Description

To quote snarfy, because I couldn’t say it any better, “I would like to offer VIC members yet another way to lose money on northeast gas.” 

Background

Cabot began studying the Marcellus Shale in 2004 following positive industry results in southwestern Pennsylvania. The objective was to analyze the Marcellus trend across the Appalachian Basin to identify areas with the thickest Marcellus Shale section that also had access to existing pipeline. The Company’s analysis led them to Susquehanna County in northeastern Pennsylvania, where there had previously been only five wells drilled in the history of the county. Since Cabot was the first-mover in the area, acreage costs were low and so Cabot began leasing aggressively. Cabot commenced its leasing efforts in Susquehanna County in 2005 and by June 2006 the Company had drilled its first vertical Marcellus well to test the viability of the play. The result was the discovery of a thick, mature, structurally-enhanced reservoir that exceeded all expectations. Based on these findings, Cabot accelerated its leasing activities in the area and by the end of 2007 the Company had accumulated over 100,000 net acres in this emerging play. Cabot implemented a horizontal drilling program in late 2008 and based on the success of this program, the Company moved to an almost entirely horizontal program in 2010, by which time Cabot had leased its current position of approximately 174,000 net acres in the sweet spot of the play. With a core position established, the Company directed its focus to efficiently developing what would soon become the most prolific natural gas field in North America.

Investment Thesis

The current appalling price environment for natural gas has created an opportunity to invest in the definitive low-cost producer in North America at an extremely attractive valuation. While this may be uncomfortable in the short term, if you expect that your home will have electricity and running water in a few years’ time, then Cabot will almost certainly be producing free cash flow. Among gassy E&Ps, Cabot has the best rock, is the least levered, and has a CEO that owns $60 million worth of stock (more than the CEO’s of EQT, RRC, AR, CRK, and GPOR combined). Cabot has 35 years of drilling inventory and, unlike peers, is focused on per share return metrics with a commitment to returning at least 50% of free cash flow to shareholders in the form of dividends and buybacks. 

Natural Gas: The Current State of Affairs

We are in an abysmal pricing environment for natural gas caused by many factors including but not limited to: northeast E&P’s hell bent on growth for growth’s sake, exponential growth in associated gas from Permian operators, a resurgence of the Haynesville shale, broad increases in well productivity, and an unseasonably warm winter. While natural gas prices will forever be cyclical, over the medium to long term, prices must provide sustainable economic returns to drillers that extract the natural gas that we need to meet rising demand. And at today’s price of < $1.90 Mcf, almost no operators, even gross of interest expenses, can drill profitably unhedged. I’m not about to prognosticate the breakeven natural gas price needed to incent drilling, but here are a few data points to show how far away we are from that price today. Below, I’ve used Q3’19 data to annualize the cost structure of a handful of E&Ps, and used well by well production data in combination with D&C costs per well to estimate approximate breakeven cost by operator. Nearly all of the operators selected rank in the top 10 in terms of well productivity for gassy E&Ps (Rice + EQT = EQT / RRC is very wet gas), and unsurprisingly, Cabot tops the list with an average 24 month cumulative production per well of 7.5 Bcf for wells with a production start date in 2017. 

We are now witnessing in real time the effects of decade’s low pricing environment for natural gas. The U.S. natural gas rig count has fallen from a high of 198 in January 2019 to 112 in January of 2020 (~45% decline), the steepest decline since early 2016, which should again yield a reset in daily production. Furthermore, amongst Appalachian operators, the consensus exit to exit production growth is now only 0.8 Bcf/d, significantly improving gas macro for 2021. Longer term, it’s important to address the role of associated gas. Importantly, it seems evident that associated gas will not be able to offset the expected growth and base decline in dry gas. At present, U.S. oil wells produce approximately 25 Bcf/d in associated gas off a base of 12.8 MMbbl/d of oil production. In addition, 12 Bcf/d of this associated gas is coming from the Permian. Assuming a 3.25 Mcf/bbl ratio for the Permian and a 2 Mcf/bbl ratio for the rest of associated gas would yield ~45 Bcf/d of associated gas production by the time the U.S. can achieve net zero crude imports (~2024).

This increase in supply will slightly more than offset the increase in natural gas demand from LNG terminal capacity, which is projected to increase 15 Bcf/d between now and 2024. After which point, demand for crude is expected to level off, and eventually begin to decline into the 2030’s as demand for dry natural gas continues to increase. 

Meanwhile, the average U.S. decline rate of 26% equates to ~27 Bcf/d of new gas production required each year to simply hold production flat. So even if the growth picture is not as rosy as some gas bulls would have you believe, we are still going to need gassy E&Ps to supply at least 20-25 Bcf/d of new production over the coming 5 years, and likely even more than that beyond 2025.  

Stacked Pay Zones: Lower Marcellus & Upper Marcellus 

Cabot has 35 years of remaining drilling inventory, which is split between ~700 Lower Marcellus locations and 2,100 Upper Marcellus locations. Their acreage is positioned in the thickest producing Marcellus interval in the basin (300-450ft), and the upper and lower zone are separated by the Purcell Limestone (25-90ft) which serves as a legitimate frac barrier. The independence of these two resources has been thoroughly tested. To date, Cabot has drilled 40+ Upper Marcellus wells that have yielded strong results, supporting management’s belief that the Upper Marcellus is an incremental and accretive reservoir. Furthermore, Cabot is confident that both zones will deliver top-tier economics when compared to the vast majority, if not all, oil and gas resource plays across the US. For example, based on 30 wells drilled with older generation completion designs, Cabot’s Upper Marcellus position boasts EURs of 2.9 Bcf per 1,000 ft lateral, productivity that is superior to virtually all Appalachian and non-Appalachian gas plays.  More recently, a dozen or so Gen 5 wells have now been drilled in the Upper Marcellus and here is CEO Dan Dinges with some commentary that should give a sense for his confidence in the program: “Well, I'll make a couple of comments. First, I'll make a comment regarding our comfort level since we received a number of -- not a number, a couple of questions regarding our Upper Marcellus and how do you know it's distinctive. And I'm going to just give one example. We have a number of examples that we could give to you, but I'll give you one example that most people are not going to have any problems understanding how we have the conviction that we do. We laid 2 -- this -- recently, we laid 2 Upper Marcellus wells in an area that we had prior completions on our -- in our -- in the Lower Marcellus. And in this specific example I'll give you, we had 2 Lower Marcellus wells that had been producing for an extended period of time. We put 2 Upper Marcellus wells 400 feet, get that context, 400 feet from 2 Lower Marcellus wells that had produced a long time. And we completed those 2 Upper Marcellus wells that were 400 feet from these 2 Lower Marcellus wells. It just so happened to be the 2 Lower Marcellus wells that we chose to do this experiment on have each cum-ed over 20 Bcf. Okay, so we laid 2 Upper Marcellus wells, 400 feet from 2 wells that had cum-ed each 20 Bcf. Those Upper Marcellus wells came on normally as you might expect. The early time production from those Upper Marcellus wells have actually fit a curve. And again I'm going to caution the comment here on a curve fit with very little data, but those 2 Upper Marcellus wells came on fitting a curve of 3.3 Bcf per 1,000 and 3.7 Bcf per 1,000. I'm not saying that that's what we're going to go to. So don't take it, and I hope nobody comes and ask about what about the 3.3, 3.7 Bcf-type thousand EUR. That might be our poster child from this point forward. I'm just giving you an example of our confidence level. If there's any place we would have seen some issues, it would've been where we had produced over 40 Bcf, 400-something feet away from a couple of Upper Marcellus. So that's that soapbox commentary on that. What was the rest of your question?”  Cabot is currently focused on drilling out the Lower Marcellus locations, which they expect to remain the dominant part of the drilling program through 2027.  

Cabot: Operational Review 

I’ll keep this brief, because I think everyone is aware that COG is a low cost producer. Over the last 5 to 7 years, Cabot has made tremendous strides in optimizing their cost structure, which management believes they can further improve upon by 10% over the course of the next 3 years. 

Which in combination with phenomenal rock quality, has led to industry leading recycle ratios

And a production profile that produces $175 million in after tax free cash flow at $2.00 NYMEX pricing. 

Taking a look at well results by vintage, we can see that Cabot’s wells are generally getting better with time, and they are recently tracking ~5.2 Bcf of cumulative production in the first 12 months online. Importantly, this is substantially better than the average US gas well which only cum ~2.5 Bcf on the same measure. 

Additionally, for wells that began production in 2018, 60 of 85 of Cabot’s wells cum-ed over 4 Bcf in the first 12 months and 70 of 85 cum-ed over 3 Bcf in the first 12 months – highflying the consistency of drilling results. 

On the infrastructure front, 2018 was an inflection year for Cabot, as years of hard work led to an additional 1.5 Bcf/d of new takeaway (1 Bcf/d of pipeline, 0.5 Bcf/d of in-basin projects). Importantly, nearly all of this new supply is under long term agreements. This has set the stage for Cabot’s future production capacity to expand toward 4.0 Bcf/d, and has dramatically eased their differentials. 

Finally, over the last decade Cabot’s management team has sold nearly $2 billion worth of non-core assets to focus on developing their high-return acreage in Susquehanna County. At this point, they are truly a Marcellus Pure Play. This has allowed Cabot to delever while also returning a meaningful amount to shareholders in the form of dividends and buybacks. Most recently, Cabot sold their ownership stake in Meade Pipeline Co LLC for $256 million, which should allow Cabot to repurchase another 10-15m shares back at depressed prices. 

Cabot is down ~50%, everyone else is down ~90% … why not own the others? 

If natural gas returns to $3.00 Mcf and stays there for any meaningful duration of time, you are almost certainly going to do better by owning RRC, GPOR, and CRK. However, at $2.50-$2.75 natural gas (assuming current production levels), many of these businesses are still too levered for me to be comfortable with. This becomes a particular problem when you factor in the finite life of the resource. Commodities are tough, and for many of these companies there are simply too many variables that I would need to get comfortable with to assure myself that bankruptcy is not on the table.

Valuation

Bear Case Assumptions:

- Natural gas stays below $2.30 Mcf through 2023

- Cabot cost structure remains unchanged, and differentials ease slightly

- 4.0 Bcf cum / 12 month type well curve and $8.5 million per well cost

- Production held flat and exit multiple of 10x after tax free cash flow

- Output = $11.71 NPV (19% downside)

Base Case Assumptions:

- Natural gas trends up to $2.70 Mcf by 2023

- Cabot cost structure and differentials remain unchanged

- 4.0 Bcf cum / 12 month type well curve and $8.5 million per well cost

- Production growth of 5.5% per annum and exit multiple of 14x after tax free cash flow

- Output = $30.83 NPV (112% upside)

Bull Case Assumptions:

- Natural gas trends up to $3.00 Mcf through 2023

- Cabot cost structure improved slightly, differentials remain unchanged

-  4.0 Bcf cum / 12 month type well curve and $8.5 million per well cost

- Production growth of 8.2% per annum and exit multiple of 16x after tax free cash flow

- Output = $56.03 NPV (300% upside) 

Risks

- Renewable like Wind and Solar and a well understood risks. However, at present, nuclear power generation is expected to decline through 2050. If depleted uranium power plants were able to get to proof of concept and gain political momentum, then this could be bad news for natural gas. I feel comfortable taking on this risk because the lead time for such a thing to happen would mean that the impacts would likely not be felt for at least a decade out. 

- Cabot is confident in the resource potential in the Upper Marcellus drilling locations. However, if these wells prove to be substantially worse than the 3.0 Bcf per 1,000 foot lateral that they have guided to, then that would make the years beyond 2027 less profitable.

- As the player at the low end of the commodity curve, Cabot benefits from having a somewhat steep break even cost curve to supply the incremental gas needed. Scale in this business matters, so if a perfect storm of consolidations take place that marginally flattens the curve -that would be bad news for Cabot. 

Catalyst

- rise in natural gas pricing

- continued share buybacks