Will China transform the world of energy?

Posted on May 17, 2013 by

by Bob Shively, Enerdynamics President and Lead Instructor

When I started in the energy business back in the early 1980’s, the utility paradigm was topower plants in Hong Kong continually build more power plants to serve growing customer loads.  This lead to environmental and economic difficulties, especially as the cost of completing planned nuclear power plants skyrocketed.

At the utility where I worked, Pacific Gas and Electric, an outside scientist named Amory Lovins gained notoriety by forcefully suggesting an alternative path that included energy efficiency and renewable power.  As the story went around the company (and I don’t know if it is actually true), PG&E executives would hide when Lovins came in the building so they wouldn’t have to listen to him telling them over and over that they needed to change their business model.  Ultimately the California regulators did listen, and both California and PG&E have transformed their energy systems into one of the more efficient and renewable-based markets in the world. And in most U.S. states, at least energy efficiency has become a key focus of electric utilities [1].

But in the U.S. the debate still rages on concerning the right energy future.  Should other states follow California’s lead with use of renewables, or is it better to focus on more traditional energy sources?  Is climate change real, and should we change our energy mix to reduce carbon emissions?  It seems that in Washington, we just aren’t capable of consensus for action at this point.  Instead it’s possible the impetus for change will come from outside.

As we suggested in a recent blog post, behind-the-scenes efforts to work with China may result in that country leading significant movement toward a cleaner energy mix. [2]  One such effort is being led by Amory Lovins’ Rocky Mountain Institute (RMI).  Lovins recent book, Reinventing Fire, laid out RMI’s views on how the U.S. could transform its energy mix.  RMI is now working with high-level officials and organizations in China to develop a blueprint for how China might lead the clean energy future.

According to Lovins, it could result in change that is “one of the most transformative that’s ever happened in global energy.” [3] When a lot of folks talk that way, it just sounds like hype.  Especially when China is the world’s largest coal generator, and electric output in China is expected to more than double by 2035.  But then again, 30 years ago who ever thought that electric utilities throughout the U.S. would be trying to convince consumers to buy less of their product?

Forecasted Electricity GenerationSource: U.S. Energy Information Administration International Energy Outlook 2011

[1] See for instance, the U.S. Energy Information Administrations Today in Energy report U.S. Energy Intensity Expected to Continue Its Steady Decline Through 2040  http://www.eia.gov/todayinenergy/detail.cfm?id=10191

[3] From the Google Hangout talk Reinventing Fire China: http://blog.rmi.org/blog_2013_05_10_Reinventing_Energy_China

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Mexican Natural Gas – The Next Paradigm Buster?

Posted on May 10, 2013 by

by Bob Shively, Enerdynamics President and Lead Instructor

Back when I worked in Calgary in the early 1990s, a consultant’s study made the rounds mexico mapsuggesting that Canadian producers should be alert to a possible competitive threat from the south.  Specifically the report stated that theoretical natural gas reserves in Mexico were so robust that one day Mexico might supplant Canada as the preferred source of imported natural gas to the United States.

Twenty years later, Mexican imports of U.S. gas have grown by a factor of 10, pipeline companies are rushing to build new pipes from the U.S. into Mexico, and Mexico imports liquefied natural gas (LNG) from counties such as Qatar and Peru. Meanwhile Mexican industrial and power plant gas demand has more than doubled in the same timeframe.  Does this mean the consultants had it all wrong?  Maybe, but maybe they were just well before their time.  Recent discoveries of significant shale gas resources in northern Mexico, coupled with potential political and regulatory reforms being pushed by the newly elected President Enrique Peña Nieto, suggest the possibility of significant future growth in Mexican gas production.

US gas exports to Mexico

Mexico gas supply and demand

Source of above graphs:  U.S. Energy Information Administration March 13, 2013 Today in Energy [1]

Gas demand in Mexico is largely dominated by use by the national oil company PEMEX, which uses gas for refineries, petrochemical plants, and oil exploration and production.  This accounts for about 40% of demand.  Another 33% is used for electricity generation and the remainder is used mostly by non-PEMEX industrial customers.  Mexico used about 2.4 Bcf in 2011 and projections are that gas demand will continue to grow due to continued construction of gas fired power plants and growth in industrial output.   Gas demand has risen on average by 4% a year between 2007 and 2011. According to projections by the federal electric monopoly Comisión Federal de Electricidad (CFE), demand for gas could triple to over 7 Bcf by 2027 just due to power plant growth [2].

Meanwhile, gas production in Mexico has failed to keep up with growing demand despite robust reserves. In the time frame of 2007 to 2011, gas production grew by 1.2% per year while demand was growing by 4%. Beginning in the early 2000s, Mexico found it necessary to significantly grow imports to meet demand, including significant growth in net pipeline imports from the U.S. and construction of three LNG import terminals.

Mexico gas sources 2011

Mexico has about 17 Tcf of proven reserves.  Technologically feasible reserves of conventional natural gas greater than 60 Tcf [3].  Much recent study has gone into the potential for shale gas reserves.  An initial EIA assessment estimated 681 Tcf of technically recoverable shale gas, which is the fourth largest of any country studied by the EIA [4].  And much of this gas is located in regions near the U.S. border.

So could Mexico one day become significant importer of gas to the U.S., thus keeping U.S. gas prices lower?  Or will Mexico continue to become a growing source of export demand for U.S. gas causing U.S. prices to rise?

As with many things in the energy business, the future has a lot to do with politics.  Mexican gas production has historically been constrained by lack of capital and lack of attention.  Much of this has to do with nationalization of the Mexican gas and oil sector in 1938 with Petróleos Mexicanos (PEMEX) designated as the sole oil and gas operator in the country.  Provisions were added to the Mexican Constitution prohibiting foreign companies from owning oil and gas resources.

PEMEX is one of the largest oil producers in the world, but has tended to focus more on oil production than natural gas.  And the Constitutional provision has prevented other companies from investing in PEMEX’s stead.  The desire to prevent foreign companies from taking over Mexican resources has been strong, and historically there has been no political will to alter things.  But this may now be changing.  Reforms in 2008 allowed PEMEX to create incentive-based service contracts with foreign oil and gas companies that would allow these companies to participate in exploration and production (although foreigners still cannot own the resources).

In 2011 PEMEX awarded the first foreign production licenses for oil in more than 70 years and the same model can be used for gas exploration and production.  And in the Presidential election of 2012, Peña Nieto included more extensive energy reform as one of his campaign goals. As of mid-2013 he seems to be building a political coalition that might indeed pull off significant reforms.

So we can conclude that the gas appears to be there.  Whether the politics, economics and technological factors will align to make it happen remains to be seen.  But it appears much more likely than it did 20 years ago.

References:

[2] Data on demand and production is taken from various U.S. Energy Information Administration (EIA) sources unless otherwise noted

[4] World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States, U.S. Energy Information Administration, available at http://www.eia.gov/analysis/studies/worldshalegas/pdf/fullreport.pdf

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Is the U.S. Ready for National Greenhouse Gas Regulation?

Posted on May 1, 2013 by

 by Bob Shively, Enerdynamics President and Lead Instructor

Flash back eight years ago to 2005.  U.S. greenhouse gas emissions (GHG) from energy consumption were increasing annually with emissions having grown by almost 20% since GHG1990. The Bush Administration announced in 2001 that the U.S. would not implement the Kyoto Protocol. Rather than pursuing regulatory mandates, the Administration announced support for voluntary measures and tax credits to encourage businesses to reduce GHG emissions[1].

Meanwhile in Europe, the European Union launched the European Union Emissions Trading Scheme (EU ETS), which regulated GHG emissions in 31 European countries through a cap-and-trade mechanism. Its goal was to reduce emissions by 21% by 2020.  And although emissions in China had grown significantly in recent years, China’s energy-related emissions were still almost 10% less than those in the U.S[2].

U.S. GHG Emissions from the Consumption of Energy 1990-2005
(in millions of metric tons)

GHG USSource: U.S. EIA International Statistics 

How different the world of GHG looks today.  By the end of 2011, the U.S. has reduced energy related GHG emissions by 8% since 2005. With the ongoing implementation of the EU ETS, the European Union had reduced GHG by 10%.  And China, with its rapidly expanding economy, had increased emissions by a whopping 59%.

GHG Emissions from the Consumption of Energy 2005-2011
(in millions of metric tons)

world GHG

As discussed in Enerdynamics’ recent Energy Insider[3], key factors contributing to the reduction in the U.S. include the economic downturn in 2008, growth of renewable generation, energy efficiency efforts, and perhaps most importantly a major shift from coal to natural gas-generated electricity.

Interestingly, as U.S. GHG emissions have declined in recent years, there is revived talk that the time may have come for national regulation of GHG emissions. Certainly we’ve been here before.  Legislative action has stalled numerous times, included the demise of the Waxman-Markey bill in the U.S. Senate in 2010 (despite having already passed the House and having the support of President Obama)[4].  But the U.S. Supreme Court in 2007 ruled that greenhouse gases fit within the definition of air pollution in the Clean Air Act, thus requiring the EPA to regulate GHG if the EPA determined that the gases endangered public health.  Subsequently the EPA ruled that GHG do endanger public health, and this determination was upheld by the U.S. D.C. District Court of Appeals in 2012.

The EPA has already issued proposed rules for new power plants[5], and many believe that the next logical step would be to extend rules to existing units.  The Wall Street Journal recently reported that the Edison Electric Institute, a utility trade group, may take a cooperative role in working to create national GHG regulations[6] based on a belief that legislative solutions could be more flexible than EPA rules.  And George Shultz and Gary Becker of the conservative Hoover Institution recently wrote a paper suggesting the time has come for a national revenue neutral carbon tax[7].

So does this mean that fear of EPA regulation will coalesce enough parties to get legislation passed?  In today’s fractured Washington politics, that is hard to predict.  But it is a renewed possibility.

References:

[1] See: Bush Unveils Voluntary Plan to Reduce Global Warming, http://archives.cnn.com/2002/ALLPOLITICS/02/14/bush.global.warming/index.html

[3] See U.S. Greenhouse Gas Emissions at 20-year Low —
What Happened?    http://marketing.enerdynamics.com/Energy-Insider/2012/Q3Electricity.html

[4] For an interesting discussion of how this bill failed to pass in the Senate, see the New Yorker article As the World Burns available at http://www.newyorker.com/reporting/2010/10/11/101011fa_fact_lizza?currentPage=1

[6] Wall Street Journal, Power Sector Plans for New Rules, April 24, 2013

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Energy Companies Using ‘Executive Forums’ to Effectively Train Employees

Posted on April 26, 2013 by

By John Ferrare, Enerdynamics CEO

A new offering by Enerdynamics that’s really taken off this past year is the executive forum. We’ve done four of these in the past year, and each one has been tremendously successful. While not exclusive to executives, the idea is that, in contrast to the interactive seminars we usually present, the forum is a way to get a lot of information out to much larger groups of people than we could typically manage in a traditional seminar.

Here’s how this works: Typically a client will have a specific audience in mind and want to educate this audience on a very specific topic. The most recent forum we presented was for a major producer of wind turbine equipment. This group wanted to better understand how energy markets work, how renewables fit in energy markets, and how the role of renewables in markets around the world is evolving.

In this case (as in most), the client worked closely with our course development team to come up with an agenda that matched its very specific parameters. To do this, we began with content from a number of our existing seminars and then systematically honed this down to, in this case, a half-day presentation. The rest of the day was reserved for Q&A and other industry professionals.

Another example is a basic electric class that we presented to a law firm’s energy practice. While this particular forum relied heavily on existing content, we made sure to package it into clearly identified and stand-alone modules that were presented at specific times during the two-day event. As with any audience that bills time to clients, time is money. So this client wanted its attorneys to be able to select the topics that most interested them and attend only those. Again, the forum was highly successful and the client is asking for a follow-up event later in the year.

Another law firm was interested in the economics of the North American energy markets, specifically how shale gas is changing this dynamic. The client saw an opportunity in this area and needed to better understand how the markets were related and where they are likely headed. The result was a day-and-a-half forum that was well received by attendees and achieved all of the client’s goals.

While these forums are often combined with another company event, they need not be. They range in length from four hours to two days and have had audiences of up to 65. And surprisingly, even with a large group, interactivity can still be achieved. Companies find it is incredibly valuable to have their high-level employees all hear the same information on a focused topic and then have an opportunity to discuss and reflect on how this affects their business strategy.

If this sounds like an idea that could benefit your company, please contact me at jferrare@enerdynamics.com or 866-765-5432 ext. 700.

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Will Low Natural Gas Prices Stall the Shale Gas Boom?

Posted on April 19, 2013 by

by Christina Nagy-McKenna, Enerdynamics Instructor 

The U.S. natural gas market is on the verge of a decades-long growth period due to the robust development of shale gas. While optimism about U.S. gas supplies is not new – it has been a hot topic in the trade press for the past year – data regarding the dwindling number of natural gas rigs raises the question of how this expansion will continue as the actual number of new wells diminishes.

 Also, with natural gas prices below $4/MMBtu at the wellhead for a significant portion of this past winter, it makes sense to question if developers have sufficient economic incentive to continue drilling new wells and bringing more supplies on line. The decision hinges in large part on the developers’ cost of production as compared to market prices. However, getting to the true production price is not as straight forward as it may appear, and as such there is some disagreement as to what it will take for shale developers to be profitable.

New data concerning Barnett Shale seems to indicate that prices do not have to increase as much as previously thought in order for development of shale formations to continue.

A recently released study about Barnett Shale by the Bureau of Economic Geology (BEG) at the University of Texas [1] determined that 44 Tcf of natural gas, enough to meet almost two years of demand by the U.S. market, will be produced by the Barnett formation over its lifetime (approximated as 2050). BEG based this forecast on an average market price of $4/MMBtu for the gas, which, while somewhat greater than today’s $3.50/MMBtu, is a far cry from the higher prices natural gas producers grew to love in late 2000s.

The BEG study is the first to look at data from individual wells within the Barnett formation. Data from approximately 15,000 wells drilled in the past decade was examined well by well rather than averaging the production from all wells as other studies have done. BEG found that not all parts of the formation produce equal quantities of natural gas. Many wells were flops, and perhaps only half of the 8,000 square miles of the formation will actually yield an economical product for its developers.

Contributing to producers’ ability to make money at low natural gas prices are revenues from natural gas liquids (NGLs) and associated oil.  Wet gas, the liquid rich gas that contains oil and NGLs such as propane and butane, is worth more money due to the higher values associated with oil and NGLs. The Bakken Shale formation in North Dakota holds shale oil that contains shale gas as well. The average by-product of oil production is almost 1 million cubic feet of natural gas per barrel. Eagle Ford Shale in Texas has yielded 1.5 million cubic feet per barrel.[2]

Thus, producers in these regions can produce shale gas at a much lower net cost than those that are solely producing dry gas.  At this time, the gas in Bakken Shale is being flared as the infrastructure to capture and market the gas does not exist.  Plans are underway to change this as the State of North Dakota is working with developers to sort out land use issues that make the building of gathering facilities very complicated.

Read the full article that includes a discussion on falling gas rig counts and the relation to gas prices in our latest issue of Energy Insider.

References:

1. “New Rigorous Assessment of Shale Gas Reserves Forecasts Reliable Supply from Barnett Shale Through 2030,” The University of Texas at Austin web site, February 28, 2013.

2. February 2013:  Energy Strategies Report, Dr. Jim Gooding, Black & Vietch.

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The Value of Regional Transmission Organizations, Part II

Posted on April 12, 2013 by

By Matthew Rose, Enerdynamics Instructor

Last week we introduced this topic with Part I of this article and discussed the current landscape of the RTO and RTO development. This week we continue our examination of map and the shadow of Electric PlugRTOs with a discussion on the value and perceived benefits of RTOs as well as the issues and objections voiced by some stakeholders.

RTO benefits
There is no shortage of industry discussion regarding the qualitative benefits of a regional transmission organization. Many of the ongoing regulatory proceedings and rulings generally include discussion of the rationale and benefits for RTO-based organizations to handle the wholesale bulk power market. A listing of some of the key benefits follows:

What RTOs Do Implications
Provide independent transmission system access Equal and non-discriminatory transmission system access using transparent and open access transmission tariffs (OATT)
Perform efficient market operations Operate energy, capacity, and ancillary service markets using low-cost unit commitment, dispatch, and congestion management
Facilitate larger, competitive, and “liquid” markets   RTO rules encourage greater market participation, greater liquidity, and pricing options for participants
Coordinate regional planning Integrated system planning with regional expansion needs and plans; includes recent ruling FERC 1000
Deliver improved reliability Ensure reliability through efficient resource sharing and formalizing rules for handling “seams” issues
Ensure market competitiveness  Employ a “market monitor” to assess market competitiveness and ensure no market power or members with undue influence
Foster alternative resource options Facilitate markets for demand response and integrate renewable resources in the resource mix
Integrate risk management tools Provide hedging products including financial transmission rights to mitigate congestion risks

In addition to the above qualitative benefits, there have been recent efforts to quantify the extent of RTO benefits. In this process, the various RTOs have identified a series of value drivers and developed estimates of the economic value each provides to the RTO.

For example, the PJM Interconnect claims that its services provide regional savings benefits of more than $2 billion annually including savings from energy production cost from $340-$445 million annually.[1]  The Midwest ISO claims similar total annual economic benefits including an estimated $180-$200 million annually for its centralized dispatch of energy operations.[2] The Southwest Power Pool estimates that its move to a Day 2 market (locational marginal price as well as day-ahead and real-time spot markets) may result in annual net benefits of $100 million.[3]

As a point of detail, a more comprehensive forecast of benefits by value driver for the Midwest ISO is shown below:

Midwest ISO Value Proposition [4]  
Value Driver Estimated Annual Economic Benefit (in $ millions)
Reliability $180-$270
Dispatch of Energy $180-$200
Regulation/Spinning Reserve $130-$150
Wind Integration $240-$285
Compliance $60-$95
Footprint Diversity $760-$950
Generator Availability $455-$570
Demand Response $110-$145
MISO Cost Structure -($225)
Total Net Benefits  $1,890-$2,440
Note: economic benefits are rounded up based on MISO values

To the extent that these economic benefits are real it requires greater attention to the detail behind the valuation. For example, what methodology was used to arrive at the comparative costs to determine savings?  With this in mind, the FERC completed a Report to Congress aimed at examining the formal benefits of RTOs through a series of standardized metrics.[5] This effort was advanced by the United States Government Accountability Office.[6] The RTO metrics were designed to measure performance on three dimensions:

  • market benefits
  • organizational effectiveness
  • reliability

A comprehensive review of these metrics is outside the scope of this discussion (but will likely be addressed in a future Energy Insider issue). What is important is the recognition that the FERC Report identified 57 different metrics that it believes should be evaluated on an ongoing basis. This amplifies the recognition that determination of RTO benefits is wide ranging and includes numerous factors.

RTO objections
In discussing the economic benefits of RTOs, it is only fair to talk about the range of stakeholders who continue to voice objections to the RTO structure. The American Public Power Association (APPA) has maintained that RTO-run electricity markets fail to produce just and reasonable electric rates.[7] Some of their key objections include:

  • Offers to sell power are not directly connected to the sellers’ cost of production. The construct where the final bid establishes the price paid to all sellers needs to be analyzed as a means of ensuring lowest supply costs.
  • The current bidding structure and reliance on locational marginal pricing shows no evidence between locational price signals and the construction of new generation or transmission facilities.
  • Consumers are paying millions in additional charges required by RTO-run locational capacity markets, especially given the corresponding lack of market response to build new capacity in high-cost areas.
  • Limited options exist for long-term bilateral contracts due to the influence of high-price sellers and the growth of financial deals (versus physical transactions).

Moving forward, the APPA has suggested placing a FERC moratorium on the establishment of new RTO markets and encourages a formal cost effectiveness investigation into the impacts of RTO-run organizations.  (A review of the accompanying references used in this discussion includes numerous examples of objections to the current RTO structure.)

Conclusion
In the end, it is clear that most stakeholders see the benefits of moving to a RTO-based transmission organization. The efforts, resources, and dollars invested in the current RTO system make it difficult to consider reverting to another framework without significant policy backtracking. Still, there are areas where further efficiencies and market design considerations should and may be pursued. The goal now is to to build upon the efficiencies and grid access in RTO-based regions while widening the participation in devising methods to more accurately measure value and benefits.

References

1. PJM, PJM Efficiencies Offer Regional Savings ( taken from PJM website- PJM Value Proposition)

2. MISO, 2011 Value Proposition, January 2012 (presentation on MISO website)

3. SPP press release, SPP Files Tariff Revisions for Integrated Marketplace,  February 2012.

4. MISO, 2011 Value Proposition, January 2012 (presentation on MISO website)

5. FERC, Performance Metrics for Independent System Operators and Regional Transmission Organizations, April 2011.

6. Electricity Restructuring: FERC Could Take Additional Steps to Analyze Regional Transmission Organizations Benefits and Performance. GAO-08-987, September 2008.

7. Caplan and Brobeck, Have Restructured Wholesale Electricity Markets Benefitted Consumers, Electricity Policy.com, December 2012.

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The Value of Regional Transmission Organizations, Part I

Posted on April 4, 2013 by

By Matthew Rose, Enerdynamics Instructor

Decisions made by regulators more than a decade ago formalized a shift to organized wholesale transmission organizations for much of the United States. As electric deregulation advanced in various states in the 1990s, federal regulators saw a need to encourage an independent structure to facilitate the planning and operation of wholesale market operations. This included the need to ensure non-discriminatory access to the transmission system especially as operations crossed state boundaries and covered large regional areas. The reliance on Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) has provided a workable platform for much of the U.S.[1]

This move also has resulted in a wide-ranging set of new rules and markets as well as a shift in how revenues and payments are handled and distributed.  It is fair to say that this transition to RTOs has had its share of debates, issues, and even the occasional need for judicial oversight. This article examines the current landscape of the RTO and RTO development. Next week we will follow with Part II and discusses the value and perceived benefits of RTOs and explore the issues and objections voiced by some stakeholders.

Current landscape of RTOs
To truly grasp the benefits and value provided by RTOs, it is important to first understand the current landscape of RTO-operated markets. Most notably, the reliance on RTOs has not been fully standardized across the country. Despite Federal Energy Regulatory Commission (FERC) encouragement (and even a failed move to a standard market design) there are large geographic areas of the country with no organized wholesale market operation. This includes not only some investor-owned utilities but also the public power and electric cooperative operations. Still, RTOs cover about two-thirds of the nation’s electricity customers.

The development of RTOs, however, continues to emerge over time. With the input of regulators and stakeholders, the rules and markets are constantly being refined and modified. For example, the design of markets to facilitate demand response opportunities was not envisioned at the outset of the transition to RTOs, but now this design is a vital piece of the value stream across all the RTOs.

There are also differences in the market design details across the RTOs. These differences reflect varied market composition, maturity of the RTO operations, capacity availability, and unique elements of the respective markets. For example, there are certain market programs such as encouraging energy efficiency as a resource in the forward capacity market that are currently offered by a couple of RTOs.

Membership within the various RTOs also is growing. For example, Entergy Utilities recently submitted an executed transmission owner’s agreement with the Midwest ISO. Entergy claims that joining the MISO will save the organization $1.4 billion in the first decade of membership.[2] East Kentucky Power Cooperative (and its 16 distribution utility owners) also announced it will join the PJM Interconnect pending FERC and Rural Utilities Services approvals.[3] These considerations all point to a working structure that offers its members value and benefit to continue ongoing growth and direction of the RTOs.

Next week’s post will take a deeper look at the value and benefits as well as the objections that some have to the RTO model.


References:

1. In this discussion the terms RTO and ISO are used interchangeably.

2. The Street, Entergy Utilities Proceed With Key Step towards MISO Integration, December 2012.

3. The Lane Report, East Kentucky Board Approves Integration Into Regional Transmission Organization, February 2013.

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