Oil & Gas / Midstream Primer, Resources

Hi monkeys, recently got staffed on an O&G deal, mainly midstream, and I'm having a tough time understanding the industry because it's so dense and there is so much info to deal with. Struggling to understand things like:

  • Quantity: is 100 million barrels a day a lot? How much natural gas is a lot of natural gas? How does capacity work?

  • Types of Resources: are crude and brent the same thing? Why are they called hydrocarbons sometimes and other times oil? 

  • Classifications: Is natural gas "clean" or not clean? Why is natural gas used to power generation plants but then natural-gas powered plants not considered clean like wind/solar? What's the difference between natural gas for powering power plants versus natural gas for other uses?

I'm just really confused, especially cause the supply chain is so complex, there's a bunch of terminology but mainly because I have no understanding of what capacity is a lot of capacity or little capacity. I know 10MW is very little (depends on source, due to capacity factor/usage) compared to 2,000MW but how do I know what cubic meters is a lot versus little? Does it depend on WHERE?

Looking for primers/long resources that are thorough, I remember there being a Deutsche primer sent around that people said was very wholistic but it's super outdated, like almost a decade old. Really need something a lot more recent, at least post COVID. Open to any recs guys, thank you a lot in advance.

Comments (12)

Most Helpful
  • Associate 2 in IB - Gen
Sep 23, 2022 - 1:37pm
  • Yes, a million barrels a day is a lot and indicates a large takeaway capacity for a pipeline system. You would write that as 1 Mmboe/d or 1,000 Mboe/d (each "M" is a thousand). Energy Transfer's Permian crude pipeline system has roughly the same takeaway capacity. You can see the scale when you compare it to some of the larger independent Permian players. Diamondback's last quarter production (for example) was ~225 Mboe/d. They're a Permian pure-play company with a TEV approaching $30bn, meaning 1 Mmboe/d in takeaway capacity could in theory handle all production for multiple Diamonback sized companies. 
  • One thing people in oil and gas do a lot is compare things on an oil equivalent (or gas equivalent) basis. The conversion rate the industry uses is "six". Technically you can get more specific, but everyone in the industry will use six. Just use six. For example, 100 Mboe/d is equivalent to 600 Mmcfe/d. 1 Mmboe/d would convert into 6 Bcfe/d. Note that gas units have an extra "M" over similarly sizesd oil units. Generally, you would present the units in whatever commodity the asset produces the most. For example, the Permian is generally weighted towards crude oil whereas Appalachia might be 90% dry gas. If it's mostly oil+NGLs, use units in barrels. If it's mostly dry gas, use units in MCF.
  • Capacity is basically just the throughput the system can handle. Generally, more capacity means a more valuable asset BUT that's also contingent on there being production from the upstream side. The Ruby Pipeline is a good example of what can happen if the production isn't there. It's a 1.5 Bcfe/d interstate pipeline (so large) that was built to move gas from the Rockies to surrounding areas. Upstream fell off there (upstream operators have better, more profitable basins to deploy capital in) so the pipeline is operating well under its capacity, so it went bankrupt.
  • Companies can protect themselves from the production vs. capacity issue by contract. Minimum Volume Commitments (MVCs) basically dictate that companies either need to put a certain volume through the pipe (and pay the fee on it) or they owe the company the difference. There are also Firm Transportation (FT) agreements which are basically just operators pre-reserving space on a pipeline system. These are common with Appalachia operators (EQT, Antero, Range, CNX, SWN etc.) because they want to get their gas out to more profitable marketes. Note also that counterparty risk matters here - you can have all of the guarantees in the world but in a bankruptcy if the other side can't pay, they can't pay. During COVID companies had MVCs and FT agreements tossed out during bankruptcy because they were seen as too burdensome and would make the post-RX company non-viable. So the midstream companies got left holding the bag.
  • You didn't ask but probably worth taking a moment to classify the types of pipelines and subsectors in the midstream space. They're differentiated by commodity and purpose.
    •  Crude Oil, Natural Gas, Natural Gas Liquids are the primary ones. But there are also refined products pipelines (move products after they've been to the refinery) and water pipelines (fraccing is water intensive and West Texas isn't known for it...). 
    •  Gathering & Processing (G&P), Transportation, Storage. G&P is the system of pipelines that connect to wells and feed into the big interstate Transportation pipelines. If you look at a G&P system (or really, gathering system) on a map they tend to look like spiderwebs. This is the most vulnerable part of the midstream value chain - changes in upstream production can significantly impact their profitability, especially if their MVCs have rolled off. For that reason companies that are heavy G&P tend to trade lower. Note that the "processing" piece pertains to gas and involves splitting dry gas from NGLs. From G&P, the crude or gas flows into transportation pipelines. These are large interstate pipelines. Most of the time if you hear about midstream in the news it's because environmentalists are protesting one of these interstate mega-projects. These are good assets and transport massive volumes of gas and oil from producing regions to the rest of the country's population centers. Note also that because they cross state lines, transportation assets are FERC regulated. That means that they don't have full control over their rates, and are a bit like utilities in that respect. Storage is just what it sounds like - large tanks that store gas, crude, NGLs etc. You pay a fee and you can keep your product there. 
    • LNG should probably be mentioned as another part of the value chain. Transporting natural gas across an ocean is difficult - to viably transport it you need to basically chill it into a liquid, which lets you put it on ships and send to Europe or wherever else (where it is regassified and used). This is becoming more relevant today, but even in the current market the proejcts can be hard to get off the ground. The assets that DO already exist are massive and massively profitable. 
  • Brent references a market / grade of crude and is typically seen as the European marker for oil prices. The American equivalent is WTI. Those are the two markets that people will reference  90% of the time, but there are many other markets and grades all around the world. Hydrocarbons includes both natural gas and oil and anything else vaguely similar (including coal). It's a broad term. If you're digging it out of the ground and burning it for energy, it's probably a hydrocarbon. 
  • Natural gas is cleaner than coal but it still produces CO2. There are also issues with straight up methane (which is mostly what natural gas is) leaking out of pipes and storage tanks, and methane is a bigger problem than CO2. Natural gas can either be used as an input into combined-cycle gas power plants to create electricity, or it can be piped around and directly used for heating. The latter is falling out of favor and plenty of states are passing laws that make it harder to expand gas home heating. 
  • Mentioned this earlier but yes, "where" the capacity is is vitally important. It doesn't matter if you have a 10 Mmboe/d system if there isn't any oil flowing through it. The best systems today are offtake in the Permian  basin (oil), Haynesville (gas) and Appalachia (gas). There are other basins, but those are the three major ones that supply American energy today. 

I don't have any primers around that are updated but what i would recommend is that you read Hart Energy (best industry publication and well respected by both bankers and Corp Dev teams) and for midstream specifically, the research of Michael Blum. He's Wells Fargo's equity research analyst and is widely regarded as the best midstream research analyst. He publishes a weekly publication ("The Weekender") along with monthly publications ("Midstream Monthly") and various one-offs. Midstream teams in Houston typically send his research around along with the weekly group-wide comps spam. RBC Richardson Barr's website is also a useful and easy way to quickly judge company sizes and day to day performance for both Upstream and Midstream.

Happy to answer any follow-ups that you have. 

  • Intern in IB-M&A
Sep 23, 2022 - 7:42pm

Is the modeling for o&g midstream significantly different to modeling for upstream? I'm more familiar with upstream, having seen and been through some models myself, but not sure if midstream is more akin to a widget company or the traditional upstream model.

When I'm talking about upstream o&g modeling, think: production profile, oil well NAV, o&g discount rate, etc.

  • Associate 2 in IB - Gen
Sep 23, 2022 - 8:47pm

Definitely different but it depends. I've seen models on the G&P side where you're functionally aggregating a dozen upstream ARIES style NAV models (because that flows into the production profile of the midstream assets). But you can also end up with pretty straightforward models where the revenue build is just simplistically utilization x rate.  A decade ago they would have been even more different, when MLPs and financial engineering was more commonplace. You still see some companies with tax-advantaged MLP structures but not nearly as many as you did in years past (you're weighing tax advantages vs. governance issues with MLPs, and recently the scales have been tipped towards governance issues being too much of a headache to justify any tax benefit). 

I would say generally that midstream is much more bond-like than anything else in energy. Cash flows are much more predictable. This is why the sector tends to trade higher than the rest of energy (upstream, OFS). In terms of modeling yes it's different (unless it's a pure G&P asset, where you're just layering midstream fees on top of an upstream production model) but it's also not 1:1 similar to any generic CorpFin modeling that you might see in OFS.

Sep 26, 2022 - 8:27am
Greg Marmalard, what's your opinion? Comment below:

This is a really great answer but a point of clarification (nit-picking)

Yes 1 MMBbld is a lot but in midstream that's going to be a gross. E&Ps report what's called net royalty interest (NRI, explained below) so FANG's equivalent gross prod is more like 330-340 at a ~67% NRI (actually think it's lower but can't remember).

For those interested, gross production is the actual production out of the ground, that's what the midstream company is measuring because they contractually get all of it if they have a gathering agreement/dedicated acreage. The operator generally has a majority interest (called operated working interest if they are the ones drilling/operating the well) but it's very common for other parties to also have interests, these are called non-operated because they just get an invoice and have very little decision-making power/control over operations. So let's say there's the operator and one other company. The operator owns 90% of the working interest while the other party holds 10%. That means the operator pays 90% of capex, 90% of opex and the non-operated owner(s) pay their commensurate share. The catch is, they won't get 90% of the revenue. How is that? Royalty holders get their piece. Someone owns the surface and mineral (sub-surface) rights.  This can get very complicated but let's assume that it's a ranch in South Texas that's been around for a long time. The standard is a 25% royalty down there. So that means that the land owner that holds the mineral rights gets 25% of all the revenue that's generated by the well. And usually pays effectively nothing (some small production taxes) and why should they since it's their land that they're inviting someone to develop. So the actual revenue to the working interest holders (operated and non-op) is the working interest times their share of the royalty (for op here - 90% * 75%). That's the NRI. As a reminder, public US E&P companies report NRI production/revenue and working interest costs. 

Sep 23, 2022 - 2:42pm
Septimus, what's your opinion? Comment below:

RBC has a primer called "Energy Made Simple" that they used to publish updates for every now and then. You can find it on Eikon I believe.

There is obviously a Canadian slant to it, but more general content is probably something that would be useful if you haven't had any experience in the industry!

Hope this helps!

Sep 23, 2022 - 2:56pm
resistance23, what's your opinion? Comment below:

The answer above says more than enough so I'll just add this. Whether gas is considered clean or not is mostly up to the preference/stance of the person talking. For example on Shell's website and promotional materials you'll see them talking a lot about gas and how it's 50-90% cleaner than coal (this is a stat I saw on their materials, no idea how accurate), but for someone who is anti-oil, they will tell you that gas is the devil. So keep that in mind

Sep 26, 2022 - 8:44am
Greg Marmalard, what's your opinion? Comment below:

DB primer is still relevant. The process, geologist, etc hasn't changed - the country/company specific stuff has of course. If you want to learn about O&G extraction, it's still a great resource. TPH has a great primer from their research team but you'd need access to their portal

Sep 26, 2022 - 11:09am
Smoke Frog, what's your opinion? Comment below:

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