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Permalink Reply by Skip Peel - Mineral Consultant on January 16, 2024 at 3:41

RBN Emergy deep dive analysis of the CHK/SWN merger.

Finally - After a Long Courtship, Gas-Focused Chesapeake and Southwestern Put a Ring On It

Friday, 01/12/2024Published by: Tom Biracree  rbnenergy.com

Excerpt.  Link to full article: https://rbnenergy.com/finally-after-a-long-courtship-gas-focused-ch...

In a deal the energy industry had been whispering about for months, Chesapeake Energy and Southwestern Energy will combine to form what will be the largest natural gas producer in the U.S., with 7.3 Bcf/d of production in the Marcellus/Utica and the Haynesville and ready access to the Northeast and the LNG export market — assuming the merger passes muster with federal regulators. In today’s RBN blog, we discuss the merger and why it makes sense for both E&Ps. 

The surging upstream M&A market, which accelerated to an all-time record pace over the past six months, has stunned a lot of industry observers. The more than $200 billion in transactions over the past year and two weeks has included some surprising deals (Chevron acquiring Hess) and some competitive bidding wars (Occidental Petroleum winning CrownRock). But the latest deal — the longest-rumored and perhaps the most logical of all (think peanut butter and jelly) — is the merger of Chesapeake and Southwestern, the two largest Haynesville producers and major Appalachia operators. In today’s blog, we analyze this $11.5 billion marriage. 

According to Enverus, the total value of U.S. upstream M&A in 2023 was $192 billion — 79% higher than the previous all-time record (in 2014) and more than the previous three years combined. And the torrid pace, accelerated by Q4 purchases by ExxonMobil ($59.5 billion for Pioneer Natural Resources), Chevron ($53 billion for Hess), and Occidental ($12 billion for CrownRock), has continued into 2024. Last week, APA Corp. announced a deal to acquire Permian producer Callon Petro... for $4.5 billion, just days before Chesapeake and Southwestern announced their combination.

First, let’s outline the basics of the deal:

• Chesapeake is acquiring Southwestern for $7.4 billion in stock, or $6.69/share based on Chesapeake’s closing price on January 10, 2024. The total transaction value is $11.5 billion, including the assumption of $4.1 billion in Southwestern debt. 
• Chesapeake shareholders will own 60% of the combined company and Southwestern shareholders will own 40%.
• The pro forma company will hold 1.18 million net acres in Appalachia and 650,000 net acres in the Haynesville Shale and over 15 Tcfe of proved developed producing reserves. Production of 7.3 Bcf/d (as of Q3 2023) will make it the largest U.S. gas producer and one of the largest gas producers globally.
• The combined company — which will have a new name to be announced later — will have 5,000 gross locations across the two plays with more than 15 years of inventory to feed growing domestic and international gas demand.

We’ll take a more detailed look at Chesapeake and Southwestern’s production assets — and the markets they sell their gas into — in a moment. But first we’ll look at their long and interesting backstories — each struggled mightily in the past but hung on, rebounded, and found the other.

Chesapeake, established in 1989 by flamboyant dealmakers Aubrey McClendon and Tom Ward, spent tens of billions accumulating mostly gas-focused acreage in multiple U.S. resource plays. Punished by falling natural gas prices as Shale Era production took off, the E&P sold $12 billion in assets in 2014-18 to shift its focus to crude oil, but falling commodity prices in late 2019 and the onset of the pandemic made it a penny stock that toppled into bankruptcy. 

After shedding $7.7 billion in long-term debt and over half its midstream commitments, Chesapeake emerged from Chapter 11 in February 2021 with a new, laser-like focus on natural gas, targeting 85% of its 2021 investment to major gas positions in Appalachia and the Haynesville. Six months later, it announced the $2.17 billion acquisition of Vine Energy, which made it the largest producer in the Haynesville at the time. It followed in January 2022 with the $2.6 billion purchase of northeastern Pennsylvania producer Chief E&D Holdings — a deal that boosted its production in the dry-gas Marcellus by 75%. As it increased its gas holdings, Chesapeake shed its Powder River Basin assets to Continental Resources for $450 million and its Eagle Ford holdings in two $1.4 billion sales to WildFire Energy and INEOS Energy in the first two months of 2023, followed by a $700 million divestment to SilverBow Resources in August 2023.

The asset sales and lean capital investment left the recently bankrupt Chesapeake with a rock-solid balance sheet highlighted by a low 11% net-debt-to-capital ratio and $2.6 billion in available liquidity at the end of Q3 2023. The E&P also increased its base dividend from $1.75/share to $2.30/share since its emergence from Chapter 11 and augmented that with share repurchases and variable dividends that raised total shareholder returns over the past seven quarters to over $3 billion. However, cash flows have been pressured by low gas prices. In response, Chesapeake scaled back its activity in 2023, most recently guiding to flat production in Appalachia and about a 2.5% dip in the Haynesville in Q4. Unable to drill its way to higher cash flows, the company began exploring growth through a transaction that would lower costs, be accretive to major metrics, and provide benefits of scale.

Southwestern, which had also evolved into an Appalachian and Haynesville producer, was the logical and long-rumored partner. Formed in the 1940s as an Arkansas gas utility, Southwestern became the fourth-largest U.S. gas producer in 2013 after assembling a dominant  position in that state’s then-hot Fayetteville Shale. In October 2014, just as oil and gas prices began to plunge, it expanded into the Marcellus/Utica through a $5.4 billion purchase from Chesapeake, which at the time was transitioning to an oil focus. The ill-timed purchase brought Southwestern to the brink of bankruptcy in 2016 and it struggled to survive until it managed to sell its Fayetteville assets to Flywheel Energy for $1.9 billion in late 2018. The company managed to grow Marcellus production to 3 Bcf/d through low-cost organic growth and an opportunistic all-stock $874 million post-pandemic combination with Montage Resources.

Now stabilized, Southwestern made a dramatic move into the Haynesville in June 2021 with the $2.7 billion purchase of Indigo Natural Resources, the fourth-largest privately held E&P in the U.S., adding 1.1 Bcf/d of production and raising proved reserves by 26%. After Chesapeake countered with the acquisition of Vine Energy in August of that year, Southwestern announced the $1.85 billion purchase of private GEP Haynesville in November 2021, boosting production in the play by another 700 MMcf/d to 1.8 Bcf/d and snatching the title of top Haynesville producer back from Chesapeake.

The acquisitions came at a cost, though, in that they raised Southwestern’s net debt to over $4.5 billion.  Since then, the E&P has been forced to prioritize debt reduction and forgo instituting the robust shareholder-return programs implemented by most of its competitors. Like Chesapeake, low gas realizations eliminated the opportunity to boost cash flows through drilling and its leverage ruled out acquisitions. The matching strategic focuses and overlapping portfolios almost inevitably drove this merger.

As shown in Figure 1 above, the 2023 operating and financial results of the two companies through Q3 are remarkably similar — everything from revenue to lifting costs, DD&A (depreciation, depletion and amortization), pre-tax income and cash flow was only marginally different. And many if not all of these metrics stand to improve when the E&Ps merge. Chesapeake said the combination will result in an estimated $400 million per year in capital and operating efficiencies: $200 million for corporate and regional costs that will boost pre-tax income, $130 million in drilling-and-completion savings that will lower DD&A for reserve additions and boost cash flow, and $70 million in other operating and capital savings that will cut into lifting costs.

For two companies that have reported $1.2 billion in profits in 2023, the resulting savings mean the transaction will be accretive to all financial metrics, including cash flow per share, free cash flow per share, and return on capital employed. Chesapeake expects this to drive a 20% increase in dividends over the next five years. Further cost savings from infrastructure optimization and drilling efficiencies are possible. And the increased scale of the company likely lowers the cost of capital.

The estimated 7.3 Bcf/d in gas output from the combined company would propel it past EQT Corp. (5.7 Bcf/d) to make it the #1 U.S. gas producer. The larger and more diversified asset base should boost the confidence of potential partners that the company has the ability to deliver on long-term supply agreements, especially for LNG export projects. The larger platform should also drive ESG synergies and spur technical innovation.

The transaction does triple Chesapeake’s net debt to about $6.1 billion, which increases its debt-to-capital ratio to 23%. However, that’s still below the 25% industry average and only one-quarter of the pro forma company’s debt matures before 2029. Chesapeake has committed to using its cash on hand — $700 million at the end of Q3 2023 — to repay debt and is targeting a total of $1.1 billion in debt reduction by year-end 2025. At current strip pricing, the company expects to lower its net-debt-to-EBITDAX ratio to 1.0x within a year of closing. Chesapeake maintains that the accretive metrics and enhanced scale accelerates its path to achieve an investment-grade rating.

The transaction price does not provide a premium for Southwestern shareholders, but they will receive Chesapeake’s current $2.30/share fixed dividend and benefit from variable dividends (based on 50% of free cash flow after the fixed dividend, when available) and opportunistic share repurchases.  Chesapeake estimates the company will pay $1.4 billion in annual dividends, the fifth-largest total among U.S. E&Ps. Investors are evidently positive about the benefits of the deal, as Chesapeake stock rose more than 3% the day of the deal’s announcement.

Now to the detailed look at the production assets. As shown by the yellow-shaded areas in Figure 2, Chesapeake’s laser-focus is on dry-gas production in the U.S.’s two premier dry-gas plays: the Marcellus in northeastern Pennsylvania (Q3 2023 production: ~1.73 Bcf/d) and the Haynesville in northwestern Louisiana (Q3 production: 1.57 Bcf/d). Southwestern (green-shaded areas) is active in both those dry-gas plays and also has extensive holdings in the “wet” Marcellus/Utica region, with most of its acreage there in northern West Virginia and eastern Ohio — the properties it bought from Chesapeake in 2014. In Q3, Southwestern produced ~2.85 Bcfe/d in Appalachia, including ~2.23 Bcf/d of natural gas, 89 Mb/d of NGLs and 14 Mb/d of crude oil (condensate); in the Haynesville, it produced ~1.77 Bcf/d of dry gas.

Taken together, Chesapeake and Southwestern produced a total of ~7.3 Bcf/d of natural gas in Q3 2023 — 3.96 Bcf/d (or 54%) in Appalachia and ~3.34 Bcf/d (or 46%) in the Haynesville. Figure 3 below shows where the gas goes. The rectangular call-out boxes identify the destination market (“Canada,” “Greater Appalachia,” etc.), the source of the gas (the bold-faced “APP” or “HV” for Appalachia or Haynesville), and the percentage share of the combined company’s gas production that currently goes to that market. The boxes’ outline colors match the color of the gas sales points within that market (colored dots). The gray arrows illustrate the directional flow.

Destinations for Pro Forma Company’s Natural Gas

As you can see, ~22% of the gas produced by the pro forma company goes to the Gulf Coast (GG) LNG Corridor (red-outlined boxes), with another ~33% going to other Gulf Coast markets (light-orange-outlined boxes), and ~3% going to the Southeast (dark-orange-outlined box). The remaining 42% of the combined company’s gas goes to markets up north, including 30% that stays within the Greater Appalachia region (light-blue-outlined box), 10% to Northeast/Citygate (dark-blue-outlined box), and 1% each to the Midwest and Canada (light-green- and dark-green-outlined boxes, respectively).

The combined company’s significant exposure to international gas markets was touted by Chesapeake and Southwestern in their January 11 presentation on the deal — they called the pro forma E&P “LNG-ready” and said they expect to benefit from rising LNG exports out of the Gulf Coast over the next several years. Just a couple of months ago, on October 31, Chesapeake’s energy marketing subsidiary and Vitol Inc. announced that they had entered into a Heads of Agreement (HOA) under which Chesapeake will supply up to 1 million metric tons of LNG per annum (MMtpa) to Vitol for 15 years (probably starting in 2028), with the purchase price to be indexed to the Japan Korea Marker, or JKM. Following the execution of the HOA, Chesapeake and Vitol will jointly select the most optimal U.S. liquefaction facility to handle the gas Chesapeake will produce,

We should also note that Chesapeake and Southwestern are both out front in advancing the market for “certified” or ”differentiated” natural gas — i.e., gas that is produced with minimal methane emissions (see Time Has Come Today). Chesapeake in 2022 was the first major producer to achieve MiQ certification for all of its gas production and has received the highest ratings. So has Southwestern, which works with Project Canary on ground-based continuous monitoring and on assessing all of its production wells in the Marcellus/Utica and the Haynesville.

Pending approval by regulators as well as the shareholders of both companies, the Chesapeake/Southwestern deal is expected to close in Q2 2024. The deal announcement didn’t include forward-looking capital investment projections. Chesapeake had announced a $1.6 billion 2024 capital budget, slightly lower than 2023 on the expectations that lower service costs would more than offset adding a sixth rig in the Haynesville in the second half of the year. Southwestern anticipated it would maintain 2023 investment levels with a range of $2 billion-$2.3 billion, with service-costs deflation balancing with increased activity to meet expected higher LNG demand in the second half of the year and into 2025. We expect updated guidance by the closing date.

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Permalink Reply by Jimmy Hamiter on January 17, 2024 at 1:57

Hi Steve.

I, too, get DeSoto royalties from Comstock. Curious, what production month did they pay you $2.65? My last check (Dec.) had the price at $2.27 for October production. Thx!  

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Permalink Reply by Steve P on January 18, 2024 at 6:26

well, now that you ask:  I own about 3 mineral acres in 22-12N-16W, and Comstock has maybe 10 wells in that section, some CV, some HA.  for reasons I can't fathom, some of those wells, in my Oct royalty payments, pay $1.91,  with others paying somewhere between 1.91 and  2.16.   I own more minerals in 2-11N-15W, and there are 5 newer wells drilled by Comstock in 26-12N-15W that include 35-12-15 and 2-11-15, and for those wells the volume, for each well, is split into 2 separate line items, one for a much smaller volume at $2.65 (maybe 20% of well production), and another line for a much larger volume paying 2.29 or 2.30.  

I'll leave it up to the experts on this blog to explain why the split.  I'm assuming that Comstock has some firm sales commitment to a customer at the higher price, and the balance is at a more market price

Before the newer wells were drilled, I just had the small interests in 22-12-16, and the monthly royalty would require several months to add up to $100 before they would issue me a check.  A check stub like that gives you an easy way to see how the price of NG is trending.

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Permalink Reply by Jimmy Hamiter on January 18, 2024 at 7:21

Who knows with all the industry's smoke and mirrors

In my October statement (Aug. production), for "Gross Quantity/Price" the price is 2.36 and for "Gross MMBTU/Price" it's 2.39. December statement (Oct. production): 2.25 and 2.27 respectively. That's on 1 HA well that crosses my 41 acres (032 12N 14W) and Comstock has field orders for 5 new wells but no drilling yet (if that ever happens).

Are you a Royalty Interest owner or is it Working Interest? 

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Permalink Reply by Skip Peel - Mineral Consultant on January 18, 2024 at 14:13

Guys, good luck attempting to figure out the price differentials.  Although gas from 12N-16W and 12N-14W are likely transported through the Carthage Hub, beyond that hub price there are far too many potential variables that are not publicly available.  Here's an example. 

At a DUG Haynesville convention some years ago, I was privy to a conversation about gathering and treating (G&T) post production costs that informed the price royalty owners saw on their revenue statements.  An Aethon rep told a small group of attendees in an off the record discussion that the company had a G&T cost of $0.20 per mcf  in a specific field while across a parish road wells operated by BPX has a G&T cost of $1.20.  Two separate G&T systems with two very different cost differentials.  The BPX G&T cost was locked in from a sale of the system, built by Petrohawk (HK) years before, that included provisions for minimum volume commitments and guaranteed profitability minimums. 

In the early years of the Haynesville play when original operators were rushing to drill all the acreage they had leased, those operators had to build out their own gathering systems because existing infrastructure was not sufficient for the tremendous volume and high pressures of Haynesville wells.  All of those early play systems were later sold to midstream companies.  In the case of the Petrohawk G&T system I mention, keep in mind that HK lost their main credit facility in 2008 when Lehman Brothers went bankrupt.  In order to stay in the game competing for leasehold, HK sold off their G&T systems for the most cash they could get.  HK got the cash but saddled their royalty owners with long term post production costs that were extremely unfavorable.  State courts didn't step in to protect the rights of mineral lessors and the ability to sign sale agreements with outrageous guarantees became the norm.  Other operators across the play did the same.  Unless you are privy to the details of those sales, it will be impossible to understand why G&T costs vary so wildly across systems that serve Haynesville wells.

These examples are limited to net gas prices and I've never been able to grasp the gross prices on the many revenue statements that I have had the opportunity to review outside of assumptions as to the hub where the gas is sold.  It's a black box and that's the way the industry likes it.  If we knew the carefully hidden details, I think there would be a lot of law suits.

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Permalink Reply by Steve P on January 19, 2024 at 9:53

royalty interest.,

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Permalink Reply by Jimmy Hamiter on January 22, 2024 at 7:50

So am I. Hmmm.

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