Changes in US oil inventories sometimes cause a sharp move in the price of crude. It makes perfect sense, even if it’s hard to tease out much of a statistical relationship from the data. Oil stocks, meaning oil held in inventory, have been falling since the early days of the pandemic when the collapse in demand left traders scrambling for places to store it. The most recent weekly data showed our inventories are the lowest in almost forty years.

The US Strategic Petroleum Reserve (SPR) has also been falling. Privately held inventories move based on economics, whereas changes in the SPR are a political choice. This was most notable a year ago when high gasoline prices prompted the Administration to release oil to avoid losses in the mid-term elections. Such sales have continued (see Crude Climbs The Wall Of Supply Worries).

So for different reasons, both privately held inventories and the SPR are falling. Historically the two moved more or less independently given their differing objectives. Now, both the Federal government and commercial operators are concluding they need to hold less.

Businesses generally hold inventories of the inputs they need for production and finished goods awaiting sale. Such decisions are made to smooth production lines. Oil has the additional motivation in that speculation on higher prices may increase inventories. And the Federal government has its own, non-commercial goals.

One way to think about inventory adequacy is to measure how many days of domestic consumption could be supported if output and imports stopped. It’s well short of a perfect measure, because it assumes all the oil in storage could seamlessly move to where it’s needed and be of the correct grade to be acceptable to the refineries or other users taking delivery. So the current ratio of total oil in storage divided by average daily consumption of 57 days doesn’t mean inventories could satisfy domestic demand for that long. It’s undoubtedly far less. But it is the lowest ratio on record, going back 37 years. We’re on track to find out what inventory level is too low. Rising crude will tell us we’re there. It may already be happening.

“Just in time inventory” has made manufacturing more efficient. Delivering inputs only when needed to an automobile factory reduces the needed working capital and improves profitability. The decline in privately held oil stocks in recent years combined with stable refinery runs shows a similar improvement in operating efficiency.

Increased domestic oil production reduces our need to hold inventories for energy security. We’re less reliant on imports but because US refineries can’t use all the light shale oil we produce, two-way trade brings in the heavy crude they’re designed for and exports lighter grades. We have enormous inventory underground, accessible when needed.

Domestic production is growing, but slowly. The Baker Hughes oil rig count is at 513, down almost 20% from its peak late last year. Current output remains just shy of the 13 Million barrels per Day record of November 2019.

Exxon Mobil (XOM) is operating 17 rigs, down from 65 four years ago. Energy companies are staying disciplined, unmoved by the recent run up in prices. “If you think about capital efficiency, and you want to make sure you’re thinking long-term about your business, moving [drilling rigs] up and down a lot is not a good idea,” said Jack Williams, a senior vice president at XOM.

Pipeline operators often complain about the difficulties with construction. The experience of Equitrans with Mountain Valley Pipeline (MVP) is perhaps the most famous example of the cost that endless environmental legal challenges can impose on infrastructure projects.

But renewable energy is more urgently dependent on permitting reform because future Infrastructure projects will be concentrated there. We mostly have the oil and gas pipeline network we need, which is why midstream companies are buying back stock and raising dividends.

Wind turbines and solar panels are built in remote, sparsely populated locations. They need long-distance, high voltage transmission lines to move power to population centers. Decarbonizing our energy systems means converting more demand to electricity.

A recent WSJ report showed that more than 10,000 energy projects were awaiting permission to connect to electric grids at the end of last year, almost all wind and solar. The SunZia wind project in New Mexico filed for permits in 2006 and just received the go-ahead to begin construction. America’s system of government creates many opportunities for NIMBY opponents to file legal challenges at the local and state levels as well as federal.

Consequently, 17% of our primary energy comes from carbon-free sources. Half of that is nuclear, which given public resistance is unlikely to grow much. Switching from coal to natural gas for power generation remains our biggest source of reduced greenhouse gas emissions. Ironically, court challenges to new energy infrastructure from environmental extremists represent a significant challenge to renewables.

We three have funds that seek to profit from this environment:

Energy Mutual Fund Energy ETF Inflation Fund

 

In March of 2020 when crude oil was collapsing dragging energy stocks, including pipelines, along, I tried to focus on the positive, which was that it had become cheaper to drive places. Except there was nowhere to go because of the lockdown. And even if there had been, I would have had to make roughly three round trips to the moon and back to generate enough savings on gasoline to compensate for my losses on infrastructure.

What some might deem an imprudently high allocation to the sector was paired with a timid appetite for leverage (ie there was none). With no need to sell I was miserable only until prices started recovering. Having endured low oil prices, I find high prices wholly more agreeable.

Therefore, JPMorgan’s chart depicting a widening supply deficit over the next several years causes me little angst. Those around me might even enjoy my pleasant demeanor if the forecast is true.

Interestingly, JPMorgan’s 2028 forecast of global demand matches the International Energy Agency (IEA) in their Oil 2023 publication at 105.7 Million Barrels per Day (MMB/D), an annual growth rate of just under 1%. Both agree that gasoline demand will soften while other oil products such as jetfuel, LPG and heating oil will continue to rise.

However, they reach very different conclusions on supply. The IEA is more bullish on US output, and therefore doesn’t foresee a supply/demand imbalance. By contrast, JPMorgan expects only 1% annual US production growth. They attribute this to (1) declining productivity, (2) continued focus on accretive projects to drive shareholder returns, and (3) higher interest rates. They see US upstream capex declining 7% annually through 2030.

The result is that JPMorgan is overweight global energy, proclaiming the “Supercycle returns.” They believe, “the upside risk to oil is $150 per barrel over the near to medium term.” They see a “higher for longer” outlook as financial discipline and increased cost of capital combine with “institutional and policy led pressures driving an accelerated transition away from hydrocarbons and peak demand fears.”

The IEA report strikes a more politically correct tone, asserting that increased investment in renewables is bringing “peak oil demand into view.” Reading it is supposed to leave investors in traditional energy despondent. JPMorgan disagrees: “We don’t see peak oil demand on our investment horizon (2030)”. They have a multi-year bullish outlook.

The IEA has a more optimistic supply view combined with a more pessimistic demand outlook. Energy producers embracing both would be disinclined to invest in the very supply growth the IEA expects. They’re forecasting peak oil within a decade or so to stimulate increased capex in oil projects that typically require well over a decade to generate an acceptable return. Only one part of that scenario can plausibly occur.

Analysts at Citi and Bank of America are similarly bullish, which contrarians will view as evidence of an already crowded trade.

If crude oil was falling, we’d note the unimportance of commodity prices to the pipeline sector. Rising prices reflect improving sentiment towards the energy complex and perhaps a modest EBITDA uplift for midstream infrastructure. But given attractive valuations, as generalist investors have begun to revisit their exposure to energy it doesn’t take much to push the sector higher. Market outperformance of the American Energy Independence Index has coincided with the rally in crude oil. They’re likely to continue moving up together.

Oneok’s (OKE) acquisition of Magellan Midstream (MMP) was approved by owners of both companies last week. Now comes the big rebalancing. MMP unitholders will receive $25 per unit, which means about $5BN in cash will be available for reinvestment early this week. Some will be set aside for taxes, but much of what’s left will go back into midstream c-corps, which should give the sector a bid.

$5.6BN is the amount of MLPs the Alerian MLP ETF (AMLP) would have to sell if they decide to rebalance away from the declining MLP sector towards c-corps. Wells Fargo reviewed the challenges this is creating for MLP-dedicated funds that follow Alerian indices. It’s an issue we have noted in the past.

The family of Invesco Steelpath funds would have to sell around $4.5BN in MLPs if they similarly rebalanced. Neither will want to make such a choice after the other. And if Alerian changes their index construction it might force the issue.

As much as $10BN of MLP positions might be swapped into c-corps if such a rebalancing goes ahead. Wells Fargo reviewed the available options but stopped short of predicting what will happen. The issue won’t go away. Fund flows ought to favor c-corps over MLPs.

We three have funds that seek to profit from this environment:

Energy Mutual Fund Energy ETF Inflation Fund

 

 

 

 

 

Crude oil has rallied recently, in a much delayed reaction to numerous analyst forecasts that have been bullish all year. A couple of months ago Goldman’s commodities head Jeff Currie, who is leaving the bank, cut his year-end forecast for Brent crude from $95 per barrel to $86 while maintaining his long term bullish outlook. He blamed ongoing releases from the US Strategic Petroleum Reserve (SPR) and “a more discerning approach to sanctioned oil,” meaning that Iran and Russia are exporting more than he expected.

Currie and other analysts have maintained a bullish long term outlook because they see a growing supply-demand imbalance. This has been delayed by the issues mentioned above, but there are signs that crude is entering a sustained uptrend.

Sales from the SPR have weighed on prices. Last year the Administration released crude oil prior to the midterms, leading to criticism that they were cynically risking our energy security in a short-term effort to buy votes. While this was likely the motivation, sales have continued and the SPR is at its lowest level in forty years.

The US consumes about 20 Million Barrels per Day (MMB/D) of crude oil and petroleum products, a figure that hasn’t changed much in over two decades. The sharp decline in the SPR means it covers just 17 days of consumption compared with the 30-40 days that was common for much of the SPR’s existence.

The 1975 Energy Policy and Conservation Act was passed in response to the 1973-74 OPEC oil embargo during the Yom Kippur War. America’s energy security is dramatically different nowadays, thanks to fracking and horizontal drilling. The White House is likely to dip into the SPR again in the run up to next year’s election. Doing so will be politically expedient, but perhaps we no longer need to keep oil in storage given our ready access to domestic supply.

OPEC+ has responded by limiting supply, since they want the highest price that can sustain current demand. OPEC expects global oil demand this year to set a new peak of 102.1 MMB/D and to rise further next year.

Meanwhile they see a growing supply shortfall, exacerbated by the Saudis and Russia extending their 1.3 MMB/D cut through year’s end. Other analysts agree.

The International Energy Agency (IEA) expects 2024 global oil demand growth less than half of OPEC’s. They see gasoline demand peaking over the next couple of years at 26.6 MMB/D as Electric Vehicles (EVs) continue to gain market share, especially in China. They see EV sales growing from 10.8 million last year to 25.9 million by 2028, at which point they’d represent more than a quarter of new car purchases. By then crude oil demand will be over 3 MMB/D lower than without EVs.

However, since China gets 60% of its total energy from coal and 71% of its electricity, the growth in EVs led by China hardly seems a cause for celebration. Given the greenhouse gas emissions and local pollution from coal, it’s quite possible the world would be better off if China stuck with internal combustion engines.

The Tesla owners I know love their cars, but they all have another conventional car for long trips. An Uber driver once told me that she was happy with the Tesla leased from the company but confessed to spending an hour recharging it in the middle of every day. EV sales have momentum, but I’m in no great rush to join. It’s bad enough worrying about recharging my iphone battery, never mind my wheels.

The IEA expects growth in jet fuel and petrochemicals (lubricants, solvents etc) will continue to push global oil demand higher at around a 1% annual rate. Nonetheless, they share the short term concern of others that low inventories, extended OPEC+ production cuts and increased demand from developing countries could push prices higher over the near term.

Discussion of the correlation between crude oil and midstream energy infrastructure is common when they’re both falling. We’ve written about this topic in the past. The relationship between pipeline stocks and commodities has been weak over the past couple of years (see Oil And Pipelines Less In Sync) However, over the last three months Brent crude has risen over $15 per barrel, coinciding with a run of market outperformance by the American Energy Independence Index (AEITR).

Pipeline companies are unlikely to revise earnings guidance, but there’s little doubt that this latest move shows sentiment towards the energy sector is improving. The fundamentals have been strong for a long time, so to us a rallying AEITR seems fully justified.

We three have funds that seek to profit from this environment:

Energy Mutual Fund Energy ETF Inflation Fund

 

 

 

At the end of August Orsted, a Danish developer of wind turbines, announced they’d be delaying their first planned installation off the New Jersey coast until 2026. They blamed supply chain issues, interest rates and insufficient US Federal tax credits. The Federal government had only recently approved the project.

New Jersey Democrat governor Phil Murphy and the Democrat-controlled legislature are big proponents of the garden state switching to windpower. New Jersey has regrettably moved to the left in recent years, partly because Republican voters are leaving for southern states such as Florida.

But even though New Jersey is a solidly blue state, there is plenty of opposition to windpower along the Jersey shore, which tends to be more conservative. Cape May county, opposite which the wind turbines are planned, is both especially conservative and opposed. Turbines already in place are blamed for a jump in whale deaths although this is disputed. It’s also feared that they will spoil the view. Protect Our Coast NJ is adopting some tactics from the environmental extremists’ playbook in using court challenges to impose costly delays. Treasurer Frank Coyne said, “The objective is to hold them up and make the cost so overwhelming that they’ll go home.”

The cost of installing windpower is going up. Orsted said it may take a $2.3BN writedown on its US projects. New Jersey Democrats even passed legislation redirecting Federal tax credits from residents to Orsted in order to make the economics more appealing. The delay until 2026 means the project won’t be completed before Phil Murphy leaves office, casting further doubt over its ultimate viability. Orsted has said it considered abandoning the project but for now intends to proceed, which is likely to encourage opponents to keep up the pressure. So far they’ve invested $4BN in US offshore wind projects including Montauk point at the tip of Long Island, and Rhode Island. They plan to make a final investment decision on all three by early next year.

Orsted is not alone. Spain’s Iberdrola canceled a planned wind farm off the coast of Massachusetts. Sweden’s Vattenfall backed out of a project off the coast of Britain, citing cost inflation. Siemens is expected to lose up to $5BN in its wind turbine manufacturing unit.

It’s tough to make money in renewables.

Then there’s NextEra Energy (NEE) and its MLP NextEra Energy Partners (NEP). NEE is “an industry-leading clean energy company” and is building its renewables capability as fast as it can. Four years ago we wondered if rapid depreciation in its asset base would ultimately hurt earnings (see Is NextEra Running in Place?). At the time the company was depreciating 5.5% of its Property, Plant and Equipment (PP&E), higher than other utility companies and suggesting a useful life of under twenty years.

Rapidly improving costs for renewables power generation cause older equipment to depreciate more quickly. And solar always faces the challenge that if a region is sunny enough a utility might find its customers investing in their own solar panels and batteries, disconnecting from the distribution network which means the fixed cost of transmission lines is spread across fewer users. It still doesn’t look like an appealing business to us.

NEE pulled ahead of the American Energy Independence Index (AEITR) for the next three years following our 2019 blog post, and its depreciation as a % of PP&E fell back to its peer group. In recent weeks it’s lagged and is now behind the AEITR over that time period. Over the past year NEE and NEP have substantially underperformed the AEITR.

An investor asked me last week what I thought of NEP. It is an old-fashioned MLP, with a controlling General Partner (GP) that can drop down assets. Midstream energy infrastructure, still known colloquially as the MLP sector, used to have many similar structures. The GP, in this case NEE, has a similar position to a hedge fund manager with respect to her hedge fund, in this case NEP.

When MLPs were controlled by a GP, we always favored the GP, just as you’d rather be the hedge fund manager rather than a hedge fund client. In 2012 I published The Hedge Fund Mirage: The Illusion of Big Money and Why It’s Too Good to Be True which revealed how investors had in aggregate done poorly in spite of hedge funds being wildly profitable, because fees had siphoned those returns over to the manager.

We recognized the analogy with MLPs and their GPs. NEE is NEP’s GP. They retain the old model but are in new energy. So we would avoid NEP and favor NEE because we always prefer the GP.

Nonetheless, it’s easy to see why both stocks look attractive especially if you want exposure to solar and wind. Within three years NEE is planning to have more renewable generation capacity than total installed capacity for any other US company. NEP is planning to sell its natural gas pipeline business and be 100% renewables.

NEP yields 7.6% and is guiding for 12% annual distribution growth. Its one year total return is –40%, probably dragged down by the challenges faced by Orsted and others.

NextEra’s wildly bullish outlook on renewables runs counter to the experience of the windpower manufacturers. They are a pureplay bet on renewables profitability, contrasting with writedowns being taken elsewhere in the industry.

It’ll be fascinating to see how this plays out.

We three have funds that seek to profit from this environment:

Energy Mutual Fund Energy ETF Inflation Fund

 

Nearly three years ago, French utility company Engie pulled out of negotiations with NextDecade (NEXT) to buy Liquefied Natural Gas (LNG). Concerns about leaks during the production of natural gas (methane) were the reason. Methane is a GreenHouse Gas (GHG) that is many times more potent than CO2 over a decade or so at trapping heat in the atmosphere. Over longer periods it decomposes, whereas CO2 remains for a century or more.  

Energy sector methane leaks are far from the biggest source. The International Energy Agency (IEA) estimates that natural gas related leaks are only 7% of the total. A third of methane emissions occur naturally in wetlands. Agriculture is responsible for a quarter, mostly from ruminants (cows and sheep) belching and farting. Several companies are developing a seaweed-based animal food additive that would alter the digestive process of such animals.  

Last year I met Steve Turner, CEO of Australian company Sea Forest at a wedding. Usually a Brit and an Aussie talk trash about each other’s national cricket teams upon meeting for the first time, but I quickly learned Steve’s company was turning asparagopsis into a solution to agricultural methane emissions (see How Seaweed Can Fight Global Warming). It’s an area worth following. 

Anyway, Engies’s conclusion in 2020 that US natural gas was harming the planet was a big setback for NEXT, which was trying to line up enough buyers of LNG from their planned Rio Grande terminal in Brownsville, TX to justify making a Final Investment Decision (FID) to go ahead. The company responded within a few months by launching NEXT Carbon Solutions to develop Carbon Capture and Storage (CCS) at Rio Grande. Recognizing the sensitivity of European buyers like Engie to the environmental impact of their product, they committed to provide “responsibly sourced gas” that is certified as being produced with minimal leaks, and to ensure their liquefaction process is GHG emission-free, by using a combination of renewable energy and CCS.   

NEXT negotiated agreements with other buyers to provide environmentally friendly gas. In April 2022 Engie returned and signed a 15 year deal for 1.9 Million Tonnes Per Annum (MTPA). Russia’s invasion of Ukraine dramatically changed Europe’s access to natural gas, but the changes NEXT had implemented addressed Engie’s earlier objections. FID on the Rio Grande LNG project came in July.  

Bechtel Energy has the contract to build the facility, having been Cheniere’s longtime construction partner for their Sabine Pass, LA and Corpus Christie, TX terminals. Recently Bechtel Energy’s President, Paul Marsden, and NEXT’s CEO Matt Schatzman, held a videotaped mutual lovefest during which each emphasized the climate-friendly features of the project. Climate extremists should be supportive, because by displacing coal in the world’s biggest emitters such as China and India, US LNG is a most effective counter to rising GHGs.  

NEXT’s FID in July was poorly received by the market because they were left with 20.8% of the economics in Trains 1-3 (Phase 1), less than the approximately one third investors had been led to expect. Global Infrastructure Partners and the sovereign wealth funds of Singapore and Abu Dhabi share 62.5% in exchange for $4.75BN of equity capital. France’s TotalEnergies took 16.7% in exchange for $1.1BN and a 20 year commitment to buy 5.8 MTPA. The $6.1BN in equity plus $11.8BN in debt financing makes Rio Grande Phase 1 the largest greenfield energy project financing in U.S. history. 

The modest 20.8% stake retained by NEXT looked as if they’d been out-negotiated.  

Global LNG demand is rising. Research firm ICIS Analytics expects the US to increase its market share from 22% to 31% over the next five years. Germany, the Philippines and Vietnam all began importing LNG for the first time earlier this year. More countries are expected to follow. The EU continues to buy LNG from Russia, as they try and impose sanctions that don’t drive energy prices up. Belgium and Spain are the world’s second and third-biggest importers of Russian LNG this year. They aim to stop completely by 2027. 

NEXT currently trades at the low end of the $6-8 per share valuation range sell side analysts ascribe for Phase 1. The upside potential for the stock relies on the completion of Trains 4-5 (Phase 2). The Rio Grande project is estimated to work out at $700-800 per tonne of capacity for 17.6 million tonnes per annum. Qatar’s expansion is estimated to cost $900 per tonne. Total’s Mozambique LNG project has faced many problems and is reported to cost $1,500.  

Rio Grande Phase 2 will benefit from the site preparation done for Phase 1, and as a result could cost under $500 per tonne. What’s unknown is what NEXT’s percentage ownership of Phase 2 will be. The market currently places minimal value if any on Phase 2. NEXT should be able to negotiate a much bigger stake, because Total already has an option on 32% of its capacity. Timing is uncertain, but the odds of Phase 2 ultimately going ahead look good to us. NEXT will be part of America’s increasing share of global LNG.  

We have three funds that seek to profit from this environment:

Energy Mutual Fund Energy ETF Inflation Fund