With an already troubled gas sector roiled by fallout from the coronavirus pandemic, DTE Energy is facing concerns from shareholders over the company’s growing exposure to natural gas. 

DTE Midstream, a non-utility business segment of the company that owns gas pipelines and storage assets, recently completed its acquisition of a gas gathering system and pipeline in the Haynesville shale formation in the Texas-Louisiana region. DTE Energy paid $2.25 billion for the system and agreed to pay an additional $400 million upon completion of a gathering pipeline this year.

The Haynesville shale purchase is the largest acquisition of gas infrastructure the utility has made in recent years. In 2016, DTE acquired 100% of the Appalachia Gathering System (AGS) and 55% of the Stonewall Gas Gathering (SGG), located in Pennsylvania and West Virginia respectively, for $1.3 billion. The company purchased an additional 30% stake in SGG for $275 million last year. The company also invested at least $1 billion in the NEXUS pipeline, a 50-50 joint venture with Enbridge that went into service in the fall of 2018.

Map showing DTE Midstream’s new assets Blue Union Gathering and LEAP Pipeline (under construction) in the Haynesville shale formation. 

DTE Energy President and CEO Jerry Norcia held a “fireside chat” with Wolfe Research on March 25. Accompanying slides showed the company trying to alleviate concerns from investors about the company’s growing gas exposure. 

Several of the slides, which were not part of the company’s February business update after the release of the 2019 earnings, appear to be an attempt by executives to reassure Wall Street analysts that the company’s exposure to low gas prices and the risk of transporting gas from a single primary supplier in Louisiana, Indigo Natural Resources, are not causes for concern.

DTE Energy is telling analysts and investors that while short-term demand for gas is less certain, there will still be demand for gas in the long run, particularly from the formations where DTE midstream assets are located – the Haynesville, Utica, and Marcellus shale plays.

But on April 15, Fitch Ratings downgraded DTE Energy’s long-term issuer default rating. The rating agency cited the company’s business risk associated with the Haynesville acquisition. 

Fitch had previously placed DTE on Rating Watch Negative immediately following the purchase and said, “DTE’s placement on Rating Watch Negative reflects increased leverage and business risk associated with the midstream acquisition … Fitch believes this acquisition has a higher business risk than DTE’s existing midstream assets.”

Questions raised during earnings calls

On recent earnings calls, several analysts have tried to find out if the utility had stretched itself too thin with the recent acquisition – especially since the company is targeting this business segment to earn $400-$420 million by 2024. That earnings target is a significant increase from DTE’s 2020 forecast of $277-$293. It is no wonder analysts are trying to glean as much information as possible in their efforts to assess the viability of that target, particularly in a market flooded with gas and a possible COVID-19 related recession that would likely reduce demand for gas.

In October, Wolfe Research’s Steve Fleishman asked if the many industrial users and LNG export plants that exist along the gulf coast were driving DTE’s thinking behind the Haynesville transaction.

Peter Oleksiak, CFO for DTE Energy, said that the company expects “significant” long-term growth on the demand side from industrial and power generation customers in the region, and the system interconnects with numerous LNG facilities along the coast. 

In February, Gregory Harmon of Gordon Evercore ISI Institutional Equities asked whether DTE Energy had a contingency plan if the company is wrong on its gas assumptions: “Are there other areas in the business where you could pivot? I mean is the renewable natural gas business sort of potentially larger than what you’re currently budgeting? I mean where are the opportunities in the plan?”

Later on the February call, Goldman Sachs’ David Neil Fishman asked, So if Indigo or another producer was unhedged, and you were to have a situation where maybe the Haynesville was flat or even slightly down, would it put a substantial amount of financial distress?”

Norcia responded by telling analysts that he feels “very good” about the contracts with customers, and Indigo’s long term drilling plans had “very economic resources at the $2 price range for over a decade and with 15% unlevered returns.” 

Norcia also reiterated that demand for gas will continue, especially as Midwest utilities build new gas power plants. Norcia believes this will continue to happen because “natural gas is readily available and really economically priced … we’re still seeing continued conversion [coal to gas] opportunities in and around all our assets,” according to his February remarks.

During DTE’s April 28 Q1 earnings call, analysts again asked about the midstream assets. Norcia repeated his confidence that LNG exports will largely drive the demand over the coming years and later said that the company is seeing more local distribution companies and power plants sign contracts along the NEXUS route.

It is true that gas-fired power plants are still being built, especially as utilities retire coal units. PJM Interconnection, the nation’s largest grid operator that coordinates the movement of electricity within 13 states in parts of the Midwest and Mid-Atlantic, has nearly 30 GW of gas capacity planned by 2027, according to S&P Global Market Intelligence. Rocky Mountain Institute (RMI) also recently identified 88 proposed gas projects with a cumulative capacity of 68 GW that have been announced to begin operation by 2025 but have not yet begun construction, across the country. The map below, produced with data from RMI, shows that many of these planned plants are in the region where DTE’s Utica and Marcellus assets reside and could transport fracked gas from wellheads to power plants.

But analysts are right to express concern, because the LNG market appears to be shifting, demand for electricity might decrease particularly during an economic downturn, and the deployment of renewables will get cheaper.

RMI recently concluded that 90% of the 68 GW of proposed gas-fired power plants will be more expensive than a combination of clean energy sources by 2035, resulting in a stranded asset risk for investors: “Just as the falling price of shale gas has allowed gas power plants to undercut coal plant operating costs, expected price declines in renewables and storage may soon strand existing or proposed gas plants.”

A separate RMI report analyzed the risks associated with pipelines that rely on revenue from gas-fired generators to justify project economics. It found that clean energy sources will eliminate expected demand growth for gas from the power sector, causing a declining throughput for newly built gas pipelines, which in turn will force pipeline companies to recover costs over fewer units of delivered fuel, creating more economic strain on gas generators which further advantages clean energy portfolios in a cycle:

“Estimated declines of 20 to 60 percent of pipeline throughput across New England, Mid-Atlantic, Midwest, Southeast, and New York regions correspond to an increase of 30 to 140 percent in per-unit delivered cost of fuel. This dynamic risks setting up a reinforcing feedback loop, sometimes referred to as a ‘death spiral,’ for gas pipelines whose unit costs rise as throughput declines – if these rising unit costs are passed on to gas generators as increased rates for transporting gas through a pipeline, this in turns leads to additional loss of throughput and further unit cost increases.” 

RMI recommends that investors in companies like DTE Energy reassess the fundamentals of the industry and the economics of new gas projects in light of cheaper clean energy resources. 

As for the demand for gas-fired power plants, the Michigan Public Service Commission recently forced DTE Electricity to revise its long-term energy plan, which initially had four potential pathways – two of which included the construction of new gas-fired power plants. DTE’s revised plan includes more energy efficiency, demand response, and solar power. The next filing is in 2023, but the company could again try to make an argument for more gas, especially since the company will analyze earlier retirement dates for the 1,000 MW Belle River coal plant. 

Additionally, two independent power producers building units in Virginia recently expressed doubt about finishing the construction of new power plants on time or even at all due to financial markets. Argan, Inc., a holding company that constructs power plants, including the Chickahominy Power Station in Charles City County, Virginia, disclosed in an April 14 10-K that, “due to several factors that are slowing the pace of the development of this project, including additional time being required to secure the natural gas supply for the plant and to obtain the necessary equity financing, we currently cannot predict when construction will commence, if at all” (emphasis added). 

And finally, regarding the LNG market, S&P Global reported last month the low oil and gas prices “could affect negotiations of long-term contracts that are expiring over the next two to three years and the signing of new LNG supply.” The outlet further reported on how Goldman Sachs expects “oversupply in the European gas market to require shut-in of US LNG exports, and ultimately a shut-in of Appalachia gas production, a trend that was already visible from a collapse in Chinese demand.” 

Reed Blakemore, deputy director at the Atlantic Council’s Global Energy Center, recently said, “the impact of low oil prices on US shale producers might, at least temporarily, knock US LNG out of the game.”

Possible impact on customers

Intervenors will have to continue to monitor closely DTE Electric and Gas rate case filings over the coming years if the holding company’s midstream asset experiences financial trouble. 

DTE’s business model is increasingly focused on expanding its midstream assets to generate earnings. During the Q1 earnings call today, Norcia said that the company will “pursue highly creative and high return expansions and organic developments in and around those platforms.”

Executives set guidance of $277-$293 million in earnings from the midstream segment this year, which would consist of 23% of the company’s total earnings guidance at the high end. In 2024, earnings from this segment are forecasted to continue to remain at this percentage for total earnings.

These profits are what drives the company’s annual dividends, which utilities strive to keep high in order to satisfy shareholders. The company boasts to investors that it has increased annual dividends per share every year since 2020, and increased dividends by 7.1% since 2016. DTE’s $4.05 annualized dividend in 2019 was the second-highest among investor-owned utilities, according to the Edison Electric Institute. And Norcia reassured analysts today that DTE will “continue to offer a healthy 7% dividend increase this year.”

But if the unregulated midstream business segment doesn’t meet targeted earnings over the coming years, leadership at the company might have to find other business segments to make up that loss in forecasted earnings – in particular, the Michigan Public Service Commission-regulated electric and gas companies.

The company says that it views the PSC as a constructive regulatory body. DTE tells investors that the state’s regulatory environment “is one of the best in the country” due to recovery mechanisms and “solid ROEs.” UBS ranked Michigan as a “Tier 1” regulatory jurisdiction. DTE’s regulated segments have increased earnings from $545 million to $897 million since 2010. 

There has been recent turnover at the PSC, with two of the three commissioners having been appointed in the past 14 months.

Posted by Matt Kasper

Matt Kasper is the Research Director at the Energy & Policy Institute. He focuses on defending policies that further the development of clean energy sources. He also frequently focuses on the companies and their front groups that obstruct policy solutions to global warming. Before joining the Energy & Policy Institute, Matt was a research assistant at the Center for American Progress where he worked on various state and local policy issues, including renewable energy standards. His work has appeared in The Guardian, the New York Times, the Washington Post, and other outlets.