- Survivor: The Natural Gas Dilemma Edition
- Distributed Generation: Making a Deal Between Opportunities and Challenges | VIEW
Survivor: The Natural Gas Dilemma Edition
Proven shale gas reserves and fracking technology have dramatically changed the production capability for natural gas and the anticipated utilization of natural gas. Energy Tomorrow touts the U.S. as a world power in natural gas, supported by the largest energy infrastructure in the world, and utilization of natural gas in the U.S. has increased markedly over the past few years. The high levels of production, combined with the recent relatively low price levels, have made this commodity very attractive to various consuming sectors. Most notably, the power generation and industrial sectors are consuming more natural gas than ever before and are expected to continue increasing their consumption of this commodity.
The EPA’s proposed Clean Power Plan adds to the popularity for the power generation sector and some estimate that there will be $100 billion worth of natural gas reliant industrial projects built along a swath that reaches from Texas eastward to Baton Rouge, Louisiana. At the same time, the U.S. is transitioning from being a modest importer of natural gas to becoming a significant exporter in the form of LNG. Although natural gas will not be the only fuel source for meeting all of the growth in the power generation sector, the growth in renewable power resources implicitly relies on natural gas resources to provide reliability support due to the intermittent nature and limited availability of existing renewable energy technologies. But as these upward trends are merging with other trends there is the potential to create discontinuities in the natural gas market.
Growth in natural gas production varies significantly across the U.S. supply regions, which will create changes in the historical natural gas flows between the regions. This shift in deliverability is requiring investment and realignment of midstream and long haul pipeline infrastructure. The strongest growth of natural gas production occurred in the East fueled by the Marcellus Shale, followed by the Gulf Coast onshore region and then the Dakotas/Rocky Mountains region. Interregional flows serving downstream markets are beginning to vary significantly and thus, will require new asset investments in pipelines.
Richard Kinder, chairman and CEO of the natural gas infrastructure giant Kinder Morgan, during a keynote address at the recent IHS CERAWeek in Houston, said the growth of production in the Marcellus Shale in the last several years has had a profound effect on the flow of the commodity, which historically has flowed from the producing regions of Louisiana and Texas to markets in the Northeast. Kinder Morgan owns four major interstate gas pipelines that stretch from the Gulf Coast region of Texas and Louisiana to market areas in the Northeast. Kinder noted that his company has turned three of the pipelines around to move gas down to the Gulf Coast and the fourth one is now seeking approval to be converted into a liquids pipeline. Kinder said much of the gas from the Marcellus Shale is selling at a discount to other regions because of the shortage of pipeline infrastructure to bring it to market. FERC Commissioner Moeller, at a recent speaking engagement, stated the following regarding pipeline capacity: “When it’s really, really needed and everybody
wants it…that’s when we have to be concerned about it”.
To appreciate the impact of shale gas and fracking technology, the state of Pennsylvania (because of the Marcellus Shale) ranks 8th in the world in terms of production, even more than Saudi Arabia. The Marcellus Shale region overall produces about 20% of total U.S. natural gas production. Given the ramp up in the Marcellus Shale, Pennsylvania is poised to take the #2 spot in terms of total U.S. production behind Texas. Production from the Marcellus Shale region is now displacing inflows from the Gulf coast, the Midwest, and Canada. Bottom line is that this makes the state of Pennsylvania a swing state in terms of natural gas supply and prices. What happens in the Marcellus region now measurably impacts all of the U.S. natural gas market including Henry Hub prices. “The Marcellus has been a game changer in terms of production, reserve potential, everything,” said Fadel Gheit, a senior energy analyst for Oppenheimer & Co. in New York.
However, with the current low natural gas prices, the drilling rig count in the Marcellus Shale region has been decreasing since 2012. For example, rig counts peaked at around 140 in 2012 and has recently slipped to the mid-70s according to Baker Hughes’ tracking report. One of the largest Marcellus gas producers reported a recent quarterly loss of over $220 million and a 60% decline in profits for the year as well as announcing they were implementing a reduction in drilling. According to the Texas Railroad Commission, natural gas deliverability from all three shale fields in Texas is leveling out. Because the majority of natural gas is produced in association with natural gas liquids and crude oil, the recent fall in crude oil prices is causing a double whammy for natural gas’ deliverability outlook and adding to the discontinuity in the market. Forward natural gas prices aren’t helping producers because they are less than half of what they were just several years ago. Of course, lower natural gas prices benefit the consuming sectors.
RTO Firm Fuel Requirements?
Not only is the natural gas supply industry talking about deliverability of the commodity, but so is the power consuming side of the commodity, including FERC and the RTOs/ISOs. In its November 20, 2014 Order, the FERC directed each RTO/ISO to file a report on the status of its efforts to address market and system performance associated with fuel assurance issues.
According to MISO’s report to the FERC, fuel availability issues can affect all generating units in the MISO footprint, potentially impacting their ability to perform and deliver energy. Although MISO states that fuel assurance is an important consideration in resource adequacy and energy market operations, and a critical factor in MISO’s ability to reliably meet customer’s electricity needs under a wide range of operating conditions, MISO believes load serving entities, with oversight by the States as applicable by jurisdiction, are primarily responsible for ensuring resource adequacy. A fuel survey conducted by MISO shows that of the 53,000 MW of generators that responded, only about 15% of them had firm natural gas pipeline deliverability arrangements.
According to MISO’s report to the FERC, fuel availability issues can affect all generating units in the MISO footprint, potentially impacting their ability to perform and deliver energy.
According to PJM’s report, the most significant initiative to improve fuel assurance in the PJM region is PJM’s capacity performance plan which has just recently been approved by the FERC. Under this arrangement, owners and operators of generation capacity resources would have strong economic incentives to invest in fuel assurance, including firm fuel transportation arrangements. PJM will make capacity market offer caps more flexible so as to allow fuel assurance costs to be included in sell offers. The would pair the additional flexibility to include costs associated with such investments with more severe economic consequences for resource non-performance, including lack of firm fuel arrangements. PJM believes the combination of increased offer flexibility and significant consequences for non-performance will encourage sellers to invest in firm fuel arrangements.
Outside of electric utilities, other gas consuming sectors are beyond being encouraged; they’ve made firm commercial commitments as was confirmed by Kinder during his keynote talk when he said investors, such as petrochemical industrial customers in Texas and Louisiana, have moved to lock in deliverability rights. These deliverability arrangements are year round, firm base load deliveries and gas producers are now looking to do the same. In the past, the natural gas distribution sector would sell its year round contracted capacity during non-winter months, mainly to the power generation sector, but new pipeline capacity will not be released. Like the turnaround in the direction of pipeline flows, this non-released capacity will also be a turnaround from the norm and adds to the deliverability discontinuity dilemma.
In light of all of these conflicting trends, natural gas consumers need to do their due diligence on the expected reliability of their natural gas deliverability and address any potential unfavorable discontinuities. This starts with supply contracting and ends with delivery point transport. Work to be done includes:
- Evaluating firmness of supply arrangements, the liquidity of supply points, and assessing potential price basis exposure;
- Evaluating the subscription level of the delivering pipeline in addition to evaluating the pipeline’s balancing arrangement and associated imbalance costs;
- Assessing gas requirements on an hourly/daily/monthly basis,managing daily gas swings, and optimizing gas arrangements and capabilities; and,
- If necessary, developing appropriate meter point allocations for the end gas users.
Natural gas consumers should proactively plan and be prepared to conduct commercial transactions for supply and transportation and potentially, develop unique, custom solutions. GDS recently assisted a client with implementing a custom solution, which was to arrange pipeline deliverability through a single meter for multiple power generating units (at the same plant site) that were dispatched separately by different owners who have separate supply and transport arrangements. Reliable natural gas arrangements extends beyond just the physical natural gas commodity and includes energy management sourcing and contracting, price hedging, and risk management.
For more information or to comment on this article, contact:
Paul Wielgus, Managing Director | CONTACT
GDS Associates, Inc. – Marietta, GA
Distributed Generation: Making a Deal Between Opportunities and Challenges
Distributed generation (“DG”) is going to be a major influence in the future of the electric industry in the United States. The blend of existing opportunities and challenges has created an environment for electric utilities to consider integrating DG technologies into their business models. The Utility Dive’s 2015 State of the Electricity Utility survey of 433 U.S. electric utility executives indicates that DG will be the biggest driver of disruptive growth in the industry over the next five years. Utilities recognize the vast opportunity distributed energy resources can provide as well as the unique challenges they present. Some companies have been exploring DG technologies and General Electric has created a new DG business by combining parts of its transportation, aviation and engines divisions to meet what GE calls, “a $100 billion opportunity”.
For decades, utilities and retail customers have used DG to generate electricity at the point of consumption using technologies like reciprocating diesel engines, natural gas turbines, fuel cells, solar panels and small wind turbines (see Figure 3).
Historically, natural gas and diesel technologies were used for commercial emergency and standby generation, or as a means of overcoming geographical limitations. utilities have installed these types of generators at substations for peak shaving as well as voltage support and reliability purposes. Interest in DG has been on the rise since the enactment of the Public Utility Regulatory Policies Act (PURPA) of 1978. PURPA was created in response to the 1970s’ energy crisis which encouraged greater utilization generation from non-utility power producers and increased research in hydroelectric, wind, and solar generation technologies. This research led to a drastic reduction in manufacturing costs of solar panels, a nearly 70% cost reduction from 1980-1995, as well as leading to significant reductions in the production cost of wind turbines. With the passage of the Energy Policy Act of 1992, the wholesale electric markets were opened up to competition which further boosted interest in DG technologies.
Increased DG Utilization
The continuous improvements in DG technology means that today, these generators are less expensive, more efficient, and more widely available than ever before. DG typically requires less capital investment (on an installed $/kW basis) than centralized generation and provides utilities with greater flexibility in siting generation resources. DG benefits include: reduction in transmission investment, managing constraints on transmission and distribution systems, mitigating potential power outages, and hedging against extreme variations in energy prices. However, four of the main challenges and opportunities around DG are accessible solar generation, energy storage, new regulatory/business models, and customer engagement.
Accessible Solar Generation
Although solar power still comprises less than 0.5% of the total electric energy requirements in the U.S., there has been exponential growth in solar installations over the past four years. In 2013, total solar installations reached 4.7 GW. According to the Solar Energy Industry Association (SEIA), that level of growth made solar power the second-largest source of new electric capacity in the United States. The number of installations grew 30% in 2014 and this trend of rapid solar installations is expected to continue over the next 25 years as illustrated in Figure 4.
While residential installations have grown nearly 50% annually since 2012, the vast majority of the installations, propelling the solar industry over the past four years, have been utility scale projects. Residential solar demand has increased due to the reduction in production costs and creative financing options from solar developers, such as purchase power agreements (PPA), lease options, and solar power loans. Perhaps the most interesting trend on the commercial side, and one to watch in the coming years, is solar developers and retailers beginning to offer energy storage as an additional tool to reduce demand charges and maximize the accessibility of solar benefits.
Electric utilities are interested in energy storage on a large scale. Recently, Southern California Edison executed an agreement with Oncor Electric to provide 261 MW of energy storage. This agreement was followed by the announcement by a Texas utility seeking authorization to add 5 GWs of storage to integrate renewable technologies into the transmission grid. Battery technology is improving and the prices are expected to continue to fall significantly as manufacturing capabilities expand the potential of energy storage. Utilities agree in their response to the 2015 Utility Dive survey that energy storage is the number one technology that can potentially transform the utility business over the next 10 years.
New Regulatory and Business Models
Multiple investment banks such as Morgan Stanley are predicting that high penetration rates of solar powered DG combined with improvements in energy storage could be disruptive for electric utilities. For DG customers in 43 states, the potential exists for customers to completely eliminate their power bills. This possibility now exists, in large part, because of customer eligibility for Federal Government’s Investment Tax Credit (ITC) as well as expanded net metering regulations. While the ITC is set to expire at the end of 2016 (under current legislation), net metering continues to represent a challenge and an opportunity for electric utilities.
Net metering is the mechanism that allows retail customers with DG to buy and sell power through the use of bi-directional metering. These customers use their DG output to offset the power purchased from their electric utilities. With the two way street of power flowing to and from customers, there are new economic and physical challenges that must be addressed through regulation and utility business models. As mentioned earlier, electric utilities in 43 states must provide net metering. Each state has its own set of rules and operating requirements, but there is one common issue: should the consumption and production of electricity be bought and sold separately or should customers be charged based on their net consumption from the utility? States are determining how to revise net metering regulations to ensure that the impact of cost shifts between electric utilities and customers is minimized. From the electric utility’s perspective, one of the most important considerations in the net metering debate is to ensure recovery of (sunk) fixed costs – from existing generation resources as well as transmission and distribution assets. One example of this concern is occurring within the state of Hawaii. More than 10% of Hawaii Electric’s retail customers have installed solar which has resulted in the significant loss of retail energy sales and some operational and financial challenges for the utilities. This potential for retail customers to move away from centralized power consumption has prompted many electric utilities to push for new regulation and the creation of new business models. Hopefully, the answer to these problems can be solved with cost-based retail rate design and updated regulations that balance the interests of consumers with and without DG. New regulations, for example, could allow utilities to utilize decoupled ratemaking where energy sales, energy savings, and demand costs are recovered more appropriately in rates.
Regardless of the business strategy, electric utilities will have to understand and anticipate the customer’s needs. The days of the customers only engaging the utility because of outages and billing questions are coming to an end. Utilities have a great opportunity to use DG as a tool to create new customer experiences with higher frequency communications. The significance of this opportunity is illustrated in the fact that 76% of respondents to the Utility Dive survey indicate that utilities have increased their investment in customer engagement. By increasing the level of customer engagements, electric utilities can create opportunities to provide new services. With respect to DG, utilities can leverage their expertise as a smart integrator of DG technologies to assist the customer with product evaluations and selection. Electric utilities can also expand energy efficiency and renewable energy resources and infrastructure to help expand DG options for retail customers. That may require certain investments in the distribution system as well as revising net metering policies and utilities should establish policies that improve their ability to invest and recover those related costs.
Distributed generation will have a major impact on the future of the electric industry in the United States. Three key actions utilities need to take in order to make the most out of the DG opportunity are:
- Gain regulatory support to recover DG investment costs in retail rates. Work with regulators to ensure that net metering does not result in cross-subsidy and that customers pay their share of the transmission and distribution network costs.
- Develop strategies to assess the technical and economic potential of DG resources whether they are owned by the utility, the customers or a third party in their service territory. To do so, utilities must understand customer load profiles and identify locations where a particular strategy provides the greatest benefits to the utility system.
- Utilities should evaluate the business opportunities of being involved in the development, financing, implementation, construction, operation and maintenance of DG solutions. There may be DG applications on a “community” basis as well as for individual retail customers.
For more information or to comment on this article, contact:
Emmanuel Miller, Engineer | CONTACT
GDS Associates, Inc. – Marietta, GA