Natural Gas Imbalance Management – A Worthwhile Juggling Act

Author:  Renato Nitura, Account Manager, Kinect Energy

I recall a time when I worked for a natural gas utility (Local Distribution Company – LDC) here in Colorado.  Gas Transportation was somewhat of a newer service offering (some 20+ years ago) and was starting to gain some traction in the local marketplace.  Marketers flooded the arena, explaining to potential customers how this service worked and how it may benefit their natural gas spend (lower and/or controlled costs).  They no longer had to accept the utility’s gas sales rates but could instead have access to the open market and competition.  Many potential customers assumed that such marketers had a good understanding of what they were promoting and selling.  Imbalance management was a service many marketers capitalized on.

I specifically recall one gas marketer who was somehow happily and surprisingly shocked that he was receiving monthly checks from the LDC.  These monthly checks were akin to getting a gift for no apparent occasion as far as he was concerned.  His misconception drove him to intentionally create sizable over delivered imbalances every single month on the LDC’s system in order to receive a check.  Somehow, he genuinely believed he was gaming the system and taking advantage of the LDC.  What he did not seemingly understand was that the LDC was actually buying his excess gas supply at a heavily discounted rate.

I suspect this marketer simply had no idea that this “gift” was actually costing his company greatly.  The marketer did not last long operating under this gross misunderstanding.  This is a clear example of not appreciating imbalance management as a real cost component and not grasping the consequences for mismanagement.

Let’s start with the foundational basics.  So what exactly is an imbalance?  It is the variance between what a Shipper has available for its use (Confirmed Receipt) and its actual demand (metered/transported volume).



Confirmed Receipt Metered Volume Imbalance Position
100 dth 132 dth (32) dth Under delivery
100 dth 85 dth + 15 dth Over delivery


An imbalance is often calculated on a daily basis and may accumulate over the course of the month with the sum of the daily imbalances resulting in a Monthly Imbalance.  Think of the above scenario like a checking account.  A Confirmed Receipt is similar to a deposit to the account and the metered volume is similar to a withdrawal on the account.  The Shipper’s (the checking account holder in this illustration) goal should be to keep its deposits and withdrawals fairly close to one another so that the net effect (imbalance) is as close to zero as reasonably possible at the end of some designated time period.


Let’s focus on monthly balancing on a LDC’s system.  A Shipper is said to be over delivered when at the end of the month, the Shipper has delivered more gas supply to the LDC than it required.  Conversely, if the Shipper has used more gas than it delivered to the LDC, then the Shipper is said to be under delivered.


So what happens to this imbalance and why does it matter?


The LDC’s tariff will likely outline how the Shipper’s imbalance position shall be cured.  A LDC may allow the Shipper to carry the imbalance forward into the next month with certain gas scheduling procedures available for curing the imbalance.  A Shipper may also have the option to trade their imbalance with another Shipper on the LDC’s system so long as the imbalance trade improves both parties imbalance position meaning the imbalances must be in opposite directions.  The LDC may even implement a Cashout policy as the imbalance cure.  For instance, a LDC may purchase an over delivered volume from the Shipper or sell gas supply to an under delivered Shipper.


Cashouts are generally structured to be punitive to Shippers in order to encourage responsible imbalance management practices.  The LDC cashout rate for the purchase of gas supply may be at prices less than market price (discounted price), meaning the Shipper will pay a higher rate for its gas supply than what the Shipper will receive in return (as was the case noted above).  In the case of an under delivery, the LDC may sell gas to a Shipper at an above market price (inflated price).  The Shipper is subjected to an additional cost for the imbalance in either case.


Some LDCs have Imbalance Tiers which are dependent on end of period imbalance percentages (formula for an imbalance percentage = Dth Imbalance/Dth Usage).  As the imbalance percent increases, so does the related costs.  A higher tiered over delivered imbalance may be cashed out at a more heavily discounted price, whereas a higher tiered under delivered imbalance may be cashed out at a higher premium.


LDCs also desire to keep their sales customers insulated from any cost causing behavior of Shippers.  Imbalance policies and procedures can be an effective tool used to influence a Shipper’s management of imbalances.  The lack of imbalance provisions may result in a Shipper taking advantage of a LDC’s rate payers by using or not using its own gas supply depending on actual market price conditions.  Imbalance policies and provisions give the LDC some level of assurance that Shippers will conduct business in a responsible manner and also provide a means of recovery for the mismanagement of imbalances.


Balancing service is not always available to Shippers.  A LDC may, from time to time, call a restriction (sometimes known as an Operational Flow Order or OFO) when its ability to meet its firm obligations (sales customers and firm Shippers) is jeopardized.  Balancing on the LDC is either not available or available under limits during an OFO.  If an OFO has been called for over delivery restrictions, this means the Shipper should at a minimum use the gas supply it delivers to the LDC.  Such events may happen during warmer periods or when storage capacity is limited.  An OFO for under delivery means the Shipper should avoid using more gas than it has delivered to the LDC.  This may happen during periods of extreme cold and when the LDC’s ability to meet the demand of its sales customers and Firm Shippers (priority of service) is compromised.  Non-compliance with an OFO typically results in OFO related penalties and in rare cases even curtailment.


Shippers should have a good understanding of tariff policies and procedures related to imbalance management.  Imbalance positions should be monitored regularly and corresponding adjustments made to Confirmed Receipts.  Effective imbalance management can be a vital piece of managing the overall delivered gas costs for a Shipper through penalty avoidance and the mitigation of cashout costs.  Imbalances are certainly not intended to be a gift that keeps on giving.


Why Is Everything Bigger in Texas?

Author:   Andrew Bleemel, Account Manager, Kinect Energy

You frequently hear the saying, “everything is bigger in Texas.”  Why?  The saying supposedly originated as a reference to the state’s size versus the other lower 48 states; plus Texas is second in size only to Alaska based on square miles.  Texas is so big that you can take 10 of the smallest American states combined and cover only half of its square mile total.  Texas also ranks second in population with California being number one.

Since you didn’t log onto an energy website for a geography lesson, the reason this saying rings true when dealing with energy is due the most recent U.S. Geological Survey study on the Wolfcamp shale.  This formation has been crowned the largest unconventional crude accumulation ever assessed in the United States that is deemed technically recoverable.  It’s nearly three times larger than the Bakken play located in North Dakota.


The Wolfcamp shale formation is located in West Texas (see map) and covers a little piece of ground in the southeast corner of New Mexico.  It is located in the Midland Basin within the Permian Basin – historically a very lucrative area of oil and natural gas.  The recent estimates indicate the formation could hold as many as 20 billion barrels of crude oil valued at around $1 trillion based on recent crude market prices.  In addition to the crude, the formation will reportedly yield a projected 16 trillion cubic feet of natural gas and 1.6 billion barrels of natural gas liquids.  The natural gas in this play alone would supply the entire United States demand for over six months as a sole source of supply.  All of these resources are said to be trapped under four layers of shale and a mile in thickness in some locations.

The Permian Basin has been gushing crude since the 1920’s.  The Wolfcamp area has been a location for vertical drilling since the 1980’s.  It has been only recently that the full potential has been realized due to technological advances and techniques in extraction.  Horizontal drilling is occurring in the area now, and more than 3,000 wells have been drilled and completed.  Exploration companies have rushed to the area, grabbing up land for future wells.

While there still are some factors that may sway the strength and importance of the Wolfcamp play’s future production, the finding of the resource is big not only for the state of Texas but for the entire domestic energy sector.  So when you hear the saying, “everything is bigger in Texas,” don’t think only about the land mass or the population.   You can reflect upon the state’s contribution to the domestic energy sector and the “big” potential of the Wolfcamp basin.


Storing Electricity the Old-Fashioned Way with New Technology – Pumped Storage Hydropower

Author:  Jean Stammeyer, Account Manager, Kinect Energy

An abundance of technology and research has been dedicated to developing ways to store electricity such as high tech batteries, mechanical flywheels and compressed air energy storage.

However, with the increased supply in wind and solar generation many utilities have turned to a much older, time-tested technology – pumped storage hydropower.  Hydropower has been around since the late 1800s and the origins of the technology reach back thousands of years.  The ancient cultures of Greece and China used water-powered mills for necessary activities such as grinding wheat.  In 1849, an engineer named James Francis developed the Francis Turbine.  This is the same type of turbine most widely used today.

Hydropower Milestones

1849: Invention of the Francis turbine.

1882: The world’s first hydropower plant begins operations in Appleton, Wisconsin, on the Fox River.

1887: The first hydroelectric plant opens in the West, in San Bernadino, California.

1907: Hydropower accounts for 15 percent of U.S. electrical generation.

1920: Hydropower accounts for 25 percent of U.S. electrical generation.

1931: Construction begins on the Hoover Dam, ultimately employing a total of more than 20,000 workers during the Great Depression.


1937: The Hoover Dam begins to generate power on the Colorado River.

1941-1945: Bureau of Reclamation dams ramped up power output to support America’s efforts in World War II, producing enough electricity to make 69,000 airplanes and 5,000 ships and tanks during a five year period.

1980: Conventional hydropower capacity is nearly triple compared with 1920 level.

Today: A vast expansion of hydropower’s potential is possible through new technologies for conventional, pumped storage and marine and hydrokinetic projects, modernizing existing hydropower facilities and adding generation to existing non-powered dams

Source; DOE

Pumped storage provides grid reliability on a large scale and is an affordable means of storing and deploying electricity.  Pumped storage projects store and generate electricity by moving water between two reservoirs at different elevations.  On nights and weekends when the demand for electricity is low, the surplus energy is used to pump the water to the upper reservoir.  During the work week and on hot summer days when demand for electricity is high, the stored water is released through the turbines in the same manner as a conventional hydro station, flowing downhill from the upper reservoir into the lower reservoir, generating electricity.  The turbine also acts as a pump, moving the water back uphill.


The U. S. has more than 20GW of pumped storage capacity today.  There are facilities in every region of the country with proposals to develop an additional 31 GW of capacity.  The majority of the projects are currently planned in the west region in support of the increasing amount of variable generation coming on line. Clean and renewable energy sources are constantly evolving creating the need for large scale storage.  New technologies are being developed to store and squeeze energy out of the approximately 80,000 U. S. dams that currently do not produce power.

As of 2015, pumped storage hydropower has provided 97% of the total utility-scale electricity storage in the United States.  Pumped storage hydropower has proven to be a reliable and commercially available, large scale, storage resource.


The majority of pumped storage hydropower facilities have been developed by utilities, both public and investor-owned.  Independent Power Producers have shown an increased interest in new pumped storage projects and have filed a number of applications for preliminary permits with FERC.  Approximately 80% of the active permits for pumped storage hydropower projects are held by IPPs.
These preliminary permits represent more than 15,000 MW of capacity.

Estimated 62% Growth – Pumped Storage Hydropower by 2050 (51GW)


Some of the challenges developers face for new pumped storage hydropower projects have to do with environmental issues.  Previously, most operating storage projects required the construction of at least one dam along main stream rivers altering the ecology of the river system and affecting the fish and other wildlife.   A relatively new approach is to locate the reservoirs in areas that are physically separate from existing river systems. These projects are termed “closed –looped” pumped storage and have minimal to no impact to the existing river system.  Once the reservoirs are filled, the additional water requirement is minimal operational make-up water to offset evaporation and seepage losses.

Another signification challenge is the long timeline for development of a new project.  Under the current FERC licensing process, obtaining a new project license to construct takes 3 to 5 years or longer before the developer can begin construction.  Currently the licensing process is the same for both open- looped and closed- looped projects.  At this time there is not an alternative licensing process for low-impact or close-looped projects to shorten the time frame.  In addition to the licensing process, a large scale project will take at a minimum 3 to 5 years or longer to construct depending on the environmental requirements.


All I Want For Christmas – A Letter to Santa from the U.S. Gas Industry


Dear Santa,

How are you doing Mr. Claus? We hope this letter finds you well and in good spirits. Just like you, this time of year is extremely busy for us (maybe not as busy as you can get, but pretty hectic as you can imagine), but we thought was a good idea we write you. We understand you typically get these types of letters from boys and girls from all over the world, but why not one from us. You’re a jolly good elf, and we hope you may find some time in the busy holiday to add us to your Christmas Eve delivery list.

First, let me tell you we’ve been good this year. Our year-to-date production of natural gas is down only 0.2 Bcf/day from last year’s record production level of 72.4 Bcf/day, which has been impressive in the lower price environment that permeated 2016. We achieved a new record in storage this year, posting a 4.047 TCF number as we neared the end of November. Finally, we began to see our first real significant exports of LNG out of the Sabine Pass terminal, with increased volume to come in 2017. Overall a good year, but not without its challenges.

Based on our performance this year and in the past, we hope you would agree that we deserve some gifts, and we wanted to give you a quick list of what we are hoping to find in our stockings for the coming year.


As you know in the North Pole Santa, the colder the weather, the more wood for the fire to heat the elves’ homes. The same goes for us, the colder the weather and the longer the duration of the cold, the more demand for gas and the more pressure on prices. As an industry we’ve suffered through two straight generally mild winters, which have led to weak pricing heading into the new gas year. It would be very helpful to get a cold winter this year, specifically targeted over the Midwest and Northeast, and for it to hang around all the way through March. The impact on pricing from such an event would help us bring on more supply in these areas, and maybe incentivize us to increase exploration and increase the gas rig count from its record lows of 2016. While end-users may be unhappy with the increase in prices, we believe the addition of new supply would eliminate the potential for a major price shock in the market if a major demand event where to occur and more production is good in the long-term.


With the growth of shale gas out of the Marcellus play in PA and OH, we have had difficulty getting this abundant volume to markets that need it. Pricing in the region has been deflated (we saw Dominion at sub-$1.00/Dth this year), and gas has had nowhere to go. There are several projects underway in the region including Rockies Express, Columbia Gas Transmission, and Tennessee Gas Pipeline to name a few, but they have either been slow to complete or not alleviated the surplus. More pipeline capacity flowing out of the Marcellus would be a welcome gift this year, especially to serve the Northeast (Constitution Pipeline completion), the Gulf of Mexico, and Mexico exports. If you wanted to throw in a shiny new LNG export terminal in the region that would be great as well, although wrapping it may be a chore.


We do know that Santa is apolitical, and think that’s a good strategy for a sovereign state operated out of unclaimed territory in the North Pole, however, we wouldn’t mind if you could deliver us a political solution under the tree this year. A delay in implementation or complete overhaul of the Clean Power Plan would definitely be a boom to our industry over the next few years. The battle with coal is over, and we have won, replacing it as the feedstock of choice for almost all new generation entering the U.S. electrical grid. The Clean Power Plan would muddy the waters for us, forcing natural gas to cede generation share to renewables including wind and solar. With the Clean Power Plan removed, natural gas would continue its dominance as the fuel of choice for the country’s growing power needs.


As with any fossil fuel, the question always begs “Where next?” The Marcellus and Utica plays have changed the face of our industry, but they can’t pump out gas forever. Shale wells deplete at a much faster rate than traditional wells and with the increase demand for natural gas through the country and the world we believe a new shale formation would be beneficial to push gas into the next decade and beyond. Wolfcamp in Texas may be that play, with current estimates showing it to the be the largest oil/gas producing shale play in the U.S.  However, the majority of the product in the region appears to be oil, which could limit activity in the region depending on the complex movements of the global oil market. We don’t want to be selfish, but a “gas-only” shale play would be nice, and would mean we wouldn’t have to share or work with some of the big bullies on the oil side of the fence.

So that’s our list for Christmas this year Mr. Claus. We appreciate your time and consideration and do hope you can find it in your heart to make our Christmas wishes a reality for 2017 and beyond.

You’ll find milk and cookies by the NYMEX screens.


The U.S. Gas Industry