to you. Losses are built into utility tariff rates, and typically in fixed-rate commodity prices from retail suppliers (ensure the contract doesn’t say otherwise). Under indexed pricing, however, the price “floats” based upon the hourly wholesale market price. A supplier then adds a per kWh adder that includes capacity, ancillary services and the supplier’s management fees. Line loss may be an extra line item charge. As always, any supply contract terms should fairly protect the interests of both buyer and seller. Failure to take losses into account could mean an unexpected increase in your power price – and budget.

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Retail Suppliers and Losses…

Most retail suppliers use a fixed line loss rate for the term of a contract, but that number varies among suppliers. In indexed bids, some use Con Edison’s standard average of 7.9%, but others offer factors as low as 5.5%. It’s clear that some suppliers use complex loss calculations involving floating factors that cannot be compared in advance, such as:

  • Con Edison’s posted average monthly line loss numbers
  • A rolling, 12-month average weighted rate based on a customer’s particular On and Off-Peak usages
  • Con Edison’s line loss numbers multiplied by a customer’s hourly kWh usage

Con Edison’s hourly loss factor has historically ranged from +26.1% to -12.8%. Line loss can be a negative number because each hour’s loss is initially based on the standard load profile for each rate class, and then corrected in the following hour based on actual data. If your contract allows for a pass thru of losses, then we recomend a quarterly reconciliation based on posted factors; if losses are fixed, then your contract should clearly stipulate the line loss factor to be used.

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ConEd Losses…

Con Edison publishes a monthly supply charge (MSC) for each of its 3 zones (H, I, and J) and which is adjusted for losses. This data can be found  here. In April of 2009, it began publishing Unaccounted for Energy through its ESCo News bulletins, typically three months after the fact (find UFE data here) Those hourly factors, however, are initially based on standardized, system-wide load profiles. They are then corrected in the next day’s (or month’s) line loss percentage for the same timeframe.

Efficiency Gains and Losses…

Recent efficiency developments that improve transmission technology offer real benefits beyond simply minimizing losses. Lower losses equates to very real emissions reductions – smaller losses means less of a need for generation – and the fuel required for it. However, gains in efficiency are only recent and implementation has been sporadic. Data is only available through 2014, and does not necessarily reflect such recent progress (See chart above. Source: EIA).

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Natural Gas Outlook…

The latest inventory report (above) shows a net increase of 22 Bcf vs. the previous week. Stocks were 327 Bcf higher than this time last year and 405 Bcf above the five-year average. Current natural gas strip prices are listed below:

12 month strip = $2.921

24 month strip = $2.952

Cal Year 2017 = $3.012

Cal Year 2018 = $2.946

(all prices NYMEX only; A/O 8/19/16)


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For an in-depth discussion on markets, purchasing strategies and other topics, call us here at Luthin Associates. We offer our clients regular market updates and our Energy Procurement Group is staffed with certified experts on energy market conditions.

Luthin Associates



Although care has been taken to ensure the accuracy, completeness and reliability of the information provided, Luthin Associates, Inc. (Luthin) assumes no responsibility therefore. The user of the information agrees that the information is subject to change without notice. Luthin assumes no responsibility for the consequences of use of such information, nor for any infringement of third party intellectual property rights which may result from its use. In no event shall Luthin be liable for any direct, indirect, special or incidental damage resulting from, arising out of or in connection with the use of the information.