What Does High Supply, Low Prices Mean for Natural Gas Business in 2016?


by Bob Shively, Enerdynamics President and Lead Instructor

Despite low prices and falling drilling rates, natural gas production is expected to grow more in 2016 due to increased drilling efficiency, price-hedged production, and producers who either physically or financially can’t stop producing quickly.

The Energy Information Administration (EIA) forecasts that annual production in 2016 will increase by almost 2% over 2015 levels, adding additional production of over 500 Bcf. 



source: www.eia.gov

Unprecedented supply led to prices in December 2015 that were the lowest seen in any month since 1998. So much for the winter price boost that producers used to count on!

So how will high supply and low prices impact the gas business in 2016? Here are a few of my predictions:

 1. There will be some demand growth but maybe not as much as would be expected given such low prices

Most forecasts for 2016 demand suggest that levels will be similar to 2015 with increases less than one-half a percent. Why is there little demand growth given the falling prices? Most forecasts predict a warm winter in the critical heating markets of the Midwest and Northeast, thus pushing residential and commercial demand levels lower. But we may see an increase in industrial demand given new chemical and fertilizer projects coming online. 

Projections for power consumption are mixed. Natural gas generation output has already passed coal output for the first time in U.S. energy history, and some believe that any price-based fuel switching has already occurred. We believe a bit more price switching will still occur and there will certainly be more coal retirements in 2016 to help gas generation grow. But other factors will hold down the growth rate. Rapidly growing renewable generation tends to displace gas generation, and and the overall growth of electric demand is relatively flat. So while there is a little room for generation demand growth, it appears it will be modest. At most, demand may grow by less than 40% of the expected growth in production.

2. Exports will help some but may not be significant enough to change the supply/demand equation

Exports of natural gas are growing. In 2016 we will see the first major LNG exports from the U.S. with the commissioning of the Cheniere Sabine Pass terminal. Alaska has exported small amounts of LNG for many years. Receiving much less attention is the growth of pipeline exports to Mexico. Despite significant gas reserves in Mexico, a growing gas market cannot wait for industry reform to increase production of these reserves. Instead existing pipelines are carrying gas south from the U.S., and new pipeline projects will provide additional U.S. to Mexico capacity.[1] Unfortunately growing LNG and Mexico exports, like domestic demand, may soak up a portion of the excess supply but will not be sufficient to dramatically change the supply/demand equation.

3. Given supply and demand, low prices are expected to last throughout 2016

The forward price curve for 2016 does not indicate an increase in prices. In fact, you have to go to January 2018 to find a futures price higher than $3.00/MMBtu and to January 2025 to find one higher than $4.00/MMBtu!

hhfutures                    source: www.cmegroup.com

Certainly drilling will continue its decline. Current rig counts are 25% what they were just four years ago. But producers are somewhat of a victim of their own success as they have increased production per well by such an extent that fewer rigs does not reduce supply as much as one might expect.

So what will 2016 look like?

First, while many seem to focus on doom and gloom for producers, the current situation is a huge boom for many including gas customers and workers in certain industries. Some examples of the upside include:

  • Residents will heat their homes this winter for as little as half what they were paying just a few years ago.
  • Major industrial manufacturers are shifting production back to the U.S. and making long-term investments here based on low gas prices. 
  • In the electric industry, low gas prices have allowed the U.S. to begin cutting greenhouse gas emissions with a low threshold of economic pain. 
  • Supply ready for European export provides geopolitical benefits as our European allies are no longer tied to supply from Russia. 
  • For the producers that survive low prices, a solid long-term market is being locked in now.

I have been in the gas industry long enough to witness three boom-bust cycles. Each time, many preached that we had a “new normal” situation and that the industry should accept that the history of cycles is no longer valid. In each instance when everyone thought we had a new normal, we suddenly didn’t, and a new cycle began. Just remember that at some point, this cycle too shall pass.



[1] See for instance: http://bv.com/energy-strategies-report/april-2015-issue/fuels-focus-growing-natural-gas-opportunities-in-mexico


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Key Trends in the Electric Industry in 2016, Part II

by Bob Shively, Enerdynamics President and Lead Instructor

As we settle in to 2016, it seems the months ahead will be pivotal for the electric industry and particularly utilities. Last week we discussed two industry trends that we predict will  gain steam in 2016: 

  • Trend #1: Markets, regulators, and utilities get real about decarbonization of the power sector
  • Trend #2: Utilities can no longer ignore distributed resources

TRENDS 2016, message on business card held by a man

Continuing this discussion, here are two more trends that will help define the electric utility in the year ahead:

Trend #3: Importance of rate cases and resource plans will increase

In many states, rate cases have not been required on regular intervals, and utilities have contently maintained current rate structures and levels. But with ongoing concerns about distributed resources coupled with capital needs for distribution modernization, most utilities will see the need to file rate cases if they haven’t already. 

 Meanwhile, utilities have historically considered only centralized resources in their resource plans and have treated distributed resources (DR) as a reduction in load. With the growth in DR, this likely won’t result in optimal planning outcomes. Given the many issues associated with flat load growth, the need for capital spending, concerns about equity associated with distributed resources, and some regulators beginning to question the current utility business model, outcomes of current rate cases and resource plan filings may determine the future of business for many utilities.  

 Trend #4: Inexorable growth of competitive markets

An important yet little-known fact is that the amount of power bought and sold under competitive markets has continued to grow significantly in recent years. On the wholesale side, organized competitive markets have grown significantly through:

  • MISO’s expansion into Arkansas, Louisiana, Mississippi, and eastern Texas, which brought an additional 50,000 MW of generation into MISO’s markets
  • SPP’s expansion into six upper Midwest states that added 5,000 MW into SPP’s markets
  • the growth of the Energy Imbalance Market in the west, which allows over 26,000 MW across eight states to participate in a real-time market run by the California ISO

Meanwhile usage by end-use customers buying their power directly from marketers has grown from less than 5% to close to 25% of total U.S. usage over the last decade. And in many regions, large customers continue to push for the rights to contract for their own power supply. Many non-traditional companies such as Google, Apple, Comcast, and AT&T are developing customer-focused services that chip away at the concept of utilities as the provider of energy services. Utilities must plan a business future that clearly defines a successful role for utilities in a world of multiple competing service providers. 

 So what does all this mean for the big picture of the industry?

In a recent publication, the Edison Foundation[1] identified three long-term trends that they believe will drive a utility transformation:

  • The transition to a clean energy future
  • A more digital and distributed grid
  • Individualized customer services

We agree, and we believe that the trends we’ve identified for 2016 will make it the year that a complete redefinition of the electric utility and its role begin to take shape. 



[1] See Key Trends Driving Change in the Electric Power Industry at http://www.edisonfoundation.net/iei/Documents/IEI_KeyTrendsDrivingChange_FINAL.pdf

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Key Trends in the Electric Industry in 2016, Part I

by Bob Shively, Enerdynamics President and Lead Instructor

In future years, we likely will look back on 2016 as a transformational year in the electric industry. This week and next we will examine key trends that in the coming year may move the industry toward a very different future. 

Trend #1: Markets, regulators, and utilities get real about decarbonization of the power sector

In an unprecedented switch, the last several months of 2015 showed more generation in the U.S. fueled by natural gas than coal.


            Source: www.eia.gov

With numerous coal retirements and all indicators pointing to a long period of low-priced natural gas supply, it appears this will be a permanent shift. While natural gas is not a no-carbon source of electricity, it does reduce greenhouse gas emissions by at least 50% per MWh compared to coal. Meanwhile, output of non-hydro renewable sources continues to set records in the U.S., and this too will be an ongoing trend.


           Source: www.eia.gov

In 2016, we likely will see the first new nuclear reactor go into service in 20 years as TVA’s Watts Bar Unit 2 goes online. Construction will continue on four units (two in Georgia and two in South Carolina) although it will be 2019 before they begin coming online. And despite ongoing political posturing and court filings, most states are already working with utilities and interest groups to prepare initial plans to reduce power plant greenhouse gas emissions under the Clean Power Plan rules issued in 2015 by the Environmental Protection Agency (EPA). 

A likely outcome will be many states creating multi-state carbon cap-and-trade programs like the current Regional Greenhouse Gas Initiative (RGGI) and California/Quebec program. Once there is money to be made in decarbonizing generation, we’re likely to see a new wave of innovation regardless of what happens with the current EPA rules.


Trend #2: Utilities can no longer ignore distributed resources

Distributed energy resources (DER) including distributed generation (DG), demand-side management (DSM), and distributed storage are poised for rapid growth. According to energy collage
EIA data, distributed solar output through September 2015 grew by 29% over output to that point in 2014.

General Electric estimated that in 2012 39% of new capacity additions worldwide were distributed generation (DG)[1]. Meanwhile controllable loads have become an important resource and, according to the North American Electric Reliability Corporation (NERC), make up 5% of reliability capacity in the U.S.[2] Distributed storage is also hitting the mainstream, most notably through a highly publicized announcement by Tesla but also with quieter roll-outs from other companies.

These resources will only grow as technologies become more advanced. In 2016 the cloud-connected smart home will see advances with new products rolled out by companies like Google and Apple, and others such as Microsoft and Amazon are not far behind.

While electric vehicles might be considered new demand, we include them as a resource because their ability to charge when power is most available makes them a new controllable load. In 2016, Chevy will introduce the Bolt with a 200-mile range and a $30,000 price point. Nissan will offer a new Leaf, and Tesla and other European manufacturers are expected to make additional announcements about lower-cost and longer-range vehicles. Even with low gasoline prices, government support in locations like car-heavy California will likely continue to boost EV growth. 

Given these advancements in various technologies, all utilities will need to restructure their distribution planning to assume very different usage/production patterns by customers and rates will likely need to be redesigned to give the right signals to consumers.

Next week we’ll look at two more key electricity trends to watch for in 2016, and in the weeks after we will explore trends that are driving the natural gas industry in the year ahead.


[1]  Brandon Owens, The Rise of Distributed Power, available at: https://www.ge.com/sites/default/files/2014%2002%20Rise%20of%20Distributed%20Power.pdf

[2] http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2014LTRA_ERATTA.pdf calculated by going through each reliability council and totaling peak demand and demand response values


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New Utility Business Models Must Address Solar Integration

by Bob Shively, Enerdynamics President and Lead Instructor

How utilities should compensate customers for solar power put onto the grid and whether they should charge customers for costs of grid connection are key issues that utilities face in 2016 and beyond.

Over 44 states have mandatory net metering rules. These rules require the utility to compensate solar customers by paying the retail rate and allowing the customers to “bank” power generated when the sun is shining and use it to offset power needs at night or on cloudy days.

Unfortunately, there are real issues associated with net metering, and it is hard to gain agreement that the retail rate is truly the right number to pay. Issues include:

  • whether time-sensitive power supply costs and fixed costs to maintain transmission and distribution infrastructure are being shifted from solar to non-solar customers
  • whether the costs of required distribution upgrades are allocated fairly
  • whether solar customers are being compensated for additional values they provide to the system.

Such issues have sparked discussions in more than a dozen states at either the legislative or state commission level about whether something other than net metering is more appropriate.

In most communities public sentiment strongly supports solar energy. Utilities’ requests to move away from net metering ignites accusations that utilities are anti-solar. Some utilities and commissions are seeking a middle ground that keeps net metering but:

  • adds minimum variable or fixed fees
  • moves net metering to time-of-use rates so that bill netting reflects the time value of power provided and/or used[1]
  • creates value-of-solar tariffs that pay a unique price based on calculated value to the grid

We are sure to see many debates, proceedings, and possibly some regulatory decisions on this issue during 2016.  

Meanwhile, utilities and their regulators must be making longer-term decisions on how to react to growing distributed resources (DR) including rooftop solar but also other forms of customer-owned generation, storage, and price-responsive load.

While tweaking the status quo may push the issue off a few years, it is unlikely to create a long-term sustainable business model for utilities unless the growth of DR proves to be an unfulfilled expectation. Utilities instead must plan now for a different future and include DR in their resource planning processes. And utilities and regulators must figure out how to pay for DR in a manner that creates economic benefits for all and creates mechanisms to encourage the proper investment for the right resources.  

Such change will neither be easy nor quick. Transformations always create winners and losers, and in a regulatory environment potential losers fight long and hard to avoid these outcomes. Since most of the pertinent regulation will happen at the state level, the possibility of 50 different solutions exists. It will be interesting to watch in 2016 how the leading states address these issues and how the regulators and utilities in the remaining states respond.


[1] See for instance the California Public Utilities Commission proposed decision dated December 15, 2015 summarized here: http://www.utilitydive.com/news/california-regulators-propose-to-keep-retail-rate-net-metering-for-solarwi/410873/



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New Edition of ‘Understanding Today’s Natural Gas Business’ Now Available

Looking to brush up on natural gas trends in 2016
or just starting in the Enerdynamics_Gas_Cover_NoCrops_Print_reduced size
energy industry and need a solid overview of how the natural gas business operates? 

Enerdynamics recently released its 2015 edition of Understanding Today’s Natural Gas Business, a 150-page detailed overview of the North American gas industry. This book, one of three industry primers offered by Enerdynamics, presents an insider’s perspective on the fast-paced and unpredictable business of natural gas. Topics covered include:

  • natural gas origins
  • the physical system and how it’s operated
  • market dynamics and players
  • risk management techniques
  • an up-to-date look at today’s regulatory environment

Understanding Today’s Natural Gas Business is ideal for those new to the industry as well as veterans seeking a “big picture” look at the natural gas business. The book is easy-to-read, contains a number of charts and diagrams to help simplify complex industry concepts, and includes a glossary and list of acronyms. Many utilities find that providing a copy of this primer to new employees on their first day strongly increases their uptake of the unique business aspects of the industry.

Click here to download a free chapter of Understanding Today’s Natural Gas Business. Buy the paperback edition before Jan. 31, 2016, and save an additional $10 on the discounted cover price. Just use code EISAVE10 at checkout. Click here for details or to purchase this book.

We also offer quantity discounts and free shipping to companies and bookstores that buy 25 copies or more. Contact us at 866-765-5432 or info@enerdynamics.com for details.


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Southstream Pipeline: Will Economics Triumph over Politics?

by Christina Nagy-McKenna, Enerdynamics Instructor

Late last month Turkey shot down a Russian fighter jet after it allegedly flew into Turkish airspace. As the world waited for the Russian 145122298 (2)Federation’s response to what its President Vladimir Putin called “a stab in the back,” few expected that a major natural gas project would be sidelined and thus deal a blow to both countries. And yet, the Federation suspended this Gazprom-sponsored project, as well as all other trade with Turkey, as part of economic sanctions meant to penalize the country financially.

This action by Gazprom and the Russian government does not just harm Turkey. Cancelling the Turkish Stream pipeline project will have longer-term negative implications for both countries as well as prospective pipeline customers. After all, what exactly does a region do with miles of pipe that is custom made for a project that was just suspended?  And what do customers like the Italian energy company Eni do when the pipeline they were counting on to be finished in 2018 is now in limbo? Are these issues enough to bring all parties back to the table to negotiate? As of this morning, the answer seems to be yes.

Turkish Stream is the second Russian pipeline project to be scrapped since the winter of 2014 when tensions escalated with Ukraine and Crimea voted to be annexed to the Russian Federation. The $12-14 billion project was to transport Russian gas across the Black Sea to Turkey and then into Southeastern Europe instead of through the Ukraine as originally planned in the Southstream Project.

Now that Russia has suspended Turkish Stream, it will need to store miles of pipe, estimated to be worth $1.95 billion, that is bespoke to the Black Sea. Perhaps the Federation has only hit the pause button on the project. Perhaps after a period of time when tensions have eased, the Gazprom will be allowed to resume construction of the pipeline and its business with Turkey. This certainly seems possible, especially after this morning’s news: President Putin said the project can continue if the European Community (EC) gives certain written guarantees to Turkey. Details about what exactly the Russian Federation expects from the EC will be forthcoming.

Gazprom mapTurkish Stream Pipeline System Map, Gazprom Website, December 2015



Burminstrova, Svetlana and Stubbs, Jack, “Turkey Row Leaves Russia Stuck with Abandoned Gas Pipes Worth Billions,” Reuters, December 3, 2015.

Kottasov, Ivana, “Russia Suspends Turkish Gas Pipeline Project Over Downed Warplane,” CNN Money, December 3, 2015.

Nissenbaum, Dion and Peker, Emre, and Marson, James, “Turkey Shoots Down Russian Military Jet,” Wall Street Journal, November 24, 2015.

“Turkish Stream Pipeline Project a Go if Turkey Gets Guarantees from Brussels: Putin,” Daily News, December 17, 2015.




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What is a Reasonable Rate of Return on Utility Infrastructure?

by Bob Shively, Enerdynamics President and CEO

“..the process of setting an allowed ROE has consistently proven to be the most contentious and subjective part of a rate case proceeding.”[1]

Much of the key natural gas and electricity infrastructure in the U.S. operates under the cost-of-service ratemaking. This is true for electric Investment-versus-return-concept-000069428007_Mediumtransmission and distribution, gas distribution, and most gas transmission lines. Cost-of-service ratemaking sets rates based on forecasted costs of providing service plus a “reasonable” rate of return on the equity invested by shareholders to build the capital facilities necessary to provide service. The return on equity (ROE) authorized by the regulator is not guaranteed since business results such as expenses and sales often impact the true return. Still, the authorized ROE is a key component of the expected level of earnings for a regulated utility.

Under ratemaking theory, the authorized return should balance the interests of ratepayers and shareholders: The rate should be just high enough to attract needed capital to maintain service reliability but no higher since anything above that level would provide shareholders with a profit level above what is necessary.

Rates of return are set by regulators after testimony by interested parties and analysis by regulatory staff. They vary based on the return on alternate investments such as bonds and other conservative business option, the amount of capital required, perceived risk associated with a specific company, and the regulatory climate in a specific locale.

Public Utilities Fortnightly has annually surveyed ROE authorized by state commissions since 1982. This year, authorized returns in the survey ranged from a low of 8.3% (ATCO electric and ATCO gas) to a high of 12.0% (Lockhart Power Company).  As shown in the graph below, most decisions clustered in the range of 9.0 to 10.3%.

2015 ROE

In 2015, the median ROE was 9.8%. Since the economic downturn in 2008, ROE have dropped significantly as interest rates have fallen and investors have looked for lower risk inherent in most utility investment.

Median ROE

Given the size of many utilities’ ratebases, a small change in ROE can result in a change of authorized earnings of many millions of dollars.  And, of course, the flip side to that is that a small change can result in a change of rate levels paid by consumers.

So the next time your company goes in for a cost-of-capital case, you’ll realize just how much is riding on the percentage authorized by the regulator. And using the information from the Public Utilities Fortnightly annual study, you’ll be able to see how your company stacks up compared to other utilities.


[1] “Equity Returns: ‘Allowed’ vs. Earned”, Phillip S. Cross, Public Utilities Fortnightly, November 2015

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