Archive for category: Midstream Energy Infrastructure

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.

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

“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.

Our twice-weekly blog saw a 30% increase in pageviews during 2019, along with a healthy jump in subscribers. It’s reposted across several other websites, and we believe it’s the most widely read blog on midstream energy infrastructure.

The interest level shown by readers, as well as questions asked by investors, both influence our choice of topics. Reviewing the past year’s stats provides a useful perspective on what pipeline investors are thinking about.

Our most read blog post of the year was When Will MLPs Recover? It was published on November 13^th. It didn’t catch the low, which came in early December, but the recent rally has lifted prices nicely above their mid-November level. Coming on the heels of a weak October, always-fragile sentiment plunged to utter resignation among some. MLPs lagged midstream energy infrastructure by a wide margin in 2019, with the Alerian MLP Index up 9% compared with the American Energy Independence Index which is up 23%. It’s a consequence of the narrow investor base for MLPs.

The Coming Pipeline Cash Gusher was #2, offering our most eloquent response to the question about sector recovery. Free Cash Flow (FCF) has not historically been a metric used by MLPs. Two of the best performers in 2019, TC Energy (TRP) and Enbridge (ENB), do generate healthy FCF. Their capital allocation reflects values inspired by Canadian Presbyterian parsimony. Their strong 2019 returns suggest that as other pipeline companies increase FCF, their stock prices will also rise. We’ll be updating this analysis following 4Q19 earnings when companies provide updated 2020 growth capex guidance.

American Energy Independence is Imminent was #3, celebrating the many positives for the U.S. that increased domestic energy production is bringing.

AMLP’s Tax Bondage was #4. This was originally published in January 2018, and is our most read blog over the past two years. Explaining the disastrous tax drag to investors in AMLP invariably draws gratitude from the newly informed.

Why Energy Transfer Can’t Get Respect came in at #5. Too few writers are willing to be critical of the sector they follow. Your investment team is heavily invested in many of the companies we cover. When they do things we disagree with, I am incensed. We sell out if we conclude there’s no hope of management making sound decisions and acting with integrity. But it’s foolish to ignore valuation, and position sizing needn’t be binary (i.e. invested or not invested), it can be scaled to reflect all the relevant factors. Publicly criticizing a CEO to several thousand readers can provide the same satisfaction as impulsively dumping the stock, and often makes for better investment returns.

Our biggest single day of pageviews came on October 9^th, driven by Energy Transfer’s Weak Governance Costs Them.

In addition to our blog, we do a weekly podcast which is about six months old. It is steadily gaining listeners. Like our blog, it covers the sector but also takes a political view on issues like climate change that have big implications for our business. A recent episode, The Coming Rally in MLPs, was our most popular podcast. A couple of my personal favorites are Celebrity Climate Change Shaming and Greta’s Grandstanding. The most vocal climate extremists are often those least capable of critical analysis. The climate change debate has too few pragmatists seeking practical solutions. The middle ground, where we sit, is wide open.

We also do a quarterly webinar and periodic videos. Stop Flaring is our most popular video.

Finally, Twitter is an under-utilized resource that surprisingly few financial advisors use. I follow energy journalists and publications, and generally limit my tweets to energy (although occasionally that self-restraint lapses). If you want to know which stories we’re following today, check out @SimonLack.

We enjoy the engagement and feedback on all the material we produce. American Energy Independence is a fantastic story for this great country. There’s a bright future ahead.

We are invested in Enbridge , Energy Transfer and TC Energy

Yesterday Blackstone (BX) surprised Tallgrass Equity (TGE) investors by sweetening their offer for the shares they don’t own to match the price they originally paid in March. It marks a victory for Limited Partners in TGE, which retained its partnership structure even though it’s taxed at a corporation so as to avoid issuing K-1s.

The sideletter that provided a floor on the price management received for their LP units was unfair, and caused us to criticize it in September (see Blackstone and Tallgrass Further Discredit the MLP Model) when BX announced their offer to acquire the remainder of the shares. Most sell-side analysts were embarrassingly silent in standing up for their investors, conflicted as they are by the desire to win banking mandates from the protagonists. RW Baird’s Ethan Bellamy is a standout exception, unafraid to raise awkward questions during earnings calls, which renders his research opinions more credible. Other sell-side analysts should take note.

TGE CEO David Dehaemers claimed not to understand (see Tallgrass Responds to Critics, Missing the Point) and with nobody else publicly taking his side, he brought forward his retirement. This ended a disappointing episode in an otherwise successful career.

Although the degree of sweetening from BX was a surprise, once they’d invested in TGE it always made sense for them to acquire the rest. Having a public equity position in a private equity portfolio adds unwelcome valuation realism. Private equity funds are reporting far better investment returns than public markets (see Private Equity, Private Valuations), even though they occasionally commit some howlers (see Leverage Wipes Out Investor’s Bet on Enlink). GIP’s 44% partial ownership of Enlink (ENLC) can hardly be their desired position – they’ll either buy the rest or exit, realizing a substantial loss. Information on GIP’s intentions has been sparse. PE investments rarely lose value as quickly as this one, and explaining it has been an unwelcome distraction for GIP’s overworked investor relations people.

TGE’s pending disappearance as a public company also represents another step in the shrinking universe available to Alerian’s MLP indices. TGE was a 4.7% weight in the Alerian MLP and Infrastructure Index (AMZI), followed by the tax-burdened ETF AMLP (see MLP Funds Made for Uncle Sam). TGE is far less than 4.7% of North American midstream energy infrastructure, as shown by its 2.4% weight in the American Energy Independence Index. Because AMZI is limited to partnerships, the TGE proceeds will have to be reallocated across a subset of the pipeline sector, further increasing AMLP’s concentration and rendering it even less representative (see AMLP’s Shrinking Investor Base).