Author Archives: Richard Meyer

Richard Meyer How well-functioning natural gas markets provide safe, reliable, and cost-effective service to customers.

Natural gas is a primary energy source utilized by more customers than ever before.

The US natural gas market—itself comprised of extensive infrastructure and systems, customers served, state and federal regulatory frameworks and industry practices—continues to perform safely, reliably, and cost-effectively for all customers.

But some argue that gas and electricity markets have not kept pace with the needs of power generators.

With increasing volumes of gas delivered for power generation, and the need for additional flexibility to balance variable renewable resources, some groups contend that we need new approaches to the rules and regulations governing how pipelines deliver natural gas supplies to these customers.

To be clear, dialogue about market rules and system operations are a healthy exercise in maintaining a safe and reliable gas delivery system. However, any dialogue about changes to existing rules and regulations must take the broader market needs, and obligations, into consideration.

In that vein, I want to use this post to share some facts about how natural gas is delivered to consumers to provide some needed context for this gas-electric harmonization dialogue.

Are Rules Not Keeping Pace with the Evolving Markets?

In a recent op-ed in the Wall Street Journal, Fred Krupp, the President of the Environmental Defense Fund attempts to establish his case that natural gas pipelines aren’t properly serving electric generators:

“New England regulators have assumed the region’s natural gas pipelines were being used efficiently. Not so. Valuable space was going unused on the busy Algonquin Pipeline, which supplies gas for electricity and heating, even during the coldest days when demand is highest. There was also a persistent gap between the amount of gas scheduled in advance, and the volume that flowed.”

Mr. Krupp references an unpublished study in which researchers examined the gas scheduling practices of two companies in the Northeast.

The study alleges that two companies routinely held capacity that other customers could not access. In other words, gas capacity was artificially constrained.

In response, the companies have called the report “a complete fabrication,” noting that scheduling practices are “to help protect customers from interruptions—including during unpredictable, extreme weather conditions.” The merits of the study’s allegations will be worked through official processes.

Digging deeper, there’s a larger context missing in Mr. Krupp’s op-ed, and EDF’s broader message.

In a letter to the editor of the Wall Street Journal, AGA’s President Dave McCurdy responds to Mr. Krupp’s comments:

Natural gas pipelines provide services to many customers, including electric generators and natural gas utilities represented by AGA. Gas utilities are obligated under state regulations to meet their customers’ needs—delivering gas directly to homes and businesses for heating, hot water and cooking. Gas utilities plan diligently to help ensure gas is always there when customers need it.

Mr. Krupp observes there is a “persistent gap between the amount of gas scheduled in advance, and the volume that flowed.” This reflects a misunderstanding of how the natural gas system works. Weather can’t be perfectly predicted. Pipelines and utilities must maintain safe operating margins, and gas utilities contract for firm interstate pipeline capacity to ensure reliability and flexibility, especially for the coldest days.

Mr. McCurdy also notes some statistical maneuvering in the way the problem is framed:

Mr. Krupp misleadingly presents this margin in terms of power generation demand, inflating its apparent significance. The economic paper he cites itself states that, over the 37 cold days analyzed for the statistic, the unutilized capacity was only 7% of the pipeline’s overall capacity. By necessity, pipeline systems are designed to meet demand that peaks on just a handful of days each winter. This means the margin on capacity constrained pipelines, such as those in New England, on those few peak days is likely much lower still.

It’s important to note that Mr. Krupp raises issues that are specific to the Northeast and not indicative of a systemic problem across the US.

The Northeast is unique primarily because the construction of new natural gas pipeline infrastructure has been limited. In other parts of the country, where pipeline infrastructure has kept pace with load growth, the natural gas market has not experienced the same persistent constraints.

Dovetailing on Mr. McCurdy’s letter, and by way of emphasis, I’d like to call out some additional key ideas going forward as we continue to discuss gas-electric harmonization:

1. Gas utilities are obligated under state regulations to reliably meet the natural gas supply needs of millions of Americans.

Natural gas utilities have a regulatory mandate or obligation to serve their core customers. These core customers are residential households and businesses, hospitals and nursing homes, schools, grocery stores, police and fire stations.

Importantly, gas utility systems are designed to meet peak demand requirements of their core customers on the coldest days of the year. Guided by past experiences and state regulatory oversight, gas utilities develop comprehensive plans to reliably deliver natural gas to their core customers.

Gas utility distribution systems are often the final step in a delivery chain of moving natural gas from areas of production to customers. After natural gas is produced, much of it is transported through long-haul interstate and intrastate pipelines before arriving at distribution pipeline systems for delivery to households and businesses.

To meet their obligations, gas utilities build and manage a portfolio of supply sources, storage and transportation services—which include a diverse set of physical and contractual assets—to help ensure they can reliably meet anticipated peak-day demand.

The last thing any gas utility wants is not to have enough gas to meet its customer needs. A loss of pressure during a peak winter month could be catastrophic. Supply management practices help ensure an event like this doesn’t happen.

2. To meet supply obligations, pipelines and gas utilities must maintain safe operating margins.

Weather can’t be predicted perfectly. Even a small change in temperatures could push customer gas demand higher than anticipated. In response, a gas utility will often call for more natural gas supplies, which may necessitate the use more interstate pipeline transportation capacity to move those supplies.

As such, flexibility is a key requirement in maintaining pipeline integrity and supply reliability. Many aspects of the current scheduling and nomination process support this critically-needed flexibility on pipeline systems.

Requirements for flexibility do not preclude pipelines from exploring innovative strategies. Indeed, pipelines continually offer new flexible service offerings, especially to meet the needs of new customers, like electric generators.

Importantly, gas utilities do not control the supply price of natural gas, and they do not earn a profit on the gas they deliver. Instead, utilities earn a profit on the delivery service they provide to customers, rates which are set by public utility regulators.

3. Market rules have evolved to meet changing needs.

In 2015, FERC concluded a major industry review of its regulations to better coordinate the scheduling of wholesale natural gas and electricity markets given increased reliance on natural gas for electric generation. FERC looked into providing additional scheduling flexibility to all shippers on interstate natural gas pipelines.

Following this activity, FERC adopted certain scheduling modifications, stating it expected that the changes would provide significant benefits to both the natural gas and electricity industries and would improve coordination between the industries.

More recently, throughout 2016, the North American Energy Standards Board held a forum on Gas-Electric Harmonization issues to further explore the potential for faster, computerized scheduling. In short, regulated gas utilities are already advancing strategies to build on efficiency and evolving market strategies.

4. The gas industry has evolved to meet changing needs too.

Under today’s market rules, unused capacity does not simply go unused. It is often released to other shippers who can then repurpose that capacity for their needs.

When gas utilities, or other shippers, do not need the firm pipeline capacity that they have under contract, FERC’s regulations allow for the capacity to be temporarily released for use by others in a secondary capacity release market.

FERC’s rules for capacity release programs are set up to avoid discrimination in the control of access to interstate pipeline capacity and to allocate the available capacity to pipeline system users who value it the most. FERC actively monitors the pipeline capacity release program to ensure compliance with its regulations.

Additionally, FERC’s regulations allow gas utilities and other firm shippers to enter into Asset Management Arrangements under which firm interstate pipeline capacity may be released to entities with expertise in managing supply and delivery arrangements—so-called asset managers.

While they can be structured in many of ways, here’s how a typical Asset Management Arrangement works: The unused firm interstate pipeline capacity is released to an asset manager, usually a marketer, who then uses the capacity to serve the releasing shipper’s gas supply requirements and, when it is not needed, it may be further released or used to make bundled gas commodity sales to other third parties.

FERC has found that these Asset Management Arrangements:

  • Result in an overall increase in the use of interstate pipeline capacity;
  • Facilitate the use of capacity by different types of customers;
  • Benefit the natural gas market by creating efficiencies through more load-responsive gas supply and an increased utilization of transportation capacity; and
  • Provide significant benefits to a variety of participants in the natural gas and electric marketplaces, and to the secondary natural gas market itself.

These are just a couple of examples of how the natural gas market and FERC policy have evolved to work efficiently and optimize unused interstate pipeline capacity, avoid unnecessary duplication of pipeline facilities, and allow gas utility and other pipeline customers the ability to contract to meet their reliability needs.

5. The natural gas market has provided economic signals that efficiently channel investment for new pipeline infrastructure.

The natural gas market, in many geographic areas, continues to function well with established practices that send market participants signals indicating a need for new pipeline capacity.

Prices and transportation cost differentials, detailed market analyses, open-season commitments from shippers, investor commitments, and regulatory oversight all send signals to market participants that additional pipeline construction may be needed.

The market’s well-functioning behavior is evidenced by the significant amount of new pipeline capacity being built.

Growing production and demand in Northeast markets has necessitated the construction of a significant amount of new pipeline capacity, although the process is often difficult and strewn with opposition. New pipeline takeaway capacity associated with the Appalachian basin is set to increase more than 70 percent between 2017 and 2018, according to March 2017 estimates by Bloomberg New Energy Finance.

From January to August 31, 2017, seventeen new US natural gas projects amounting to a capacity of 7 Bcf per day and 482 miles of pipeline have been placed into service. More are expected through the end of 2018.

Reliability of service for customers is an overarching priority for both the gas and electric industries. The foundation for providing reliable supplies in many instances is adequate infrastructure, where needed, as well as pipeline scheduling practices that preserve and enhance, but not decrease, reliability for all gas pipeline system customers.

Gas-electric harmonization is an onion with never-ending layers to peel. The above points are neither comprehensive nor definitive. However, I hope they add some needed facts and context to an important dialogue underway.

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Richard Meyer Natural Gas Market Indicators: November 15, 2017

Cold has arrived, and with it, surging demand. U.S. natural gas consumption hit 98 Bcf per day on November 10, an increase of 33 percent from five days prior. Heating requirements for homes and businesses provided the main thrust as residential/commercial consumption jumped 93 percent during those five days. Power generation climbed eight percent over that period; exports, while strong, ticked up a mere 2.7 percent.

How much energy is 98 Bcf? The rate at which 98 Bcf per day flows chemical energy into the economy is equivalent to 1,230 GW. By comparison, the U.S. power grid boasts a little more than 1,000 GW of net summer capacity. In other words, natural gas, as it does every winter, supplies a lot of our energy needs.

Visit this link to download the full Natural Gas Market Indicators report. Topics covered in this week’s report include: Reported Prices, Weather, Working Gas in Underground Storage, Natural Gas Production, Shale Gas, Rig Counts, Pipeline Imports and Exports, and LNG Markets.

Please direct questions and comments to Chris McGill at cmcgill@aga.org or Richard Meyer at rmeyer@aga.org.

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Richard Meyer Natural Gas Market Indicators: October 30, 2017

Supplies are increasing. Record levels of production are flowing into the market have more than offset slight declines in Canadian imports. Storage inventories are robust even though totals are slightly below the all-time highs set in 2016. December prices currently trade at $3.00 per MMBtu. Now we wait for the first cold snap to see how the market reacts. Winter is coming.

Visit this link to download the full Natural Gas Market Indicators report. Topics covered in this week’s report include: Reported Prices, Weather, Working Gas in Underground Storage, Natural Gas Production, Shale Gas, Rig Counts, Pipeline Imports and Exports, and LNG Markets.

Please direct questions and comments to Chris McGill at cmcgill@aga.org or Richard Meyer at rmeyer@aga.org.

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Richard Meyer The Tech Sector’s Natural Gas Play

Two household names in the technology world are integrating natural gas technology and infrastructure into their clean energy plans.

First up is the Microsoft Corporation, which announced that it is constructing a first-of-its-kind natural gas datacenter. In partnership with McKinstry and Cummins, the tech giant will install a 20-rack datacenter in Seattle, WA that utilizes natural gas fuel cells. The company says this approach could transform how it powers its servers.

On the company’s blog, Christian Belady, General Manager, and Sean James, Principal, Microsoft Cloud Infrastructure and Operations, describe the benefits:

“This stark and simple design significantly reduces the amount of energy lost in power generation, transmission and power conversion. Right now, datacenters are powered by the electrical grid, which flows from a power plant, through multiple substations and transmission lines, and then must be converted into the right voltage for a datacenter before we can use it. With fuel cells powered directly from the natural gas line, we cut out all those steps, and remove the energy losses that occur through this long transmission process as seen below.”

The benefits also extend to energy reliability and resiliency. Belady and James continue:

“With fewer pieces in the supply chain, there are fewer potential points of failure. That helps improve the reliability of our power supply and our datacenters. And, of course, with this simplification comes a reduction in cost. Eliminating electrical distribution, power conditioning, and backup infrastructure makes a datacenter easier and less expensive to build, operate and manage.”

Make sure to keep an eye on this pilot project.

Next up is Apple, which is putting the finishing touches on its new corporate headquarters in Cupertino, CA.

Apple has announced that its new campus, the 175-acre Apple Park, is to be run on 100 percent renewable energy.

How exactly does the company accomplish this? The new campus will feature on-site rooftop solar and a mix of offsite purchases and credits. However, a closer examination of its plans shows that natural gas infrastructure is how Apple gets to 100 percent.

The company will utilize four megawatts of baseload biogas fuel cells to power its facilities. The efficient on-site generators will provide reliable power to its office, datacenters and energy-intensive research and development facilities while remaining carbon neutral.

The fuel cells also work as a natural pairing with the on-site 17-megawatt rooftop solar installation, which together will provide 75 percent of the facilities’ total electricity needs.

Apple’s Environmental Impact Report documents describe how the fuel cells will be powered:

“Directed biogas will be delivered by an off-site renewable biogas producer by means of the existing natural gas pipeline. As with electricity, there is no means of ensuring the actual molecules of biogas are consumed at the customer’s site. Thus, the gas may not be physically delivered to the site, as the biogas may actually be utilized at another location along the pipeline route (requiring the use of natural gas on the project site).”

In other words, Apple will utilize the existing natural gas utility distribution system to power its on-site fuel cells but will purchase biogas credits to reach its renewables goal.

Both projects offer unique insights into different ways that large companies are trying to meet their environmental goals while maintaining energy reliability. In both cases, on-site natural gas provides an energy backbone onto which renewables are integrated. I, for one, will be watching how both projects progress with interest.

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