Back on May 4 I wrote a bullish piece on natural gas producer Southwestern Energy (NYSE:SWN), deriving a price target of just under $9 per share using a simple discounted cash flow model of SWN’s free cash flow generation potential over the next five years.

The stock closed at $4.61 on May 4 and is up more than 40% since that time; however, it’s still trading at a roughly 35% discount to the discounted cash flow (“DCF”) target I derived back in early May. Indeed, the updated cash flow analysis and DCF model I’ll present today points to a significantly higher target for the stock near $10 per share.

Further, on October 17 Reuters reported larger rival Chesapeake Energy (CHK) had approached SWN regarding a potential acquisition.

I believe such a combination makes strategic sense given the geographic proximity of SWN and CHK acreage in the Haynesville and Marcellus natural gas shale fields. As I’ll explain, if CHK does acquire SWN it’s likely to be an all-stock deal that offers both short-term and longer-term upside for SWN shareholders.

Let’s start with this:

Fooled by Seasonality: Gas Futures Pricing

As I’ll outline later on in this article, roughly 86% of SWN’s annual production is natural gas with around 12% from natural gas liquids (“NGLS”) like ethane, propane and butane and approximately 2% of production from crude oil.

So, clearly the single most important input into any DCF model for SWN is the price of natural gas. And while forecasting commodity prices – particularly notoriously volatile gas prices – is an exercise fraught with uncertainty and error, a DCF model for SWN is more stable than you might imagine.

Here’s a look at front-month natural gas futures prices so far this year:

As you can see, gas futures started 2023 at around $4/MMBtu and tumbled to close at $2.10/MMBtu when I penned the May 4 piece on SWN. Front-month gas futures then jumped to around $3.58/MMBtu at the end of October and have since fallen back to around $2.80/MMBtu.

Look at this chart and it seems natural gas has been on a rollercoaster, rallying more than 70% from May 4th to the October 31 peak and then slumping 22% from the end of October through settlement on Friday, December 1.

Gas is a notoriously volatile commodity, and front-month futures are sensitive to near-term expectations regarding weather conditions. The National Oceanic and Atmospheric Association (“NOAA”) issued its latest temperature forecast for the month of December 2023 at the end of November, showing higher-than-normal temperatures across much of the US this month:

Winter is the most important season of the year for US gas demand and a warmer-than-average start to the season implies lower demand, a smaller-than-normal seasonal decline in gas storage and all else equal, a decline in spot and front-month gas prices.

However, watching the day-to-day fluctuations in futures prices, or the latest weather report, represents a misleading guide regarding the fundamentals of the US natural gas market particularly as it relates to valuations of companies that produce and sell the commodity.

Here’s a more useful chart:

Futures contracts allow you to buy or sell gas for delivery every month of the year for several years into the future.

This chart shows natural gas futures prices for every month through December 2026 on three different dates: May 4, 2023 (blue), October 31, 2023 (orange) and 11/29/2023 (grey).

Back in early May, the front month futures for natural gas was the June 2023 contract and as I explained earlier, June 2023 futures traded at about $2.10/MMBtu. At the end of October, the front month contract was December 2023, which sold for $3.58/MMBtu as I outlined above.

However, the price of natural gas didn’t rise 70% plus from early May through the end of October; that rally is illusory, almost entirely a function of normal seasonality in the gas market.

Since US natural gas demand is generally highest in the winter months because of heating demand, contracts for winter gas delivery – December, January and February – tend to trade at higher prices than contracts for delivery in periods of lighter demand such as June.

That’s why all three curves on my chart are shaped like sine waves – the peak of those waves corresponds to contracts for winter delivery each year.

The real rally in gas from May 4 through October 31 was about 3.8% – not 70% – because the December 2023 gas futures sold for $3.45/MMBtu on May 4 rising to just $3.58 on October 31. Take a look at the blue and orange lines on my chart above – the futures curves on May 4 and October 31 – and you’ll see they’re virtually identical.

Since the end of October, the price of natural gas has fallen. At the end of October, the January 2024 gas futures traded at $3.813/MMBtu, and today, with the January contract now the most active contract on the board, gas sells for $2.80.

That’s a decline of about 27% in a month.

However, almost all the change in the gas futures curve since the late October peak is at the front end of the curve. The current curve is significantly lower than the May 4 and October 31 curves over the next nine to 12 months; however, starting next autumn and into the winter of 2024/25, all 3 curves realign.

Since a discounted cash flow model attempts to forecast cash flow generation potential for a company like SWN over a multi-year period, changes in commodity prices over the next 9 to 12 months will have little impact on the valuation target.

That’s particularly the case with SWN because, as I’ll illustrate in a few moments, the company has already hedged significant expected production volumes through 2024, locking in prices regardless of the short-term vagaries of winter weather and gas prices.

Of course, that’s not to say there’s no relationship between front-month gas futures and the short-term performance of SWN’s stock:

Value vs. Price

As the father of value investing, Benjamin Graham once said:

“In the short run, the market is a voting machine but in the long run, it is a weighing machine.”

In this case, when the front-month price of natural gas is weak and there are concerns about the level of gas in storage, that tends to catalyze a deterioration in sentiment towards all natural gas producers regardless of their underlying fundamentals.

You can see that effect in this chart:

The price of Southwestern and the front-month price of natural gas don’t move in lockstep, but there’s clearly some correlation. Periods of broad strength in gas prices (orange line) on this basis, such as from May 2021 through the summer of 2022, tend to correspond to strong returns for SWN shareholders.

The opposite is true. Note, in particular, the collapse in US front-month gas prices early this year to lows under $2/MMBtu prompted a sell-off in SWN to below $5 last spring.

This is the voting machine of investor psychology – when front-month gas prices are weak it does tend to weigh on the value of SWN shares.

This also presents an opportunity for longer-term investors with a contrarian streak to use periods of bearish sentiment towards gas – such as early in May when I penned my last bullish piece on SWN for Seeking Alpha – to acquire shares of high-quality producers at a discount.

Any logical estimate of the value of SWN shares has little relationship to the current price of natural gas futures for delivery in January 2024.

Clearly, SWN doesn’t produce and sell all its annual gas output in the month of January 2024 and, as I’ll outline in just a few moments, the company has already hedged much of its 2024 production at prices well above the current quote.

Around 97% of the discounted cash flow price target I derive for SWN in this article is based on expected cash flows for the company in 2025 and beyond, not Q3 2023 and 2024 output. And, as you can see in my chart of the futures curves above, futures prices for gas in the 2025-2027 period have changed very little in the seven months since I posted my initial piece on SWN.

One reason that’s the case is a major shift in the US natural gas market that’s underway starting in the second half of next year:

This table presents a list of all liquefied natural gas (LNG) export terminals currently approved and under various stages of construction onshore in the US. As you can see, the total peak capacity of these projects is 9.63 billion cubic feet of gas per day (bcf/day) with most of this growth expected between the second quarter of 2024 and the end of 2025.

All told, the Energy Information Administration sees US LNG export capacity more than doubling between the end of this year and the end of 2027 to 24.3 bcf/day. Most of these projects are located along the Gulf Coast in the states of Louisiana and Texas.

That’s a lot of gas. According to EIA dry gas production in 2022 was around 100 bcf/day; in order to continue serving domestic demand, support pipeline exports to Mexico, and growing LNG demand/exports, US production would need to rise significantly.

That’s a major reason why the futures curves for natural gas I showed you earlier have a clear upward slope with prices expected to average well above $4.00/MMbtu by 2026. That reflects the price level needed to incentive producers like SWN to increase their output enough to support growing exports and consumption.

So, let’s return to deriving a valuation for Southwestern starting with the short-term outlook:

A Look at Q3 2023

Let’s start with a look at SWN’s quarterly performance in Q3 2023, which they reported on November 2nd.

Here’s my quick model of their Q3 cash flows:

There are four main sections in this table.

The top section shows SWN’s Q3 2023 production broken down by commodity type. So, the company produced 368 billion cubic feet (BCF) of natural gas in Q3, about 8.23 million barrels of natural gas liquids (NGLS) like ethane and propane and 1.31 million barrels of crude oil.

Since SWN is primarily a gas producer, I’ve converted their production into billion of cubic feet equivalent (Bcfe) of natural gas production. The standard energy conversion is that one barrel of oil contains about 6 million British Thermal Units (BTUs) of energy, which is the same as 1,000 cubic feet of natural gas. So, the conversion factor is 6:1.

NGLs are considered liquids, so they’re converted using the same 6:1 factor.

I’m also using the industry standard “M,” a Roman numeral used to denote 1,000, and MM to mean 1,000 times 1,000 or 1 million.

So, 8.228 million barrels of NGLs is the same as about 49.4 bcf of natural gas (8.228 multiplied by 6) and 1.31 million bbl of oil equals 7.9 Bcfe of gas.

In total, SWN produced 425.2 Bcfe of natural gas equivalent production in Q3 with 86.5% of that production in the form of gas, 11.6% in the form of NGLs, and 1.8% in the form of crude oil.

The second section of this table represents the company’s costs.

The largest single cash cost for SWN is capital spending (CAPEX). That’s primarily the cost of drilling and completing new wells on their existing acreage. Since SWN owns shale acreage, completing a well involves fracturing wells and hooking them up to gathering systems (small diameter pipeline networks).

Also included in CAPEX is spending on infrastructure and some land/acreage acquisitions that companies like SWN undertake as a normal part of their business.

Lease Operating Expenses (LOE) are generally the cost of maintaining existing wells and related infrastructure, so they continue to produce at optimal levels. These would be wells the company drilled and completed in prior quarters.

In SWN’s case, the company also includes gathering, processing, and transportation costs, as part of LOE. SWN is a dual basin producer with production in the Marcellus Shale of Appalachia and the Haynesville Shale of Louisiana. Demand for natural gas locally in Appalachia is low and prices in the region are normally lower than the price of NYMEX gas futures, which are priced at the Henry Hub pipeline interchange on the Louisiana Gulf Coast.

So, rather than sell gas locally at depressed prices, Marcellus producers tend to contract for capacity on pipelines that can move the natural gas to markets where pricing is more favorable. That would include the Gulf Coast, where demand for gas from chemical plants, refiners, and industrial end-users is high and prices are more favorable. That can also include markets along the Eastern Seaboard like Florida, where demand for gas in power generation is higher.

Note that gas prices in the Northeast, relatively close to Appalachia in geographic terms, also tend to be elevated. However, New York and other states in the region have rejected several planned pipelines to move Marcellus gas to the region, including the Constitution Pipeline and Northeast Supply Enhancement Projects both cancelled in 2020.

As a result of the need to transport Marcellus gas relatively long distances to regions where there’s more gas demand, transportation costs for producers in this region tend to be higher than average.

The advantage of the Marcellus is that it’s the most prolific play in the US, accounting for an estimated 35.95 bcf/day of production in November 2023, and tends to have the lowest production costs of any gas shale field in the US.

In contrast, Southwestern’s other major production basin is the Haynesville Shale, located in Louisiana and parts of eastern Texas. Producers in the Haynesville, including Comstock Resources (CRK) I profiled on Seeking Alpha here, tend to face higher production costs. However, the offset is the field is located in Louisiana, a short distance from massive Gulf Coast industrial gas consumption.

Also, the Haynesville is located close to most US LNG export capacity along the Louisiana and Texas Gulf Coasts – realized pricing is much higher in this region than the Appalachia and transportation costs are lower.

General & Administrative (G&A) costs – basically overhead such as running their headquarters – as well as interest paid on debt are likely familiar to many investors and common across most industry groups.

Production & Property Taxes are not income taxes, but taxes paid to the State based on the value of oil and gas extracted from a well.

I’ve converted all these costs from raw dollars to dollars per thousand cubic feet equivalent (Mcfe) of gas production. That’s because if we total costs per Mcfe, we can derive an approximate commodity price realization that’s needed for the company to “break even” on a cash basis.

That figure can be found in the final section of my table where you’ll see a line labeled “Breakeven per Mcfe.” Simply put, in Q3 2023 I calculate SWN needed to sell its production at $2.46 per Mcfe or higher to cover all its basic costs, including capital spending, and generate free cash flow.

Notice that I’m using the term “Mcfe,” not just Mcf. That’s because while most of SWN’s production is natural gas, the company still derives 13 to 14 percent of its production from NGLs and oil, which trade at higher prices on an Mcfe basis than gas. So, this is a benefit that accrues to SWN.

And that brings us to the section titled “Realized Pricing Deck.” For Q3 2023, this is a known figure that’s reported in the Q3 2023 results. When forecasting future quarterly results, we’ll have to estimate commodity prices based on the current futures curve pricing for natural gas, oil and NGLs and we’ll need to factor in the value of hedges SWN carries on all these commodities. For Q3, however, I’ve simply listed the all-in realized prices for oil, NGLs and natural gas adjusted for any hedges related to Q3 production.

As you can see from the table when we convert all of these realized prices to a Mcfe equivalent and adjust by their relative share of total SWN output, the company’s realized value for every Mcfe in the quarter was about $2.43/Mcfe.

Thus, by my estimates, SWN lost between $0.02 and $0.03/ Mcfe in Q3 2023 ($0.232/Mcfe unrounded) on a cash basis, which works out to about $9.85 million in actual dollar terms. However, in Q3 2023 the company reported a positive free cash flow of $23 million dollars.

While that might seem like a large gap between my estimates and actual performance, it works out to just under $0.03 per share of SWN outstanding.

There are a few main reasons for the discrepancy. First, my estimate is based on the core business of producing and selling natural gas, oil and NGLs. In addition to that, SWN has a marketing business, where it buys gas from third-party producers, transports it to market and resells it, earning a spread on those sales. The marketing business chips in some ancillary cash flow every quarter.

Also, it appears that SWN factors some of the transportation costs it incurs into the realized prices of the commodities as reported in quarterly results as well as in the LOE cost line. So, this may result in some “double counting” of costs in my model.

I find that small discrepancy to be acceptable for two reasons. First, I care most about the profitability of their core production business rather than ancillary businesses like marketing. In addition, if my model is actually overestimating costs slightly that renders it a little more conservative in estimating future free cash flows and, ultimately, yields a slightly more conservative target price. I’d rather err on the side of underestimating than overestimating a price target for SWN.

So, let’s step forward one quarter and examine our model estimates for Q4 2023:

The Outlook for Q4 2023

Each quarter, SWN releases updated guidance for both the quarter ahead and the current year (in this case 2023).

SWN’s quarter-ahead estimates offer less detail on certain line items in my model, such as LOE and CAPEX than their full-year estimates. So, to create this table I used explicit Q4 2023 guidance if available and then inferred estimates for other cost line items based on their full-year guidance.

For example, the midpoint of management’s guidance for full-year 2023 CAPEX is $2.15 billion and on their Q3 2023 earnings statement they reported $1.714 billion in spending through the first nine months of the year. That implies an additional $436 million in Q4 2023.

If there’s neither explicit guidance for Q4 nor the potential to back out a Q4 number from full-year guidance, I simply used the Q3 figure. For example, SWN doesn’t guide to interest costs, so I am just using the $36 million ($0.09/mcfe) quarterly number presented in Q3, which is in line with what it has reported in other quarters this year.

So, here’s a look:

The bottom line here is that I’m modeling to about $132 million in Q4 2023 free cash flow from SWN. That consists of about $78.2 million from their underlying production business with an additional lift from SWN’s in-the-money natural gas hedges covering production in the quarter.

This estimate is very close to the Wall Street mean and median free cash flow estimate for Q4, so the model appears well-tuned. And, while the line items in this table are similar to Q3, I’d make a handful of observations.

First, overall Q4 production is projected to be lower than Q3, falling from 425.2 Bcfe to just 409.9 Bcfe. This is based on explicit guidance provided by SWN management, released as part of their Q3 results in early November. This is not a huge surprise given the projected drop in CAPEX from $454 million to just $436 million. All things equal, lower CAPEX means fewer wells drilled, completed and turned to sales.

However, because production is falling in Q4 that suggests management is spending less than maintenance CAPEX – this is the amount the company would need to spend to hold production roughly constant. Shale gas (and oil) wells have high initial decline rates, meaning production falls rapidly after the well is put into production and then levels off to create a long tail featuring a more gradual decline in output.

So, if a producer like SWN wishes to hold production constant, they’d need to drill just enough wells to offset the natural decline in production from their existing stock of older, maturing wells. To generate growth, they’d need to drill enough new wells to offset that base decline and then additional wells to push growth.

No one really knows what a particular company’s maintenance CAPEX is. And this figure changes over time due to changes in cost structure or the distribution of SWN’s wells between its two main operating areas, the Haynesville and Marcellus fields.

It’s logical that SWN would be willing to allow its production to fall right now since near-term gas prices are low and there’s no reason to ramp production into a weak market. Further, as production falls, the company’s hedge coverage actually rises because the same volume of hedges covers a larger portion of the projected output.

In the long term, however, I suspect SWN will want to hold production at least steady and, eventually, grow output to serve a growing base of US LNG exports into 2025. So, this needs to be factored into our CAPEX cost estimates for future years – annualizing the Q4 CAPEX level of $436 million would be unrealistic, because spending that low would result in declining output.

A second point to note is the composition of SWN output and the tilt in favor of oil and NGLs that are implied by Q4 guidance. This illustrates the flexibility of the company’s dual basin production model.

The Haynesville is a dry gas play, meaning that gas in this field has little liquids content – only a small volume of NGLs and oil. However, some of SWN’s acreage in the Marcellus Shale region is in the “wet gas” window; producing gas in this part of the field generates significant volumes of hydrocarbons like propane, butane, natural gasoline, and crude oil.

Given generally lower gas pricing through much of 2023, SWN has shifted some CAPEX in favor of drilling in the wet gas window of the Marcellus, resulting in a rise in its liquids production as a percentage of total output. Since oil and NGLs have more favorable pricing, that helped to boost the company’s realizations per Mcfe in the quarter.

To estimate realized commodity prices for Q4, I’ve used average NYMEX oil and natural gas prices so far this quarter and the price of December oil and gas futures as of late November.

The midpoint of management’s Q4 guidance calls for realized oil prices at a $12.50/bbl discount to NYMEX-traded futures and gas at a $0.64/Mcf discount to NYMEX. NGLs pricing is based on the midpoint of management’s Q4 guidance for a barrel of NGLs to sell for 26% of the value of NYMEX traded West Texas Intermediate oil futures.

The company has significant hedges in place for Q4 2023 production including 179 bcf of gas production hedged using fixed-price swaps at $3.28/MMBtu as well as oil and NGLs volumes. The company also uses options to provide pricing floors for significant quantities of oil, gas and NGLs production.

For natural gas, I’m factoring in a significant gain from hedges because the company’s hedge price of $3.28/Mcf is above the $2.98/MMBtu average price for NYMEX gas I’ve calculated for the model (by convention 1 mcf of natural gas equals 1 MMBtu of gas).

The hedges for both oil and NGLs appear to be struck very close to the average trading prices for NYMEX oil, propane, butane and ethane prices. So, I’m modeling that these oil and NGLs hedges are a wash for Q4.

2024 Cash Flow Potential

Let’s step forward to look at 2024 estimates:

This table presents the same basic model for SWN’s 2024 free cash flow.

For the most part, I’ve simply rolled forward the mid-point of management’s full-year 2023 guidance on CAPEX, costs, production and commodity realizations for 2024.

In 2023, CAPEX was front-end loaded with the company reporting capital spending of $665 million in Q1 2023, $595 million in Q2 and $454 in Q3 as I noted earlier. I also modeled Q4 2023 CAPEX of $436 million as explained earlier bringing full-year CAPEX to $2,150 million right in line with the company’s full-year guidance estimates.

This reflects the fact that commodity prices were high through 2022, so SWN was spending more to increase production and take advantage of attractive pricing. As commodity pricing came down into 2023, management began cutting spending to preserve cash and avoid significant outspending of its cash flows.

However, producers like SWN contract for drilling rigs and fracturing crews over a period of time and it’s not efficient to immediately drop rigs and crew to respond to short-term swings in commodity prices. Thus, as is typical, there was a gradual ramp-down in activity levels through 2023 with the company spending around 59% of its annual CAPEX budget in the first half of the year.

In addition, back on the company’s Q1 2023 conference call in late April, management talked about the high cost environment in late 2022 and early this year. Costs for all sorts of basic equipment and services, from leasing rigs to performing fracturing work, was elevated last year as producers ramped up their activity to benefit from higher commodity price.

At the time, management expected cost inflation to ease further through 2023 as producers cut their capital spending, resulting in a loss of pricing power for services and contract drilling providers.

Back in February 2023 when SWN produced its first guidance for full-year 2023, the mid-point of CAPEX guidance was $2.35 billion, a full $200 million more than the current guidance if $2.150 billion. Meanwhile, SWN foresaw a total 2023 production at 1,688 bcfe compared to the latest guidance for about 1,678 Bcfe.

At least in part, this reflects lower-than-expected drilling costs – the company has cut its CAPEX guidance by 8.5% but its production guidance is only down just over 0.5%.

SWN usually releases updated guidance for the year ahead when it reports fourth-quarter earnings, usually in late February. So, we’ll have a better idea of management’s expectations for 2024 in about three months’ time. In lieu of that, I believe $2,150 million in CAPEX – the guidance for 2023 – is a good starting point for next year. That’s because I’d expect 2024 CAPEX to be a mirror image of 2023 – the company is ending 2024 with CAPEX of just $436 million, an annualized run rate of $1.744 billion.

However, as I explained earlier, with CAPEX so low, production is falling. This makes sense with current low gas prices, but the futures curves I posted earlier show much more attractive gas pricing in the second half of 2024 and into early 2025 corresponding to the expected start-up of LNG export terminals on the US Gulf Coast.

Therefore, I believe it’s likely we’ll see SWN start the year in capital preservation mode, followed by a ramp later in the year and into early 2025 to take advantage of better commodity pricing.

To generate the commodity price deck in my model I’m simply using the calendar strip prices for NYMEX-traded oil and natural gas futures in 2024 and applying the mid-point of their 2023 guidance for price discounts to NYMEX – SWN sells oil at an $11.50/bbl discount to NYMEX and natural gas at a $0.625/mcf discount to NYMEX. I’m also assuming a mixed barrel of NGLs sells at 31% of the value of WTI crude oil, again in line with what management expects for this year.

All told, based on these inputs SWN would actually see negative free cash flow of around $83 million on their core E&P business next year. However, the company has significant hedges in place including 528 bcf of gas production hedges with swaps at $3.54/MMBtu, a significant premium to the current 2024 Calendar strip of $2.98/MMBtu using the futures prices for the January -December 2024 NYMEX gas futures reported by Bloomberg as of the close on December 1st.

Oil hedges are priced in line with the current calendar strip for oil, but SWN’s propane, butane and ethane hedges would be in-the-money at the current strip, adding in some $18 million in hedge proceeds through next year.

The end result of all this is $253 million in free cash flow. As you can see on my table that’s actually well below Wall Street consensus estimates for $400 million in free cash flow next year.

I suspect a large part of that discrepancy is based on the timing of my model calculation. Specifically, I used the closing prices for 2024 commodity futures as of December 1st, while most of the published Wall Street estimates on Bloomberg are dated prior to November 20th. If I re-run my model using the futures price curves from November 20th, the free cash flow estimate jumps to $423 million in 2024, right in the range of consensus.

Further, when creating a DCF model I model the remaining quarters of the current year and then switch to an annual free cash flow model. Generally, I believe modeling on a quarterly basis introduces unnecessary complications with no real gain in precision.

However, in this case I believe my annual model is conservative based on timing issues alone. After all, typically, SWN will layer in hedges to future production over time, so that means the company often has more hedges covering production over the next 1 to 2 quarters than 3 or four quarters in the future. At the same time, the 2024 futures curve I showed you earlier factors in depressed prices for gas to start next year followed by a significant recovery into year-end.

That means, SWN likely has less exposure to low gas prices in Q1/Q2 than my model implies and more upside exposure to higher expected gas prices later in the year.

Further, I am modeling 2024 total production of 1,675.4 bcfe of which 86.3% is natural gas and 13.7% is liquids. Meanwhile, SWN pivoted in favor of liquids into Q4 of this year (expected about 14% liquids), so I suspect the company will continue to prioritize liquids into the first half of 2024 since pricing is more favorable for oil and NGLs than gas into Q1 2024. Even a few tenths of a percent can make a significant difference by improving price realization in the first half of 2024.

One more point regards SWN’s dual basin exposure.

In the company’s Q3 2023 Investor Presentation, management intimated that it expects to sell gas from its Marcellus acreage at a $0.75 to $0.80/mcf discount to NYMEX-traded gas and its Haynesville acreage at a discount of just $0.30 to $0.40/mcf. This reflects the deep local price discounts for Appalachian gas and the higher transport costs for production from this region to more favorable markets.

Meanwhile, the company sells all of its production from the Haynesville into Gulf Coast markets and sees the region as key to serving contracts with new LNG export facilities in Louisiana and Texas.

So, my long-term assumption that SWN sells its gas at a $0.625/mcf discount to NYMEX is on the low side. The company has said it’s likely to pivot more spending to Haynesville as LNG export capacity ramps up. And since Haynesville gas historically receives far better pricing realizations, growth in the play should lower the company average discount for natural gas production.

With these points in mind, I bumped up my 2024 free cash flow estimate to $300 million, higher than my model but still well below the Wall Street consensus per Bloomberg.

Starting in 2025, I roll forward my 2024 cost and production estimates as well as my estimates for realized pricing relative to NYMEX. Trading volumes in distant future oil and gas contracts are low, so I tend to view the calendar strips for 20025 and beyond more as a rough guide than an exact point estimate.

So, let’s look at the SWN’s ability to generate free cash flow under 3 commodity price assumptions:

The first is roughly the current strip price for 2025 with natural gas prices at $3.90/MMBtu and crude oil at $75.bbl. Under those assumptions, SWN can generate around $1.275 billion in annual free cash flow.

The second set of assumptions is $80 oil and $4.20/MMBtu natural gas. As you can see, under those assumptions, SWN can generate more than $1.78 billion in annual free cash flow. Finally, a higher-for-longer commodity price assumption of $85/bbl oil and $4.50/MMBtu yields more than $2.3 billion in annual free cash flow.

For purposes of calculating a DCF target for SWN, I’ll assume the most conservative commodity price deck for 2025, implying a free cash flow of $1.275 billion in that year, followed by the central base case of $1.8 billion per year starting in 2026.

I continue to view these assumptions as leaning to the conservative side. After all, it’s unrealistic to assume flat production at the 2024 level and beyond, because should oil and gas prices rise to near $4.00 it’s likely SWN would pursue production growth in its Haynesville acreage. And, should that scenario unfold, my natural gas price realizations are too low – I’m assuming a flat $0.625 discount to NYMEX prices, which is too aggressive a price discount for Haynesville volumes.

Also, I profiled Comstock Resources (CRK) a pure-play Haynesville producer back in an April 26, 2023 article for Seeking Alpha “Comstock Resources: 2023 Will be Messy.” In it, I calculated that CRK needs $3.25/MMBtu or higher natural gas prices just to break even on its acreage.

If Haynesville production is going to grow to meet rising LNG export demand, smaller higher-cost producers like CRK will need prices to rise to a level high enough to generate meaningful free cash flow. So, I believe a long-term natural gas price estimate of around $1/MMBtu over that minimum breakeven should be regarded as a floor to incentive volume growth.

So, let’s plug these free cash flow estimates into a simple DCF model for SWN:

I’m using a discount factor of 10.5% to calculate the present value of future cash flows. I chose that rate because debt accounts for 37.6% of the company’s capital structure and equity the remaining 62.4%. The actual cost of debt is 6.4% annualized for SWN.

To calculate the cost of equity at 13.1%, I used a Bloomberg approximation based on the risk-free interest rate in the US, and the beta (volatility) of SWN’s stock relative to the S&P 500.

Note that the 10.5% weighted average cost of capital (WACC) is higher than the 9% discount rate I used back in early May. The main reason for this is the rising risk-free rate of interest in the US as well as an uptick in the volatility and beta of SWN shares in recent months.

All-in the net present value of SWN is $15.234 billion by my estimates, so subtracting the company’s $4.248 billion in net debt, I see the equity value at just under $11 billion or $9.97 per share.

That implies a 50% upside from the closing price on Friday, December 1st to my target price.

So, even though SWN has already rallied more than 40% from my first bullish piece on the stock in May, I still see it as an attractive buy at current prices.

An M&A Kicker

On October 17th Reuters reported larger rival Chesapeake Energy had approached SWN regarding a potential acquisition.

Of course, the energy industry has been the focus of significant merger and acquisitions (M&A) activity speculation in the wake of two megadeals in the past few months, Exxon Mobil’s (XOM) $68 billion deal to acquire Pioneer Natural Resources (PXD) and Chevron’s (CVX) proposed $59 billion deal to acquire Hess (HES).

I believe a CHK acquisition of SWN makes strategic sense.

First, this year Chesapeake disposed of its last remaining properties in the Eagle Ford Shale of Texas, making the company a pure play on the Marcellus in Appalachia and the Louisiana Haynesville shale. And Chesapeake not only operates in the same regions as SWN, but the two companies have significant overlapping acreage in east-central Louisiana and northeast Pennsylvania.

In fact, SWN is a relative newcomer to the Haynesville Shale field, entering the play via the acquisitions of privately-held Indigo Resources and GEP Haynesville back in late 2021. And Chesapeake Energy sold much of its Haynesville Shale acreage to Indigo Minerals, a predecessor company of Indigo Resources, in the first quarter of 2017. So, should CHK buy SWN, it will also be acquiring properties it sold some 7 years ago.

This is important for three main reasons.

First, producers tend to gain experience operating in a particular field partly through trial and error and experimentation with various well designs. So, if an acquirer buys acreage in an unfamiliar field, this can result in a learning curve as those assets are integrated via an acquisition.

In this case, CHK has years of experience in the Haynesville and Marcellus fields and direct experience with SWN’s acreage, which it owned prior to CHK’s bankruptcy restructuring in 2020.

Second, drilling long horizontal wells allows E&Ps to generate more natural gas production from a well at a lower cost per Mcfe produced. However, in order to drill wells with long lateral segments, you need to own larger blocks of contiguous acreage. There’s no way to know with absolute certainty, but given the proximity of SWN and CHK acreage, it’s likely a combined firm would have more long lateral drilling locations.

Third, economies of scale and cost synergies. Both SWN and CHK have significant infrastructure in the Haynesville and Marcellus Shale fields including gathering systems and firm capacity on regional pipelines. Chesapeake is also an equity partner and anchor shipper on the Momentum project, a pipeline that’s designed to move natural gas from the Haynesville to Gulf Coast LNG export hubs.

CHK announced on its last earnings call that it has signed long-term supply deals with energy trading firms Vitol and Gunvor to supply natural gas for LNG export linked to the Japan Korea Marker (JKM) price. Per Bloomberg, the JKM price for natural gas currently stands at $16.28/MMBtu compared to less than $3/MMBtu for Henry Hub.

By more fully utilizing pipelines like Momentum and other key infrastructure, it’s likely a combined CHK-SWN could realize significant cost savings over time.

The combined company could also likely save significant interest costs. SWN has a net debt of roughly $4.25 billion as I noted earlier. Chesapeake had a net debt of a little under $1.28 billion as of the end of Q3 2023 and received $700 million in proceeds related to its sale of assets in the Eagle Ford in November.

With a current market capitalization of $7.3 billion, SWN’s $4+ billion debt burden looks elevated. However, Chesapeake has a market cap of over $10.5 billion and will have only around $600 to $700 million in net debt following the Eagle Ford sales proceeds, so the combined company would have a much more reasonable debt load.

Perhaps most important of all, the largest independent natural gas producer in the US is EQT Corp. (EQT), a Marcellus producer that produced 491.5 bcf of natural gas alone in Q3 of 2023, compared to SWN at 352.5 Bcf and Chesapeake at 310.8 Bcf. Thus, a combined SWN/CHK would become a dominant producer in the two largest and most important gas-focused shale fields in the US. That would make the stock a “must own” for investors looking for exposure to US natural gas and LNG export optionality.

I caution readers that any CHK bid for SWN is likely to follow a pattern similar to the recently announced XOM-PXD and CVX-HES mergers. Both of the latter were structured as all-stock deals with relatively modest premiums for shareholders in the target company.

Rumors of the Pioneer-Exxon deal first hit the news on October 6th and the deal was formally announced on October 11th. Exxon offered Pioneer shareholders 2.3234 shares of XOM for every share of PXD owned as well as agreeing to assume PXD’s $5.618 billion debt load.

Per Bloomberg, the volume-weighted average trading price of XOM between September 5th and October 5th – one calendar month before the deal was first rumored – was $115.98. The same figure for PXD was $230.83.

So, based on these average prices, 2.3234 shares of XOM were worth about $269.47, about a 16.7% premium to the average trading price for PXD over the same one-month period.

The CVX deal for HES was announced on Monday, October 23rd with HES shareholders to receive 1.0250 shares of CVX for every share of HES owned. The volume-weighted average price for CVX from September 20th through October 20th was $166.00 and for HES it was $154.68 for an implied premium of approximately 10%.

These takeover premiums might seem rather meagre to investors used to acquisitions in other sectors. However, investors tend to take a dim view of acquisitions in the energy sector if they believe the buyer is overpaying for assets. So, both deals were structured to offer investors in the target companies some near-term upside followed by intermediate to long-term upside via ownership of the merged entity.

The volume-weighted average trading price of SWN stock in the month prior to the first rumors of a CHK-SWN deal reported by Reuters was just under $6.40. If we use the PXD premium as a guide that would imply a takeover offer for SWN in the $7.50 range.

I suspect CHK would need to offer more than $7.50 to induce SWN to accept a deal because, as I’ve illustrated in this article, SWN’s valuation on even conservative commodity assumptions is closer to $10. At the same time, I suspect CHK will seek to offer a price that does not dilute existing shareholders to such an extent it supports the view they’re overpaying.

Given that SWN stock jumped as high as $7.69 days after the Reuters story hit the wires, I would expect Chesapeake to offer a price closer to $8.00 to $8.50 per share of SWN. That’s a 15% to 20% premium to the volume-weighted trading price of SWN since the deal was first rumored.

And I strongly suspect CHK would seek an all-stock transaction, effectively allowing SWN shareholders to maintain their stake in SWN assets via a piece of the merged entity.

Risks and Conclusion

The two biggest risks to my bullish thesis are the same ones that I covered in my May 4th article on SWN: Commodity prices and SWN’s debt burden.

In this article, I’ve illustrated how SWN is able to generate positive free cash flow even when natural gas prices are low thanks to its low production costs and hedging policy. Given good hedge coverage, especially for natural gas, through 2024 I believe SWN is in a good position to generate positive free cash flow even with a 2024 calendar strip of just under $3/MMBtu.

However, the net present value of cash flows I’ve estimated for Q4 2023 and the full year 2024 is just over $417 million, less than 3% of my DCF valuation for the stock.

So, what really matters is commodity prices in 2025 and beyond. My view is that rising LNG exports will drive a rally in gas prices longer-term to over $4/MMBtu on average. If natural gas prices instead were to remain depressed – perhaps near current levels under $3/MMBtu – over the long haul, then my cash flow estimates would be far too high.

As I’ve explained, I believe my cash flow estimates are on the conservative side but a lower-for-longer natural gas price environment could upend this model.

Second, as I’ve detailed, SWN’s debt burden of $4.25 billion is elevated relative to its market capitalization. The company took on much of this debt to fund the purchase of its Haynesville acreage in 2021, which I believe was a savvy move given the growth potential in the region. Further, should SWN generate the level of free cash flow I’ve modeled over the next few years, the company should be in a position to pay down debt towards management’s target of $3 to $3.5 billion.

Further, this risk is mitigated by the fact that SWN has only one bond maturity for $390 million before 2028. However, in a lower for longer commodity price environment, the company might struggle to generate adequate free cash flow to reduce its debt burden over the intermediate term.

I believe these risks to be modest and my cash flow model has proved conservative in recent quarters, underestimating the company’s actual free cash flow in Q3 2023.

Based on my estimates, I derive a target valuation for SWN of just under $10 and I’d regard the recent dip in the stock under $7 as a good buying opportunity with the upside of 50% to my target price.

Investors should also consider using the inherent volatility of the natural gas market to their advantage. As I’ve illustrated, SWN shares tend to rally when front-month natural gas prices rise even though there’s limited fundamental impact on cash flows or valuations. Such rallies are an opportunity to book partial profits in the stock.

Much the same can be said for rallies to $8 or higher on takeover rumors; as I indicated, given premiums on the recent acquisitions of Pioneer Natural Resources and Hess, I believe CHK or another acquirer is unlikely to offer more than $8 to $8.50 as part of an all-stock acquisition of SWN.

Similarly, sell-offs on short-term weather concerns, such as we’re seeing in gas right now, offer an opportunity to buy at more attractive prices.