Today’s Pipelines Leave MLPs Behind

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Last week Kelcy Warren, CEO of Energy Transfer (ET), defended the MLP structure. He’s definitely correct that MLPs possess a powerful tax advantage over corporations, in that their profits are only taxed at the investor level. Tax-deferred income free of the double-taxation to which corporate profits are subject is very appealing, and for years it drew countless buyers. Unfortunately, Warren is part of the reason that the MLP structure is losing favor. Midstream energy infrastructure and MLPs used to be synonymous, but widespread distribution cuts and investor abuse have left the old, rich Americans who used to be the investor base betrayed.  The names Kelcy Warren and Rich Kinder still elicit strong reactions from longtime MLP investors.

The Alerian MLP ETF, a good proxy for how MLPs have performed, has cut its distribution by 34% since the market peak in 2014. Companies chose to finance growth projects in excess of free cash flow, and ultimately resorted to either outright distribution cuts or “backdoor” distribution cuts by merging with a their lower yielding corporate general partner. Many MLPs abandoned the structure, and income seeking investors in turn have abandoned the remaining ones.

The result today is that MLPs represent 36.5% of the sector by market capitalization, as defined by the Alerian Midstream Energy Index — AMNA (see MLPs No Longer Represent Pipelines). Kinder Morgan, ONEOK, Enbridge, Targa Resoures and Williams Companies are among those that have fully adopted the corporate structure.

MLP-dedicated mutual funds and ETFs were originally designed to offer sector exposure to retail investors who didn’t want to deal with K-1s. They saddled their investors with a ruinous tax burden, because funds with over 25% of their portfolios in partnerships (which is what MLPs are) have to pay corporate tax. It seems odd to take a tax-efficient vehicle and add taxes to it, but showing how few investors read the fine print, these products took hold. And they’re now focused on just 36.5% of the sector (see Are MLPs Going Away?).

To illustrate how much things have changed, just two names, Energy Transfer and Enterprise Products, represent 43% of the market cap of all MLPs.  Dedicated MLP funds are forced to drastically underweight these two, which leaves them with outsized exposure to the smaller MLPs. They’ve moved a long way from diversified portfolios of large, fully integrated “toll road” pipeline systems that originally attracted investors.

The biggest of them, the Alerian MLP ETF, has since inception delivered less than one third of its index. This is probably the worst performing index ETF in history. Corporate taxes have taken a bite, and when the sector delivers a couple of big years the tax hit will be even more noticeable (see MLP Funds Made for Uncle Sam). The 1.04% since inception annual return is not far from the 0.85% advisory fee, putting AMLP in the company of the hedge fund industry in making profits while the clients don’t.

If you ever meet one of the hapless souls who’s chosen AMLP, you’ll find they’re probably unaware of the tax drag.

The shrinking number of MLPs has rendered MLP-dedicated funds less representative of the sector. Of the ten biggest North American pipeline companies, six are corporations and so excluded from AMLP and its cousins. Every time another pipeline company leaves the publicly-traded MLP universe, these funds are left with fewer names and a preponderance of small ones. The market has shifted since many of these were launched a decade or more ago (see AMLP’s Shrinking Investor Base).

If any of these funds decides to reduce their MLP exposure below the 25% threshold, so as to be more representative and avoid corporate taxes, it’ll depress MLP prices because many will have to sell three quarters of their holdings. A quarter of the $135BN in public float for all MLPs is held by $34BN in MLP dedicated-funds. It’s a crowded space.

Moreover, AMLP reflects the worst of MLPs – AMNA is 21% Gathering and Processing (G&P), the more risky end of the midstream business because it’s more dependent on production from specific areas. Due to limited choices, AMLP has 26% exposure to G&P. Even worse, natural gas pipelines are a big underweight in AMLP, even though the long term prospects for natural gas are more visibly positive than for crude oil and liquids. Natural gas pipelines represent 46% of AMNA, but only 27% of AMLP. So AMLP investors have an overweight towards crude oil and liquids.

Investors are starting to act on the many flaws of MLP-dedicated funds. Over the past year, $4.1BN has left the sector. The American Energy Independence Index is investible (you cannot invest directly in an index) and has weights that are more reflective of the industry. Its holdings are mostly corporations, which reflects today’s pipeline business. Several names are ESG holdings for Blackrock and other big fund managers, but MLPs don’t pass ESG screens because of poor governance (watch ESG Investors Like Pipelines). The broader investor base and ESG qualities helped pipeline corporations outperform MLPs last year.

Disclosure: our affiliated investment products are structured to reflect the insights listed above.

Crude Catches a Virus

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We’re in one of those times when everything is a macro call. Stocks and sectors are, for now, more highly correlated, since Coronavirus developments are dominant. Click here for some cool graphics illustrating its spread. The recent recovery in stocks echoes the information on the link.

We won’t attempt to offer any insight on the virus, but have some observations on energy markets.

Recent reports suggest that China’s crude demand is down by around 20%, or 3 million barrels per day (MMB/D). OPEC is apparently considering temporary cuts of 0.5 MMB/D and could perhaps reduce by 1 MMB/D. That still leaves the market over-supplied by 2.0-2.5 MMB/D, although China’s imports should hold up relatively better as it builds strategic reserves.

Libya’s production has fallen by around 1 MMB/D, from 1.2MMB/D to just 0.2 MMB/D recently, because of the ongoing civil war there. However, they are holding peace talks and a cease-fire agreement may be reached soon.

Before the Coronavirus hurt demand, we had thought U.S. shale output was likely to come in below expectations (see Why Oil Production May Disappoint).  Oil wells experience faster depletion than natural gas, which means that as shale production grows an ever increasing number of new wells is needed to compensate for the production drop-off experienced by older wells. We also noted the sharp drop in “DUCs” (Drilled but not yet Completed), which become the source of future production when they’re completed.

Schlumberger, the world’s largest oil field services company, recently announced plans to pull back from shale oil because they see so many E&P companies struggling to be profitable. In announcing results last month, CEO Olivier Le Peuch said, “North America revenue of $2.5 billion…dropped 14% sequentially due to customer budget exhaustion and cash flow constraints.”

Capital is clearly becoming constrained. Natural gas-dedicated E&P names such as Chesapeake and Range Resources have seen their stock fall 95% or more from peak levels more than five years ago. Even the biggest companies such as Exxon Mobil trade at historically low valuations.

The rig count has been sliding for some time amid weak crude oil prices and steadily sinking natural gas. The Coronavirus-driven sudden drop in crude prices is likely to cause a further pullback in the rig count drilling for shale oil, restraining production growth.

The caveat is increasing efficiency of production. The U.S. Energy Information Administration recently noted that oil and gas production grew in 2018 even while the number of wells in operation fell 10%. Doing more with less has been a hallmark of the Shale Revolution since its infancy. However, this reaches a limit as the least efficient rigs drilling the highest cost acreage are the first to be laid down, leaving the high-tech rigs in the sweet spots.

Depending on the length of economic disruption caused by the Coronavirus, supply may need to adjust. Low prices are the best cure for oversupply. Saudi Arabia has signaled they’re willing to cut production with OPEC to get the price of oil higher, and can maintain its lower production quotas after demand has recovered. U.S. activity demonstrates that shale oil growth was already moderating before recent developments. Meanwhile, many forecasts see the physical oil markets shifting to a multi-year deficit in the back half of 2020 and tension in the middle east remains elevated as the US continues its maximum pressure policy of sanctions on Iran.  With the many cross-currents, energy investors remain on the edge of their seats.

Kinder Morgan’s Slick Numeracy

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A Chief Financial Officer needs to know her way around a financial statement. Presenting operating performance in the best possible light is a highly valuable skill. We watched Kinder Morgan’s (KMI) Analyst Day last week via webcast, and my admiration is split between (1) KMI President and former CFO Kim Dang’s deft maneuvering among numbers, and (2) my detail-oriented partner Henry Hoffman for spotting the sleight of hand.

The story begins where KMI uses a “bridge” chart to show how EBITDA changed from 2014 to 2020. Dang introduced the slide as answering a common investor question: if you’re doing so well, why isn’t EBITDA growing more?

The chart includes the much criticized CO2 segment, which sells CO2 for Enhanced Oil Recovery (EOR) as well as being used by KMI itself for that purpose. CO2 contributed a $0.6BN decline to EBITDA from 2014-20. Since its decline is shown on the chart, it must also be part of the $1.8BN EBITDA increase from Expansion Projects, because the $7.6BN 2020 Adjusted EBITDA is for all of KMI.

Another slide shows an attractive EBITDA multiple on capital invested, of 5.9X. In other words, $100 invested will return its capital invested over 5.9 years. The reciprocal of 5.9X is the return, a juicy 16.95% in this case and well over KMI’s assumed cost of capital. The 5.9X multiple implies these projects are generating $2.08BN in EBITDA.

But the small print notes that on this slide, CO2 segment Expansion Projects are excluded.

To find out what KMI invested in CO2 projects 2015-19, we turn to another slide, which shows annual figures.  Adding up the Capex for 2015-19 gives $2.18BN.

So KMI’s total capex over the period covered was not $12.3BN but $14.48BN,  once you add back CO2.

This makes the EBITDA multiple on new investments a little less stellar. The $1.8BN in EBITDA from Expansion Projects that required $12.3BN in investment equates to a 6.78X multiple. But since we know the $1.8BN EBITDA is from all Expansion Projects, including the CO2 business, it’s appropriate to add back the $2.18BN invested in CO2 Expansion Projects to get the true total.

That means the $1.8BN in “growth” EBITDA was earned on $14.48BN in capex, or a multiple of 8.04X. That’s 12.44% rather than the 16.95% calculated earlier. It’s pre-tax, and excludes interest expense as well as depreciation.

KMI uses more than one EBITDA definition through these slides, so you have to follow carefully. When calculating the EBITDA multiple, they like the “Year 2 Project EBITDA”, with its implied $2.08BN in EBITDA. The EBITDA bridge chart simply shows 2020 EBITDA of $1.8BN from all new projects initiated since 2015. Why are they different, and what does it mean?

Investment outlays have been falling since 2015, which means that the projects funded since then are, on average, past the two year mark. 2020 capex is almost a third lower than it was in 2015.

Since the $2.08BN “Year 2 Project EBITDA” is above the $1.8BN 2020 EBITDA from Expansion Projects in  the bridge chart, and we know the average project is more than two years old, it means that EBITDA from new projects is declining. Using the “Year 2 Project EBITDA” flatters the results. Management teams persist in using EBITDA multiples, which are easily manipulated, rather than NPV and IRR. It’s as if they don’t think their investors will understand them – or maybe they’ve concluded that EBITDA multiples are easier to obfuscate.

Following this is admittedly a complicated exercise, but it illustrates the agile numeracy required of today’s energy sector CFO, and of the investors interested in properly understanding their business. KMI is certainly not alone in using financial complexity to their benefit. In this case, we think it’s driven by their continued retention of the CO2 business, which they should sell. Apart from that, KMI has some great assets.

We are invested in KMI

Washington-DC Based Energy Experts Offer Their Outlook

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We had an opportunity to meet with a Washington-DC based independent research firm, specializing in energy policy and geopolitics last week.  The following is from our notes on their discussion.

On Iran, one principal, a highly decorated ex CIA officer and Iran expert, thought markets continue to underestimate the risk to oil infrastructure and production in the region. He expects tensions to increase in the months ahead, possibly leading to direct negotiations with the U.S. in 3Q20. He expects asymmetric attacks to resume once plans are approved by Supreme Leader Khamenei, with military confrontations in Iraq but energy infrastructure targeted elsewhere in the Middle East. He placed the odds of a major escalation at 25%, most likely as a result of a miscalculation followed by a disproportionate U.S. response (“Trump likely to hit back 10X”).

We would note that U.S. infrastructure assets should look relatively more attractive to investors in the scenario described above (see Gulf Tensions Back in Play).

On Libya, he noted that the lost output of 1 Million Barrels a Day (MMB/D) has had muted impact, because OPEC retains excess supply well in excess of that. He also thought that Saudi Arabia was willing and able to make further cuts if needed, as long as others are in compliance.

Contrary to consensus, he sees Venezuela increasing output to 0.8 MMB/D, because the current bottleneck is in marketing. The fact that the U.S. has allowed Chevron and others to continue business in Venezuela suggests a tacit acceptance of exports finding their way to market.

On Electric Vehicles (EVs), China recently cut EV subsidies but also relaxed restrictions on conventional internal combustion engine vehicles. This illustrates China’s preference for economic growth over reduced greenhouse gas emissions, something we’ve often noted (listen to our podcast China Keeps Warming the Planet). Another expert who specializes in energy policy matters also argued that technical requirements for mandated emission reductions in Europe render them unachievable, and that strong SUV sales will support gasoline demand.

The discussion turned to domestic politics and what changes could be expected with a Democrat in the White House (not currently anyone’s forecast). By contrast with Obama’s view on natural gas, which this policy expert regarded as relatively clean and a “bridge” fuel towards decades-long development of renewables, he noted that today’s Democrats view natural gas as just another fossil fuel. He predicted that a Democrat president would likely impose an immediate ban on new leases on Federal land. Current Gulf of Mexico production is 2 MMB/D, and onshore from Federal land is around 1 MMB/D.

Around 1/8th of natural gas is extracted on Federal lands, but this is more easily replaced with increased production on private acreage. He also expects a new administration would rescind existing permits on Federal land, and although courts would likely disallow this, resolution could take a while. Tighter rules on methane leakage and waste prevention are likely, which would eventually impede production on private land. The granting of infrastructure permits would become highly political, with FERC likely to become partisan. No new LNG export permits should be expected.

Democrat policies would likely reduce U.S. supply, exacerbating Middle East tension by increasing U.S. reliance on OPEC imports (see Energy Strengthens U.S. Foreign Policy).

Overall we felt there were several differentiated insights from the discussion and wanted to share them.

Why Oil Production May Disappoint

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E&P companies routinely drill wells but hold off completing them until a later date. Completion includes creating a cement outer wall for the well to avoid leaks, and firing holes in the exterior in preparation for injection of fracking fluid under pressure. Typically wells can be drilled in sequence, as the drilling equipment is moved to the next site, but are completed in batches once a fracking crew is available. Drilled but Uncompleted wells (“DUCs”) are a form of production inventory, in that they represent future output once completed.

The Energy Information Administration collects data on DUCs, and it usually tracks production pretty closely. There’s an underlying assumption that a DUC will eventually be completed, but sometimes a drilled well is a dud, or completing it never becomes economically viable. Some believe that the EIA’s measure of DUCs is substantially overstated. This matters to future production, because fewer wells to be completed means less output, until more wells are drilled.

A characteristic of shale oil wells is that they deplete faster than natural gas. As crude production has increased in the U.S., this means that an ever greater number of new wells need to be drilled in order to compensate for depletion from an ever increasing number of current wells. Because this can’t happen indefinitely, production growth has to slow from it past torrid pace. We explored this in Drilling Down on Shale Depletion Rates.

The time from drilling to completion varies and doesn’t ultimately affect output, according to a study last year from the EIA (see Time between drilling and first production has little effect on oil well production). But it’s also true that the longer a well remains a DUC, the less likely it is to ever be productive.

Currently, we’re completing around 1,200 wells per month. The EIA study referenced above estimated 3-4 months on average between drilling and completion – this was based only on North Dakota, so subsequent inferences rely on that single region to represent the country. But assuming the 3-4 months applies more broadly, that implies 3,600 to 4,800 DUCs in rolling inventory.

In recent months, DUCs have fallen noticeably although tight oil production has continued to grow. At around 7,500, DUCs are only modestly above our assumed rolling inventory. Because production has begun to diverge from DUCs, it suggests either drilling activity must pick up sharply to restore DUCs to output, or output itself will fall.

This doesn’t allow for any overestimate of DUCs by the EIA. Criticism from industry executives include comments such as, “My sense is the EIA DUC number implies more production capacity than actually exists and leads to downward revisions of supply estimates, which we have seen in the last six months.” Another added, “The EIA has no clue on their estimated number of DUCs, in my opinion.” Sadly, the executives are unnamed in last September’s piece from S&P Global Platts (see US producers criticize EIA estimates of DUCs, clouding production outlook).

Others seem to agree though. Raymond James estimates that the EIA is overstating DUCs by 2,000 wells.  Spears & Associates believe the EIA may be overestimating DUCs by 3,000.  In the last six months of 2019, completed wells exceeded drilled by 140 per month on average.  If Raymond James and Spears & Associates are right about the EIA’s overstatement, then we’re already out of true DUC inventory.

The EIA is forecasting 13.3 Million Barrels per Day (MMB/D) of U.S. crude oil production this year, up from 12.2 MMB/D.  The falling DUCs and possible overcounting create downside risk to this forecast, and upside potential for oil prices.

Pipelines Slowly Returning Cash

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2020 should be the year in which pipeline companies deliver on the promised increase in Free Cash Flow (FCF). The Coming Pipeline Cash Gusher remains the strongest bull case for midstream energy infrastructure. We’ll be updating these projections once companies provide updated 2020 guidance on spending in the next few weeks.

A trend towards returning more cash to investors is taking hold though. EnLink (ENLC) announced their much-anticipated distribution cut along with higher projected FCF (see EnLink Aims for Positive Free Cash Flow). Unusually, the stock firmed up following the announcement, showing that investors are looking past dividend yield as a source of valuation.

Yesterday morning Magellan Midstream Partners (MMP) announced a $750MM stock buyback along with the sale of three marine terminals to Buckeye Partners (BPL) for $250MM. MMP now joins Enterprise Products (EPD) and Kinder Morgan (KMI) in having a buyback program. These used to be extremely rare for MLPs. EPD and MMP are among the few that have operated reliably in recent years, with disciplined capital allocation and continuously increasing distributions. The U.S. pipeline business would be better if it was run by Canadians (see Canadian Pipelines Lead The Way). However, EPD and MMP are run as if they’re Canadian, which is about the highest praise one can offer nowadays.

Although growth projects are broadly commanding less cash flow than in the past, TC Energy (TRP) is likely to be a big exception this year. Last week they announced that work on the phenomenally delayed Keystone XL pipeline will resume next month, and a 1.2 mile segment crossing the U.S.-Canada border is scheduled for April.

Canada badly needs additional pipeline capacity to move its crude oil to market (see Canada’s Failing Energy Strategy). It has been delayed more than a decade, much of it under the Obama administration. The 830,000 barrels per day of added capacity will provide a welcome lift to prices for oil producers in Alberta. We currently estimate TRP will invest over $4BN on this and other expansion projects this year in addition to over $1BN on recoverable maintenance expenditures (mostly pipeline integrity). Along with Enbridge (ENB) and Energy Transfer (ET) these three will likely be the biggest spenders once 2020 capex guidance is revised.

KMI will kick off pipeline earnings later today.

We are invested in ENB, ENLC, EPD, ET, MMP and KMI

EnLink Aims for Positive Free Cash Flow

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It’s a sign of the market’s evolving view of pipeline stocks that EnLink Midstream’s (ENLC) distribution cut was followed by a modest bounce in the stock. A cut had been widely expected, and during the conference call with analysts some questioned whether the 34% reduction was big enough.  MLP investors are no longer solely focused on distribution yield as a measure of value.

ENLC is technically an LLC rather than a partnership. It has elected to be taxed as a corporation so as to broaden its investor base by issuing 1099s rather than K-1s. But its owner base remains dominated by MLP funds, perhaps because the weaker governance of an LLC dissuades many institutions who might otherwise consider the stock.

One unanswered question remains the influence of Global Infrastructure Partners (GIP) in setting strategy. GIP has taken a beating since investing $3.125BN in July 2018 (see Leverage Wipes Out Investor’s Bet on Enlink). GIP took on $1BN in debt and the subsequent collapse in ENLC’s stock has virtually wiped out the equity. The deteriorating fundamentals of Enlink’s business since GIP’s investment highlight that private equity often brings little to the table besides cash (and additional leverage). Uncertainty about GIP’s intentions remains a negative, and ENLC has offered little information. CEO Barry Davis simply said they exchange information with GIP on what each is seeing in the marketplace, which means either he doesn’t know much useful about GIP’s plans or what he does know isn’t positive. Preserving enough cashflow to GIP from the reduced dividend to service their debt was regarded by most as a factor.

Investors were mildly cheered by the discussion of Free Cash Flow (FCF) and the fact that it’ll be positive in 2020. Midstream energy infrastructure stocks have been rewarded for generating FCF. We estimate that almost half the industry’s 2019 FCF came from two big Canadian companies, TC Energy (TRP) and Enbridge (ENB). Both were star performers last year, returning 58% and 39% respectively including dividends. In The Coming Pipeline Cash Gusher last year we highlighted the industry’s growing FCF. Following 4Q earnings in the next few weeks we’ll update those projections, but they’re likely to be largely on track.

Even after the cut, ENLC now yields 13%, roughly 2X the yield on the American Energy Independence Index. This new dividend is presumably secure, not least because it must align with GIP’s debt servicing needs. Questions remain about long term performance in its assets located in Oklahoma and North Texas. Devon Energy (DVN), once ENLC’s owner and significant customer, triggered the weaker performance by divesting from plays in those regions. ENLC is still struggling to convince investors that their long term future is secure, and as with many pipeline companies the Permian in west Texas looks more attractive.

More clarity around GIP would be helpful. ENLC isn’t the traditional toll model with secure volume-backed contracts extending out many years. Customer drilling activity remains a critical factor in driving their performance. But for now they seem to be operating from the front foot. The dividend is also fully classified as a non-taxed return of capital, an appealing feature for those taxable investors who care about such things. It’s likely to remain that way for at least another three years due to a depreciation shield offsetting taxable income. RW Baird estimates 2021 FCF of $115MM, which on its current market cap of $2.85BN is a 4% FCF yield. However, that’s after the 13% distribution, so represents a high total FCF yield to equity holders. FCF is a recent discovery for many energy companies, and the fact that ENLC can show some ought to provide some support for the stock.

We are invested in ENB, ENLC and TRP

Clean Fossil Fuels May Be Coming

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Tokyo enjoys on average 1,800 sunny hours a year, less than half of sun-drenched Arizona. It’s also subject to extreme weather, such as typhoons. Arizona may be a candidate for solar power, but if Japan’s capital relied on the sun for its electricity, it would require battery back-up to provide the 25 Gigawatts (GW) its residents use for each day that bad weather, including typhoons, blocked its power source.

That’s 600 GWh per 24 hours. By 2021, Southern California Edison is planning a single system capable of running 100 MW for four hours. Tokyo would need 1,500 of them for 24 hours of back-up, sitting mostly idle until called into action by an extreme weather event.

This thought experiment is used in an interview with Bill Gates, where he illustrates the challenges facing renewables in meeting the world’s energy needs. Elon Musk is planning bigger batteries, but the economics of storing vast amounts of power to compensate for cloudy days remains daunting.

This is why combating climate change requires innovation on so many fronts. Given the enormous fixed investment and substantial R&D budgets of today’s biggest energy companies, developing technologies to use fossil fuels more cleanly remains a more likely solution.

NET Power has developed a natural gas power plant that produces electricity with no CO2 emissions. Conventional single-cycle power plants burn natural gas (or coal) to heat water which acts on a turbine to generate electricity. This produces CO2, and in the case of coal plants other noxious gases and polluting particles. Combined cycle power plants use some of the produced CO2 to power a second turbine, improving efficiency but still ultimately emitting Greenhouse Gases (GHGs).

The Allam Cycle burns methane (natural gas) with pure oxygen extracted from the air (which is roughly 80% nitrogen and 20% oxygen). The result is water, and supercritical CO2 (sCO2) which is used to power the turbine. Most of the sCO2 is then recycled in a closed system to provide further power. There are no emissions, and the CO2 is eventually captured for resale or to be permanently sequestered underground.

Its backers, who include Exelon, Occidental Petroleum and venture capital firm 8 Rivers, aim to show that the technology is commercially viable. Publicly, developments have been slow. An experimental power plant is operating in La Porte, Texas. For now its power output is only being used internally while testing continues; it’s not yet reliable enough to connect to the Texas grid, run by ERCOT. NET Power expects the technology to be deployed commercially by 2022.

In testimony before the Senate Committee on Energy and Natural Resources last year, 8 Rivers principal Adam Goff noted the business potential in China and India, where local pollution is as big a concern as GHG emissions.

NET Power has been around for some time. Goff said 8 Rivers began developing the Allam Cycle in 2009. Progress has been methodical, or ponderous, depending on your perspective. Based on public comments from Goff and others, within the next year or two we should see tangible signs confirming that NET Power has a commercially viable product.

The electricity produced is expected to be cheap, partly because of the rebate from selling CO2. Occidental, one of NET Power’s investors, pumps 50 million tons of CO2 into the ground annually to boost oil production. Although the CO2 is permanently out of the atmosphere, climate extremists are unlikely to be impressed. And it’s unclear that there’s demand for the amount of CO2 that such plants would produce if the technology was widely adopted.

The Allam Cycle is not limited to natural gas. Petroleum-based products and even coal can be combined with pure oxygen to generate electricity, although the focus has been on developing the natural gas capability. Capturing the CO2 from conventional power plants is expensive because it has to be separated out from the air as it’s emitted. NET Power’s approach captures the CO2 while it’s still in a relatively pure form, which is much cheaper.

80% of the world’s primary energy comes from fossil fuels. Although only around 20% of global energy use is for electricity, that’s still substantial and initiatives to combat climate change generally contemplate increased electrification of transportation. Electric vehicles charged by hooking up to a predominantly solar and wind grid remain the dream of many. But when you consider how well fossil fuels work, and the enormous capital invested in their continued dominance, privately-owned NET Power looks like a venture that much of the energy sector is cheering on from the sidelines.

If its backers are right, they’ll earn an enormous return as well as ensuring continued demand growth for natural gas. If emission-free power from fossil fuels becomes a reality, depending on sunny and windy days supported by a huge battery back-up will seem rather quaint.

Energy Strengthens U.S. Foreign Policy

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“Let us set as our national goal, in the spirit of Apollo, with the determination of the Manhattan Project, that by the end of this decade we will have developed the potential to meet our own energy needs without depending on any foreign energy sources.”

Over 47 years ago, President Nixon set out this vision. Securing oil supplies from a region of the world that often seems hostile to the U.S. has driven foreign policy ever since.

Four years later, President Carter warned in a speech to the nation that, “We can’t substantially increase our domestic production, so we would need to import twice as much oil as we do now. Supplies will be uncertain. The cost will keep going up. Six years ago, we paid $3.7 billion for imported oil. Last year we spent $37 billion — nearly ten times as much — and this year we may spend over $45 billion.”

Last week, following Iran’s deliberate miss of U.S. forces in Iraq, President Trump said, “…our economy is stronger than ever before and America has achieved energy independence (emphasis added). These historic accomplishments changed our strategic priorities…We are now the number-one producer of oil and natural gas anywhere in the world. We are independent, and we do not need Middle East oil.”

In November, the U.S. was a net exporter of crude oil and petroleum products for the first time in decades, a development made possible by the Shale Revolution. Increased freedom of action is one of the many benefits, as Iran is finding out.

Some have noted that the figures don’t show that the U.S. is a net oil exporter, which is true (see America Is Not Yet A Net Crude Oil Exporter). Domestic production is currently 12.9 Million Barrels per Day (MMB/D), and consumption of refined products is around 20 MMB/D. The difference is made up by 5 MMB/D of Natural Gas Liquids (NGLs), of which 3 MMB/D is consumed domestically, much of it as inputs into the petrochemical industry; 1.0 MMB/D of ethanol; and 1.1 MMB/D of net refinery processing gains. Net imports of crude oil make up the difference.

Crude oil comes in hundreds of grades, and it’s often reported that U.S. refineries are better equipped to process the heavy crude that Venezuela and Canada produce, with limited capacity to handle the light crudes that come from the Permian in west Texas. So we trade with other countries to achieve the desired mix of blends.

Imports from Venezuela have collapsed to almost zero from 1.2 MMB/D a decade ago. Imports from the Middle East have fallen to 0.7 MMB/D, so it wouldn’t be hard to get by with no Middle East imports at all. Meanwhile, Canada’s continue to grow.

From an energy independence perspective, Canada’s oil imports are hardly at risk. Its oil is produced in Alberta and runs south through pipelines to refineries in the Midwest, and even all the way to the U.S. Gulf coast. Two thirds of Canadian production is the heavy blends suited to U.S. refineries, and we buy 80% of their production. Canada has little choice other than exporting to the U.S. Domestic politics has prevented the construction of additional pipeline capacity from Alberta to Pacific coast ports in British Columbia (see Canada’s Failing Energy Strategy).

So even though there’s two-way trade in crude oil to achieve the blends needed for U.S. refineries, our imports are increasingly coming from friendlier countries.

The net result is that the U.S. is not only net independent in crude based products, but our imports of the blends of crude we prefer are coming from friendly countries. It’s a truly incredible outcome, and midstream energy infrastructure is vital to this success.

For a list of the most important companies in this sector, look at the American Energy Independence Index.

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