Diversified Energy Share Discussion Threads

[11_percent] 09/5/2023 12:02

Taking it down......looks like they are running the stops under 90

[renewed1] 09/5/2023 09:12

All reads well to me!!

[oneillshaun] 09/5/2023 08:52

You would think with such a healthy ongoing divi the markets would be all over this.

[holts] 09/5/2023 08:34

Seemed a reasonable statement with some useful hedging , market underwhelmed .

[aleman] 09/5/2023 07:33

I wonder if the solar projects will be lease only or part equity. Anyway, more liquids and solar adds some diverisification to gas revenues.

[bluemango] 09/5/2023 07:28

Bullish statement. Dividend maintained.

[lab305] 09/5/2023 07:23

"We have built a sizable and resilient Company, and believe our intrinsic value per share significantly exceeds our current share price, ...."
They can say that again. Good set of numbers but will it have any effect ?

[ntl2] 07/5/2023 09:37

I am with HL. Service has deteriorated over the years. Went southwards during and post pandemic. Perhaps people are still working at home!!!!

[garycook] 06/5/2023 02:05

No Reply regarding DEC Dividend dated 24/04/2023
Can HL reply to this email please, Diversified Energy Company PLC Dividend Withholding Tax .Dear Sir/Madam I have been informed that the DEC dividend 30% withholding tax does not apply for a UK SIPP, and also the DEC holding is owned by HL being my Nominee. Can you explain why I am being deducted 30%, when it should be Nil in a UK Regulated Pension scheme. Me residing in the Philippines does not apply regarding the facts below. There is a bilateral tax treaty between tax jurisdictions. I have a UK tax residency, which clearly states on my Personal details and account settings as Residency tax status: Rest of UK rate taxpayer The country I happen to be sitting in is irrelevant. Physical location isn't even a question on the W8-BEN form. UK Tax resident and the dividend in a SIPP is recognized by UK Tax Authorities as a recognized pension scheme the withholding tax rate is zero. Regards Gary Cook Still no reply from this email to HL, from 24/04/2023, and repeated on 03/05/2023.Regarding the DEC dividend in my SIPP. Unusual for HL not to reply. I believe they do not want to answer, because my email incriminates them. Any advice or where to take this problem ? Think threaten HL with the Financial Ombudsman

[mondex] 05/5/2023 17:22

(Bloomberg) -- US shale-gas drillers are betting that a price slump eroding their cash-flow outlook will be short-lived and that a rebound awaits in 2024.

A group of suppliers including EQT Corp. and Southwestern Energy Co. used the latest round of earnings calls with analysts to reassure investors that natural gas supply and demand fundamentals remain structurally bullish even after prices have slumped by more than half this year.

The dramatic rise of natural gas to 14-year highs in 2022 bolstered producers with unprecedented cash while driving a surge in utility bills. This year’s drop after a mild winter has traders and producers speculating whether the market’s exuberance has come to an end or just taken a pause. A return to higher prices would be unwelcome for consumers who are still faced with debilitating inflation for food and other energy-related costs.

Suppliers’ message is that production growth in the US is quickly slowing down as shale explorers everywhere from Appalachia to Haynesville cut down on drilling activity. That should indicate that a supply glut currently weighing on prices will shrink into next year, when new export capacity is set to considerably boost demand for the heating and power-generation fuel from Europe and elsewhere.

“Near-term activity reduction will result in lower natural gas production this year, further strengthening the longer-term fundamental outlook,” Southwestern Energy Chief Executive Officer Bill Way said during the company’s first-quarter earnings call.

Antero Resources Corp. Chief Financial Officer Michael Kennedy echoed those comments, saying reduced drilling will lead to “significant volatility in pricing as natural gas demand grows materially in 2024.” Comstock Resources Inc. CEO Jay Allison said the gas outlook is “extremely positive” while anticipating “a little bit more pain.”

Chesapeake Energy Corp., Comstock. and APA Corp. are among the companies that signaled a slowdown in drilling activities.

The bullish view on 2024 is reflected in producers’ hedge books. Antero said last week it paid about $200 million to unwind contracts aimed at protecting it against lower gas prices next year as the company seeks to be fully exposed to the commodity upside. EQT, the largest producer, said it has locked in prices for only 10% of its year-ahead production. That’s down from roughly 45% a year ago.

Read More: Shale-Gas Drillers Brace for $8 Billion Cash Shock on Price Drop

US benchmark futures have traded in a contango structure, meaning gas for delivery further in the future is more expensive than today. On Thursday, contracts for 2024 commanded an average premium of 34% over 2023 maturities.

“I think we’re seeing a very positive setup here,” David Khani, CFO of EQT, said during the company’s first-quarter call. Stronger power demand this summer could work as catalyst for higher gas prices, he added. “The big negative could be if summer doesn’t show up.”

[scrwal] 05/5/2023 16:42

Cassini
The 2022 Asset Retirement Supplement states the cumulative retirements every 10 years and are as follows: Year 10 4,500 Year 20 19,000 Year 30 38,000 Year 40 57,000 Year 50 72,000.

[asp5] 05/5/2023 15:01

The only hard legal commitment DEC have is to the various states where they closed 10-15 year contracts in which they commit to plugging a minimum number of wells per year. This as far as I understand is 80 per annum (across all states) which they are comfortably exceeding.

In my view all well plugging activity should be performed on a business case basis (they provided a decision matrix for this in the previous ARO but it would need updating to reflect CCUS, 3rd party plugging etc). In short, I would not expect this to lead to a linear plugging profile.

One other aspect is that you do not want to scale an inefficient process. I could fully understand DEC optimizing their procedures, technology etc. via 3rd party jobs - let someone else pay for you to learn & optimize as it were. Once you feel you have reached a certain level of efficiency you can then deploy on your internal estate i.e. only scale efficient processes.

However the above could also be viewed/interpretted as trying to avoid meeting your commitments. This will become much clearer over time.

[johnhemming] 05/5/2023 13:32

You would be surprised if the wells were being retired on a simple average as they should be retired at the end of their useful life and that will be tail loaded.

One thing I check is the forecast production vs the actual production. For example the recent Tanos production is in a period of rapid decline at the moment, but the rate of decline (as a proportion of production) will reduce. Hence although the price paid is about 2.5 times the next 12 month's EBITDA the following 12 month EBITDA (assuming constant pricing) will be possibly a third less. I don't remember the precise figures.

[cassini] 05/5/2023 13:10

Surely we wouldn't expect the same (or even proportionate to those remaining) amount of wells to be retired each and every year as they (mostly) all start off life as productive (but low rate) wells in the beginning that get exhausted gradually? Most of their acquisitions have only been in the last few years.

Therefore, I'd expect the capping process to be back-end loaded so to speak.

NB: I suppose it depends on what the previous well owners were doing with these wells - had they actually exhausted any of them at low-rate production in the time they operated them? - but in any case DEC claims it 'massages' them to get maximum low rate production out of them.

[scrwal] 05/5/2023 12:26

The latest ARO model assumes a 50 year period.
My main beefs are that c4,500 wells are to be retired in the first 10 years and based on a simple average DEC is behind the curve , and no average cost for 2023 was given because revenue from 3rd party work covers said cost but this only occurs because the company is retiring its wells to meet state requirements plus a fair bit - if they were to meet their own average yearly retirement target there would be very little 3rd party work done and this aspect has been glossed over in my opinion. The figures are as supplied by the company and creates doubt about the model - in the longer term it may not matter but who's to say that things don't go the wrong way if assumptions are loaded too far in the company's favour.

[spangle93] 05/5/2023 10:10

Ptolemy - just to add to asp5's reply

I'm not sure what 20-year "industry norm" you are quoting... global or NA? all wells or gas-only?

Taking your figure at face value, part of the reason that wells are shut in economically is not because they stop producing, but because they become cash-flow negative. A significant part of gas opex is the transportation cost, or third party pipeline levy. In most of the acquisitions made, DEC also takes ownership of the regional export infrastructure, thus tariff that would have increased opex is not incurred.

[johnhemming] 05/5/2023 10:01

@asp5 - I did the figures as to what the first year would be, but things have changed since then in that DEC have more wells (but also more income).

From my point of view they are doing well at making it zero, but at the same time it won't have any material impact on cash flow. (because they are doing well on controlling emissions).

[asp5] 04/5/2023 23:02

@johnhemming - my understanding is that the Methane fees kicks in based on next years methane emission levels. These fees will increase in 2025 & 2026 and then remain at this level going forward. Just curious are your estimated numbers based on the fees in 2024 or the 2026 fee level? I agree, DEC have made good progress on this and I am expecting more positive news on this front over 2023.

@Ptolemy - I think the logic in your example is flawed. "The industry norm" are the various north american E&P players which have a drilling based business model vs the DEC model of acquiring producing assets in the steady decline phase and optimizing production. I am not aware of many other players following the DEC model. It is different to the others (which then requires more intense scrutiny).

To illustrate DEC has on average a 75% lower decline rate vs "the industry norm". So if the industry norm is 20 years well life then it is completely feasable for well life to be 50 years for DEC with their optimization based approach. The regular E&G player is focused on where to drill the next well and not optimizing production from old wells.

I try to validate my reasearch from other sources, so as long as DEC numbers are in the same reasonable ballpark then I am normally fine - it is when things are outside an expected range I tend to dig deeper to make sure I am satisfied.

I do agree with your sentiment of not taking things at face value and hope I did not give that impression

[ptolemy] 04/5/2023 15:29

asp5,

Thanks for your response. The ARO makes some mighty assumptions and I think it's reasonable to challenge those, rather than to simply quote them. For example, DEC assumes a well life of 50 years average when the industry norm is 20-odd years. And some are deemed viable for 75-years. Have other companies really said that 75-years of cash flow is not good enough for them, or do they disagree on the life span? DEC have assumed a close-in cost of $21k per well whilst the industry norm is $50k. Can DEC really shut-in wells fro less than half the cost others have done it?

I'm not saying there isn't money to be made buying DEC but investors/traders ought to look beyond the DEC provided data. I'm saying there are reason to believe there are risks in taking the DEC view at face value. I hope l've made my point and I won't labour the point further.

I trade based on technical patterns and I'm on the look out to buy.

[johnhemming] 04/5/2023 07:17

@asp5 I have done detailed calculations on the Methane Fee and IMO DEC have done really well at driving down emissions to minimise the Methane Fee. It is a bit complicated as it depends on the source, but my last set of calculations in 2022 took it down from below USD9m to below USD3m, but that was without Tanos II for which I have no data.

There are also upsides to this as well, but I like to assess the max downside.

E&OE DYOR

[johnhemming] 04/5/2023 07:13

With Martin Thomas it may be because he has been a non-exec for a long time. I can see the arguments both ways on people remaining non-execs for a long time and being complacent. However, I am not as it stands of a clear view.

Martin Thomas looks well qualified.

[asp5] 03/5/2023 21:59

Ptolemy, let me try and provide some feedback on the points you raise.

1) “DEC have no where near enough money (nor will have) to meet the liabilities of plugging”

The cost of plugging all wells is approx. 65K wells x 25K cost per well = $1,6B. The free cash flow that these 65K wells produce is $~8B (as per last ARO report). I see no issues in meeting liabilities. Furthermore the $~1,6B liability should be considered highly conservative because:

a) It assumes no efficiency gains from the experience of plugging wells and advances in technology. In 2022 the average cost to plug a well was 21K, already DEC has achieved a 15% reduction vs 2020 costs despite a high inflation environment.

b) It assumes no offset from 3rd party well plugging. Already in 2023 ~50% of plugging capacity is being used for 3rd party plugging.

c) It assumes 100% of wells will need to be plugged, even though the inflation reduction act will drive demand for CCUS. This growing CCUS demand has the potential to materially reduce the number of wells that need to be plugged.

d) It assumes no offset from CCUS tax credits which are already set and approved in the inflation reduction act

2) “Releasing gas into the air at thousands of well heads”

DEC have defined targets of 30% reduction in Scope 1 methane intensity by 2026, a 50% reduction in Scope 1 methane intensity by 2030 and net zero Scope 1 and 2 GHG emissions by 2040.

They produce detailed updates on their progress with the latest results showing Scope 1 methane intensity already down 25% (vs 2020) , well ahead of schedule.

Clearly we would all like to be at net zero today, however DEC is steadily executing and delivering results. I see the role of “proven trusted stewardship” as being something that will be highly appreciated going forward.

3) “DEC is accused of using non-industry standard procedures for measuring emissions”

The Oil & Gas Methane Partnership 2.0 (OGMP 2.0) is the flagship oil and gas reporting and mitigation programme of the United Nations Environment Programme (UNEP). It is the only comprehensive, measurement-based international reporting framework for the sector.

It was designed to improve the credibility of methane reporting to better inform methane-reducing challenges and best practice through a more robust and consistent reporting framework. DEC are 1 of only 5 US companies (as of 2022) to achieve the gold standard.

I see DEC making really good progress, which should be reflected in the share price in due course. As usual DYOR.

[lab305] 03/5/2023 10:43

At least Martin Thomas has a decent shareholding of over 2m shares unlike many of the others.