Just In Time Oil

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


Will Fall Seasonals Cause The Market To Rise?

Students of stock market history will know that September is seasonally the worst month of the year. This month is typical. Some may think it’s October because of the crashes that month in 1929 and 1987. Only a few years into my Wall Street career, I returned home on October 19th, 1987, and solemnly warned my wife that a depression was coming. She scoffed that it was a problem for Wall Street not Main Street, and thus emboldened has ever since retained modest skepticism about my market prognostications.

The fourth quarter historically offers the best returns. It’s easy to go down a rabbit warren of meaningless relationships with seasonal patterns. A wet weekend ten days ago didn’t mean golf would be rained out this past weekend, even though it was. One quarter of the four is going to be the best. Since 1980 the 1.6% average fourth quarter return follows the seasonally weakest third quarter of 0.3%. The relationship has persisted for over a century.

MLPs used to have a distinct quarterly seasonal pattern around distribution dates. MLP buyers are often yield-driven and like those quarterly payments. K1s also induce sales before year-end and purchases right after, in both cases to avoid a K-1 for just a few weeks of January (see Why MLPs Make a Great Christmas Present). Fewer MLPs are not just causing rebalancing challenges for Alerian-linked products (see Alerian Still Clinging On). They’re also making the seasonals less pronounced.

More interesting is whether the approaching fourth quarter will hew to the historical pattern.

Recently I switched to Bloomberg TV from CNBC as my background noise of market commentary. I chose substance over entertainment. All day long executives and market participants are discussing interest rates and crude oil. Both are responsible for September’s weak equity market performance, and the energy sector’s resurgence. The macro outlook always offers reasons to worry.

We’ve stopped worrying about the Fed causing a recession (see Jay Powell’s Victory Lap). With the economy coping well with 4.5% ten year treasury yields, there’s concern that rates will remain higher for longer. The Equity Risk Premium (ERP) shows stocks are expensive compared to the past couple of decades, and around neutral going back to 1960.

Bond yields are moving higher with inflation expectations as defined by TIPs remaining well behaved at under 2.5%. Consequently, real yields have breached 2%. Early last year they were negative. Bonds are a better investment than they’ve been for years, though to this writer still inadequate to compensate for our fiscal outlook.

Crude oil is moving steadily higher, causing some economists to worry that this will pressure consumers’ disposable income. The dismal science usually sees problems. We energy investors are not alone in liking the rally in crude (see The Super Cycle Or Peak Oil?). At the margin it should boost demand for electric vehicles. Higher oil and gas prices support a faster energy transition. Sincere climate extremists, if there are any, should rejoice.

Occidental (OXY) CEO Vicky Holub told Bloomberg TV she saw no evidence of demand destruction in response to rising oil. JPMorgan sees OXY keeping capex flat next year versus this, and overall is forecasting a 7% annual decline in E&P drilling budgets. They are better positioned than the International Energy Agency to have an informed opinion on the topic.

If the coming quarter follows the seasonal pattern of providing the year’s best return, perhaps it’ll be because the challenges caused by rising rates and oil prices will not be enough to derail the US economy. They are “known knowns” to partially quote former Defense Secretary Donald Rumsfeld. And if you find those headwinds leave you nervous about the broader market, you’ll find that midstream energy infrastructure has exhibited more robust performance in recent months.

JPMorgan, Wells Fargo and Morgan Stanley all considered the impact of the shrinking MLP universe on Alerian’s indices and the funds and products that are linked. The cost of running a non-RIC-compliant dedicated MLP fund in a RIC structure (corporate taxation) becomes increasingly difficult to justify with a smaller universe of stocks (Morgan Stanley). As more and more large-cap MLPs get eliminated from the indices, the Alerian becomes further imbalanced (Wells Fargo). We would not be surprised to see a methodology change emerge again, potentially lifting the maximum ceiling weight to 15% (JPMorgan).

We have written at length about the contradictions of owning a portfolio of 100% MLPs in a taxable, non-RIC compliant ‘40 Act fund, so have nothing new to add. Holders of such funds will eventually conclude they shouldn’t have been.

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

Energy Mutual Fund

Energy ETF

Inflation Fund




The Super Cycle Or Peak Oil?

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






Offshore Wind vs Onshore

A couple of weeks ago in Windpower Faces a Tempest, we highlighted the challenges facing offshore wind both in the US and Europe. A good friend of mine, a lawyer who has made his career doing energy deals, took issue with the blog post. A spirited text message interaction ensued, continued in person over two rounds of golf together this weekend.

Most lawyers are proficient debaters. Our younger daughter is heading to law school, perhaps inspired by my observation that she never loses an argument, just runs out of time. My legal friend eloquently argued his case in between parring most holes, challenging me to match him on two dimensions. My putting suggests I was more focused on the shortcomings of windpower.

In the blog post, I used offshore windpower examples to illustrate the challenges facing the industry. The US is almost all onshore wind, where the economics are better. Offshore windpower is more common in other countries such as the UK. I was criticized for conflating challenged US offshore wind with far larger and generally successful onshore.

The US Energy Information Administration (EIA) publishes data on windpower generation by state. In 2022 five states in the central US (Illinois, Iowa, Kansas, Oklahoma and Texas) were responsible for half our output.

The Administration has a goal of adding 30GW of offshore windpower by 2030. The US Department of Energy reports that 52 Gigawatts of offshore windower is in development, half of which is off the coasts of New Jersey, New York and Massachusetts. These are the economically challenged projects highlighted in the earlier blog post, and also by RBN Energy (see When The Wind Blows – Potential Project Cancellations Highlight Difficulties For Offshore Wind). Less than 1 GW is under construction. The struggles of many offshore projects are threatening the 30GW goal.

The US has 145GW of installed onshore windpower capacity. The EIA reports that wind provides around 10% of our electricity, with natural gas at 40%. According to the Energy Institute’s Statistical Review of World Energy, renewables (mostly solar and wind) provided 8.8% of America’s primary energy last year, up from 8% in 2021. Renewables are growing, but past energy transitions took decades and so will this one. Natural gas rose from 32.2% to 33.1%. Renewables’ % growth rate is much higher, but America’s biggest source of added energy last year was natural gas.

The intermittency of solar and wind remains a significant obstacle at higher levels of grid penetration. If weather-dependent energy is 5% of your power supply a calm cloudy day doesn’t much matter, but at increased levels it becomes part of the baseload. Electricity needs to be available 100% of the time. Batteries are becoming part of the solution, as are natural gas power plants because they can adjust their power output fairly easily. But the low costs sometimes floated for renewables often ignore the needed backup.

Germany, which generates a fifth of its primary energy from renewables, is an example of the consequent high energy prices that accompany such policies. California is another. Within the US there’s no clear link between windpower penetration and electricity prices. Iowa gets over half its power from wind and enjoys relatively cheap electricity. It must be a reliably windy place.

By contrast, solar power does tend to correlate with higher prices. It’s not just California (18% solar) but states such as Massachusetts and Vermont where one would think their northern latitudes render them unattractive locations. Prices are even more clearly linked with a state’s politics. Red states have cheaper power than blue ones.

Why would anyone want to live in a place that relies on intermittent power.

It’s not just climate extremists pushing the narrative that renewables are the complete solution to our energy needs. Liberal states such as New York and Massachusetts pursue policies that impede additional natural gas use. The Bay state has among the dumbest energy policies around. Six years ago Enbridge gave up on their Access Northeast natural gas pipeline, which would have supplied New England with cheap Marcellus gas, because of unsupportive policies in the region. Nonetheless, last year 77% of electricity in Massachusetts came from gas, almost 2X the US average. Some of it was imported expensively from foreign countries as LNG.

If we face an existential climate threat these fanatics should also embrace nuclear power as a vital solution. Finding a place to store nuclear waste remains unresolved, and costs are currently prohibitive. Georgia Power’s Vogtle nuclear plant started operations in March, years late and at $35BN cost double the original estimate. But France gets 32% of its primary energy from nuclear. America is 7.6%. The global figure is 4%. We should emulate the French.

My learned friend and I agreed on much, including that natural gas will be a significant energy source for the foreseeable future. But he was right to note that US offshore wind is a trivial source of power today. Next time I’m putting for the win he’ll probably distract me with a positive comment about renewables. I’m betting I’ll still make it.

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

Energy Mutual Fund

Energy ETF

Inflation Fund



Crude Climbs The Wall Of Supply Worries

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




Pipelines Returning More Cash

The old MLP model rarely saw stock buybacks. Traditionally the General Partner (GP) would sell assets to the MLP it controlled in a non-arms-length transaction. The MLP would issue equity and debt to pay for them. MLPs were sellers of their own units, not buyers.

Today’s midstream energy infrastructure sector has left that model behind. Most companies are corporations and most have buyback programs in place. Of the names listed, 12 of 16 retired some stock last year and 14 are expected to do so this year.

The buyback yield (ie portion of outstanding shares repurchased) can be added to the dividend yield to give the total return to shareholders exclusive of price changes. By this measure, half the sixteen companies listed offer a return of 7.9% or greater, assuming they execute their buyback programs as JPMorgan projects through the remainder of the year.

This year’s median dividend yield + buyback yield of 7.9% is up from 7.4% last year, a 7% growth rate. Returns are increasing.

MLPs are repurchasing shares alongside their c-corp peers. Without a controlling GP poised to drop down assets they have more conventional growth capex opportunities of acquisitions and re-investing back in the business.

M&A activity has picked up recently, with Oneok’s (OKE) acquisition of Magellan Midstream (MMP) and Energy Transfer’s (ET) purchase of Crestwood. Investors worried that ET’s issuance of $2.7BN in equity to fund this purchase indicated that buybacks were a lower priority. But the company assuaged these fears with a presentation that earmarks up to 20% of distributable cash flow to buybacks once they’ve reduced their Debt:EBITDA ratio close to 4.0X.

The OKE/MMP deal looks likely to receive shareholder approval now that independent proxy firms Glass Lewis and ISS both recommended a yes vote.

The dealmaking reflects increased confidence in the sector’s outlook by management.

Many companies have revised up their 2023 EBITDA over the past year without seeing it reflected in stock price performance.

Valuations are still below where they were in 2019 before the pandemic, even though companies have de-risked by reducing leverage. Enterprise Value/EBITDA averaged 11.5X for the sector according to JPMorgan and is below 10.0X today. Leverage is coming down and dividends are growing. Capex remains well below the levels of 2018, partly because environmental extremists have turned the courts into a weapon against all kinds of infrastructure including renewables (see Windpower Faces A Tempest). This has helped improve free cash flow among pipeline companies.

Canada has similar problems. The TransMountain expansion from Alberta to British Columbia has quadrupled in cost since Kinder Morgan deftly sold it to the Canadian government in 2018. The ultimate tab might go even higher. Engineering difficulties have led the company to request a different route, but the indigenous community is opposed. Public hearings are scheduled, and the crude pipeline’s completion could be pushed back a further nine months to the end of next year. Unlike in the US, Canada’s native tribes never signed peace treaties with the European settlers. As a result they have greater legal rights including limited sovereignty over their land. Canadian construction projects often have to work around this, as TransMountain is having to.

Unexpected delays are common in pipeline projects, which is why it’s unattractive to build them. This makes the existing stock of infrastructure more valuable.

I used to think climate extremists were trying to put us out of business, but I have since developed a more subtle appreciation of their positive impact on free cash flow since there’s less spending on new pipeline construction.

Hug a climate protester and drive him to his next protest.

In spite of all these positives, after two very strong years the pipeline sector as represented by the American Energy Independence Index is lagging the broader market this year. It looks cheap to us.

US natural gas prices have been weak in recent months. Domestic demand isn’t growing fast enough to match production – the market needs more liquefaction capacity.

Fortunately, that’s coming. The US Energy Information Administration (EIA) expects gross LNG exports to reach 14 Billion Cubic Feet per Day (BCF/D) by the end of next year. The net may be smaller if Massachusetts imports LNG as they have in the past (see Why Staying Warm In Boston Will Cost You).

Based on projects under construction, we should be exporting 24 BCF/D by 2027, a doubling over five years. This will add upward pressure to cheap US prices and will enable other countries to reduce their use of coal for power generation.

The valuations, strong fundamentals and growth prospects make this one of the most overlooked sectors in the market.

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

Energy Mutual Fund

Energy ETF

Inflation Fund




Windpower Faces A Tempest

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


Why Are Real Yields Rising?

The members of the Federal Open Market Committee (FOMC) could be forgiven for feelings of quiet satisfaction. They’ve raised short term rates higher than most observers expected, and odds of the consequent recession have been receding. The increase in the unemployment rate to 3.8% on Friday leaves it still well below full employment. Yet inflation expectations remain well contained. The University of Michigan survey reports a five year outlook of 3%. Republicans (3.3%) are more pessimistic than Democrats (2.7%), but members of the White House’s incumbent party are generally more willing to think things will work out.

Inflation expectations from the bond market tell a similar story, with ten year inflation derived from TIPs at 2.3%. All this is consistent with a Personal Consumption Expenditures (PCE) deflator of 2%, since its construction means it tends to run a little lower than the CPI that most people rely on. Fed credibility remains intact.

But there’s always something to worry about. Because the ten year treasury yield has drifted up to 4.25% while the inflation outlook hasn’t changed, it means real yields have risen to almost 2%. As recently as eighteen months ago real yields were negative. The distorting effect of central banks and other return-insensitive investors was sufficient to guarantee a loss of purchasing power on buyers. The current 2% real yield is close to the long term real return on treasuries.

Near term SOFR futures have barely moved over the past few weeks. Contracts five years out and longer have borne most of the upward adjustment caused by the increase in treasury yields.

JPMorgan revised up their 3Q23 GDP forecast to 3.5%. A few months ago they were among those forecasting a mild recession by year’s end, something they no longer expect. Factset bottom-up earnings forecasts have started to edge higher. It’s just as well, because the Equity Risk Premium (ERP), defined here as the difference between the yields on S&P500 earnings and ten year treasuries, makes stocks look as expensive as at any time in the past two decades.

The corollary to an expensive equity market is that bonds are cheap. It’s not something you see often on this blog, but treasuries look more attractive relative to stocks than in a long time. We wouldn’t suggest switching, because the poor US fiscal outlook makes inflation a long-term risk and fixed income investments won’t offer much protection.

Interest expense on the US federal debt is forecast to more than double as a percentage of GDP over the next 25 years, according to the Congressional Budget Office. Publicly held debt will rise from 100% of GDP to 169% over the same period. One of the mysteries of finance is how long term US interest rates have maintained levels seemingly oblivious to our helpless profligacy. Thirty year bonds at 4.4% can only be justified by substantial demand from buyers willing to ignore that. As well as central banks, there are sovereign wealth funds with hundreds of $BNs to invest satisfied simply with the assurance of getting their money back. Add pension funds with inflexible mandates that continued to require a fixed income holding even when yields were below 1%.

Even US banks adopted the same behavior during QE, which is why Silicon Valley Bank failed and why the industry had $515BN in unrealized losses on securities in the first quarter, albeit with an improving trend since 3Q22.

However, there are signs that the appetite for bonds among those that care least about the return may be waning, which is allowing real yields to rise. Kevin Coldiron is a long-time friend and retired hedge fund manager who is now a finance lecturer at UC Berkeley and co-authored The Rise of Carry. Kevin writes thoughtfully on financial markets, and a recent blog post Inflation in the Twenty-First Century Part III: A Circular Flow No Longer addresses this issue.

For decades the US has run a trade deficit. In aggregate, this leaves the world’s exporters with more US$ than they need, and some of them get reinvested back into US treasuries. It’s often pointed out that a trade deficit requires financing by foreigners, through asset sales or debt issuance, because our exports don’t generate enough foreign currency to pay for our imports.

Kevin neatly displays this in the first of his two charts. But he goes on to suggest that this happy state of affairs may be ending. China is reducing its holdings of US treasuries. Perhaps the sanctions imposed on Russia following its invasion of Ukraine was a factor. A $1.1TN investment in US government bonds doesn’t look like a smart move for a country pledged at some point to reunify with Taiwan.

The Federal Reserve is also shrinking its balance sheet, albeit ponderously.

There’s little reason to expect real yields to stop rising. 2% is simply the long run average. It’s only high compared with the past few years. The factors causing China and the Fed to cut back will remain indefinitely. Maybe the bond market, which is far bigger now than in 1994 when Jim Carville famously said it could “intimidate everybody,” is about to command more of our attention.

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

Energy Mutual Fund

Energy ETF

Inflation Fund


The Growing LNG Trade

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


Growth Is Gassy Not Oily

We’ve been critical of Magellan Midstream’s (MMP) proposed sale to Oneok (OKE) for months (see Oneok Does A Deal Nobody Needs), mostly because it forces MMP unitholders to pay taxes now that didn’t need paying and for some may never be paid. But we do agree with MMP CEO Aaron Milford that the growth opportunities in crude oil and refined products where they operate are not as attractive as in natural gas and natural gas liquids. Of course, MMP investors didn’t need him to sell the company because of that, anymore than a merger to create a more diversified business is justified. Investors can create their own diversification or high growth portfolio without M&A by management. But Milford’s not the only energy executive with the conviction that growth is more gassy and less oily.

Energy Transfer’s acquisition of Crestwood brings natural gas gathering and processing assets and reduces crude oil transportation to 20% of ET’s cash flows. This deal also doesn’t create any tax issues for owners.

TC Energy (TRP) recently announced they’re spinning out their liquids business to a be a standalone entity, leaving them to be an “opportunity-rich, growth oriented natural gas and energy solutions company.” They expect their liquids business to offer “incremental growth and value creation opportunities.” This doesn’t sound very exciting. TRP had been lagging its peers because of its high capex. The spinoff announcement wasn’t well received because it caused investors to think a little more about the liquids business and its low growth prospects.

Blackrock and KKR recently sold their stake in an Abu Dhabi crude oil pipeline for $4BN.

Most long term energy forecasts are political documents nowadays. If your projections don’t show a rapid transition away from fossil fuels, climate extremists accuse you of destroying the planet. BP struggled with this in recent years. They handed off their Statistical Review of World Energy to the Energy Institute last year. In 2022 their projections had the Orwellian names Accelerated, Net Zero, and New Momentum. The third was the realistic one showing current trends – the other two were useless for capital allocation.

The US Energy Information Administration (EIA) makes long term forecasts that fortunately remain apolitical. Forecasts of crude oil demand become increasingly tenuous over time because the transportation sector dominates and public policy can more easily impact the move to electric vehicles. But natural gas is harder to replace, especially in the industrial sector where the EIA sees Incremental growth for the next three decades.

The Inflation Reduction Act is encouraging Foreign Direct Investment (FDI). Dutch fertilizer company OCI is investing $1BN to produce ammonia, a key fertilizer input, in Texas. Europe’s declining energy consumption following Russia’s invasion of Ukraine is in part due to de-industrialization caused by high energy prices. Chemical, metallurgic, glass, paper and ceramic industries have been closing factories across Europe. In a recent survey of 3,500 German companies, more than half felt the transition away from Russian natural gas and towards renewables was “very negative or negative” for their business. Some of these companies are transferring output to America. Since 2021 the US has been the world’s biggest destination for FDI.

US exports of Liquefied Natural Gas (LNG) are almost certain to enjoy strong growth as the US adds LNG terminals to send cheap US gas to foreign markets. Industry and LNG exports are the two main drivers of growth for US natural gas.

Construction of new pipelines for both crude oil and natural gas in the US is far below past years and is unlikely to recover anytime soon. We have what we need. This is why growth capex is down more than half from its peak, boosting cash flow and making the stocks attractive.

The only major crude oil pipeline project under construction in North America is the expansion of the Trans Mountain Pipeline which Kinder Morgan wisely sold to the Canadian Federal government in 2018 (see Governments And Their Energy Policies). Getting its oil to international markets is regarded as being in Canada’s national interest. But the same environmentalist activism and cost inflation that delay private sector projects have similarly hurt this one now owned by the public sector. The estimated cost has increased 4X since KMI’s sale.

Recently engineering difficulties in an approximately one mile stretch of tunnel through a mountain in British Columbia have triggered a request for regulatory approval to alter the route. The indigenous population is opposed. Further delays look likely, risking “significantly increased construction costs.”

Gas is a growth business. Capital and M&A decisions are starting to reflect that.

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

Energy Mutual Fund

Energy ETF

Inflation Fund