As I write this month’s column, the dog days of summer have come to Washington, D.C. While longing for a cool autumn night and a football game under the lights, I relay the “hot” news impacting the oil and gas pipeline industry.
Marrying Natural Gas, Electricity Utilities
This summer, Southern Co. has taken two major steps to becoming a highly integrated natural gas and electricity company. The company’s major electric subsidiaries include Alabama Power (1.4 million customers) and Georgia Power (2.4 million customers). In 2014, Southern’s power-plant portfolio was 40 percent coal-fired, 40 percent natural gas, 16 percent nuclear and 4 percent hydroelectric. By 2020, the company is planning to have up to 55 percent of its electricity generated from natural gas, while reducing coal-fired generation to 21 percent. Southern is not unique. Due to more stringent environmental regulations, coal-fired generation is expected to decline with a corresponding increase in natural gas-fired generation.
Southern doubled down on its commitment to natural gas with the recent $8 billion acquisition of AGL Resources and its 4.5 million natural gas customers. The acquisition made Southern the second-largest utility company in the United States in terms of customer base, including 11 regulated electric and natural gas distribution companies providing service to approximately 9 million customers, using nearly 200,000 miles of electric transmission and distribution lines and more than 80,000 miles of natural gas pipelines.
On the heels of the AGL Resources acquisition, Southern also announced a joint venture with Kinder Morgan Inc., including the acquisition of a 50 percent interest in an interstate natural gas pipeline, Southern Natural Gas Co. (SNG), for $1.47 billion and an agreement to cooperatively pursue growth opportunities to develop natural gas infrastructure. The acquisition is expected to close later this year.
SNG is a 7,600-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee. SNG aligns well with Southern’s electric and natural gas operating companies.
It’s clear that Southern Co. is expanding its operations both horizontally and vertically. Already a consumer of natural gas to fuel its electric generation facilities, making it a transportation customer of SNG, Southern significantly increased its gas load by acquiring AGL Resources and then acquired the interstate natural gas pipeline that transports natural gas within the Southern’s footprint. Not only does the marriage of natural gas and electric operations in the same region increase economies of scale, but the vertical integration of the operations could produce efficiencies to benefit both owners and ratepayers. That makes sense and might be a recipe copied by other regional utilities. But as discussed below, it comes with a caution.
Reduced Storage, Electric Reliability in California
Last fall, a major natural gas leak occurred at the Aliso Canyon natural gas storage facility. The leak has been stopped, but a moratorium prohibits the operator of the facility from injecting natural gas into the underground reservoir until completion of a comprehensive safety review. The review requires that all 114 wells in the facility be safety tested or removed from operation and isolated from the underground reservoir. As a result, Aliso Canyon is operating at historically low levels to provide gas to meet the energy demands in the Los Angeles basin and San Diego area. The reservoir is depleted, down to less than one-fifth of capacity.
Aliso Canyon storage services are a critical component of the natural gas transmission and distribution system in the Los Angeles area, helping supply millions of people with natural gas for home heating, hot water and cooking fuel. But what you might not expect is that Aliso Canyon also helps provide supplies to natural gas-fired electric generation plants. Southern California relies on these gas-fired plants to serve both high summer electric load and load changes, that is, gas-fired generation facilities are called upon to meet “peak” load requirements and to “firm up” renewable generation resources (when the wind doesn’t blow or the sun doesn’t shine). Operational limits at Aliso Canyon will, therefore, stress the state’s natural gas system, resulting in curtailed gas deliveries to electric generators, which in turn will stress the electric grid. In regulatory parlance, constrained gas supplies from Aliso Canyon raises regional concerns with electric reliability (e.g., interruptions in electric service).
In order to address these reliability concerns, the California Independent System Operator (CAISO), which operates the electric transmission facilities owned by the state’s utilities (e.g., Southern California Edison) and administers electric markets, filed with FERC a set of tariff revisions that will “sunset” on Nov. 30, unless CAISO subsequently files to retain or revise them. As a general matter, California generators submit to CAISO bids to generate certain amounts of electricity. CAISO selects the generators needed to satisfy load requirements based on “locational pricing,” which prices electricity based on the cost of generating and delivering it. Scarce gas supplies will increase gas supply costs for generators. Against this backdrop, CAISO’s temporary market rules would 1) promote generator bids that reflect gas system limitations, 2) permit CAISO to react easily and readily to changes in the gas system, and 3) improve the ability of generators to recover fuel costs during a period of anticipated price volatility.
FERC approved CAISO’s proposal and also established a technical conference on Sept. 30 to discuss the effectiveness of CAISO’s tariff revisions and the need for additional and/or longer-term measures.
FERC Chairman Norman Bay stated that this situation “highlights the connection between the gas and electric industries and how their operations affect consumers. It also points out the need for infrastructure as gas becomes the marginal fuel for power generation in many markets. We need to ensure the gas is there in order to maintain reliability.”
The Southern Co.’s acquisition of AGL Resources and SNG could be a harbinger of more electric and natural gas utility consolidations. Forgetting competitive concerns, increased economies of scale and efficiencies may compel other energy companies to follow the Southern’s lead. The electric and natural gas markets are becoming more interdependent each year and with it the need for more coordination. That need may become even more pronounced, with more electric and natural gas utility mergers.
Historically, the electric industry and regulators relied on a diverse fuel supply portfolio to ensure electric reliability. That will change under the Obama administration’s Clean Power Plan, which would result in reduced coal-based electric generation and increased renewable generation. But increased reliance on renewable resources, such as wind and solar, also requires increased reliance on quick-start natural gas generation facilities.
These quick-start generation units must necessarily ramp up and down on short notice (as wind velocities or solar intensities change), often during peak periods, which impacts both natural gas and electric markets. For example, when a generator, in order to maintain electric reliability, unexpectedly “pulls” gas off a pipeline without a corresponding injection (possibly due to lack of gas supplies), there can be a direct impact on the deliverability, pressure and reliability of the pipeline system, which in turn would harm other natural gas users and result in the pipeline’s imposing significant penalties on the generator (for short notice deviations from scheduled or contract quantities and related imbalances). And to compound the generator’s problems, a system operator, like CAISO, does not normally compensate a generator for these penalties. This is just one of many issues that must be addressed to better coordinate the gas and electric industries.
In the new electric marketplace, what will happen when the wind doesn’t blow, the sun doesn’t shine, and natural gas supplies become constrained? Some might argue that if Aliso Canyon teaches us anything, it should be that policymakers’ best intentions to curb greenhouse gas emissions must be moderated, and regulators should increase their on-going efforts craft more and improved coordination between electric and natural
Congressional Reaction: PIPES Act
In partial response to Aliso Canyon, a new piece of legislation was enacted on June 22. The Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (PIPES Act) reauthorizes the federal pipeline safety program within the Pipeline and Hazardous Materials Safety Administration (PHMSA) until 2019 and requires the agency to update safety regulations, increase transparency and embrace emerging technologies.
The PIPES Act is intended to speed up the process of completing outstanding safety requirements. More than a quarter of the 42 rulemakings required by the 2011 reauthorization remain outstanding, including regulation of pipeline leak detection systems and the use of shut-off valves and excess flow valves in certain applications.
The new law will require PHMSA to provide Congress with updates every 90 days. In addition, the law creates an Aliso Canyon task force to report to Congress on the gas leak, its causes and how to prevent or mitigate future leaks and mandates a number of other studies and reports within the next 12 to 24 months.
The act also expands federal oversight by vesting the Secretary of Transportation with additional authority. First, the act further authorizes the Secretary to analyze the potential for leaks to occur at underground natural gas storage facilities, similar to the Aliso Canyon gas leak and issue minimum safety standards. In the meantime, PHMSA is expected to issue an interim final rule requiring operators of underground gas storage facilities to comply with minimum safety standards. Second, the Secretary now has the right to issue emergency order imposing restrictions and emergency measures on pipeline operators without prior notice or a hearing process. But pipeline owners and operators can petition PHMSA for a review of an emergency order, which will trigger a 30-day period for PHMSA to release written findings that support the order.
The PIPES Act will impose on the industry significant costs due to increased inspection, monitoring and repair requirements from the enhanced regulatory oversight and the anticipated underground gas storage rules. The extent of those increased costs will become clearer as the underlying regulations are developed.
PHMSA Revisions to National Pipeline Mapping System
Also on June 22, PHMSA issued a notice of changes to the data that operators of pipeline facilities (except distribution and gathering lines) must submit to National Pipeline Mapping System (NPMS). Specifically, PHMSA will modify or drop the following attributes, standards or components: Positional accuracy; highest percent operating specified maximum yield strength; decade of installation, year of last corrosion, dent, crack and other inline inspections; coated/uncoated and cathodic protection; type of coating; year of original pressure test and pressure; year of last pressure test and pressure; and gas storage fields. Complete details on the changes are available in a revised NPMS Operator Standards Manual, at npms.phmsa.dot.gov.
Finally, to bring this column back to my summer desire for a fall football game, essayist Pico Iyer once said, “A single Dallas Cowboys football game uses up as much electricity as the entire nation of Liberia in those same three hours — one reason the globe, if looked at from a certain height, is a cluster of lights surrounded by enormous patches of dark.” It’s unclear whether Iyer noted a patch of darkness around the Capitol when Washington’s team plays.
Washington Watch is a bimonthly report on the oil and gas pipeline regulatory landscape. Steve Weiler is a partner at Stinson Leonard Street LLP in Washington, D.C. Contact him at email@example.com.