Malcy’s Blog: Oil price, PetroTal, Wentworth, Molecular Industries. And finally…

WTI (Mar) $75.88 -53c, Brent (Apr) $82.17 -67c, Diff -$6.29 -14c. 

USNG (Mar) $2.45 u/c, UKNG (Mar) 145.0p -5.0p, TTF (Mar) €56.495 -€13.0.

Oil price

Oil fell yesterday after the final interest rate increases were announced but the mighty dollar staged a rally as Jerome suggested inflation may be peaking, or not…

PetroTal Corp

PetroTal has announced that it received a notice to exercise 11,764,706 Investor Warrants at a price of 16 pence per Common Share from an investor in relation to the Investor Warrants issued on June 12, 2020. The Company received 1,882,352.96 GBP for the Warrants exercised.

Following the Warrants exercise, the Company will have 47,110,981 Investor Warrants outstanding. Application will be made for admission of the 11,764,706 common shares, which will rank pari passu with existing Common Shares, to trading on AIM, which is expected to occur on or around February 9, 2023.

Following Admission, the Company will have 874,973,702 common shares issued and there are no shares held in treasury. This figure may be used by shareholders as the denominator for the calculations to determine if they are required to notify their interest in, or a change of their interest in, the Company under the FCA’s Disclosure Guidance and Transparency Rules.

Speaks for itself.

Wentworth Resources

Wentworth announced on 5 December 2022 that they had reached agreement on the terms of a recommended acquisition of the entire issued and to be issued share capital of Wentworth by M&P. The Acquisition values the entire issued and to be issued ordinary share capital of Wentworth at approximately £61.7 million (approximately $75.0 million).

The Acquisition is to be implemented by means of a scheme of arrangement pursuant to Article 125 of the Jersey Companies Law, which requires (among other matters) the approval of the Scheme Shareholders at the Court Meeting and the Wentworth Shareholders at the General Meeting, and the sanction of the Court.

On 25 January 2023 Wentworth announced the publication and posting of a circular in relation to the Scheme containing, amongst other things, a letter from the Chairman of Wentworth, an explanatory statement pursuant to Article 126 of the Jersey Companies Law, the full terms and conditions of the Acquisition, notices convening the Court Meeting and the General Meeting, an expected timetable of principal events and details of the actions to be taken by Wentworth Shareholders, together with the associated Forms of Proxy 

The Court Meeting and General Meeting are scheduled for 23 February 2023 and the latest date for lodging Forms of Proxy is 21 February 2023.

The Board of Wentworth notes that Institutional Shareholder Services (“ISS”) and Pensions & Investment Research Consultants Ltd (“PIRC”) have both issued supportive FOR recommendations, advising their institutional shareholder subscribers to vote IN FAVOUR of the resolutions necessary to approve the Scheme at the Court Meeting and general meeting.

ISS and PIRC are leading independent, third-party proxy advisory firms which provide proxy voting recommendations to pension funds, investment managers, mutual funds, and other institutional shareholders.

Subject to any restrictions relating to persons resident in Restricted Jurisdictions, the Scheme Document is available on Wentworth’s website at and on M&P’s website at

Scheme Shareholders and Wentworth Shareholders are encouraged to submit proxy appointments and instructions for the Court Meeting and the General Meeting as soon as possible using any of the methods set out in the Scheme Document. Scheme Shareholders and Wentworth Shareholders are also encouraged to appoint the Chair of the relevant Meeting as their proxy.

It is important that, for the Court Meeting in particular, as many votes as possible are cast so that the Court may be satisfied that there is a fair and reasonable representation of the opinion of Scheme Shareholders. Whether or not you intend to attend the Court Meeting and/or the General Meeting in person, you are therefore strongly urged to complete, sign and return both of your Forms of Proxy or appoint a proxy or proxies electronically for both the Court Meeting and the General Meeting as soon as possible.

Wentworth Shareholders should carefully read the Scheme Document in its entirety before making a decision with respect to the Scheme.

This is important for Wentworth and its shareholders as both these firms are considered to be independent and their advice, as can be seen in other M&A situations, are by no means taken as read. 

Any endorsement by either PIRC or ISS can be relied upon to be advice worth heeding and given that the Board has recommended the transaction as being in the best interests of shareholders should be borne in mind.

Molecular Industries

Molecular Energies has provided an update on the drilling rig for its Paraguay operations.

Further to the announcement of 9 January 2023 the relevant drilling rig has been successfully procured and the drilling contract with President Energy Paraguay S.A now signed. As flagged previously the rig will now undergo necessary repairs and checks due to the rig having being cold stacked for a prolonged period.

The agreements for ancillary drilling services are now being signed with the objective of commencing drilling as soon as possible. Due to the significant delays completely outside of MEN’s control the estimated time for commencement of drilling is in May. We restate that such delays were directly due to the complex financial insolvency of the previous owners of the rig which necessitated dealing with multiple parties.

The drilling time projected to reach target depth is estimated to be 40 days from the time of commencement.

Despite the various delays shareholders will be pleased that a timescale is now ahead of them. 

And finally…

Tomorrow is one of the most exciting sporting days of the year as the start of rugby Six Nations Championship. Even more exciting as this year is a Rugby World Cup year with the finals in France in the autumn.

The fixtures start tomorrow with Wales v Ireland (14:15) and England v Scotland (1645). On Sunday a newly invigorated Italy entertain Les Bleus in Rome.

The Prem is back and tonight the famous Kings road derby sees the Cottagers head up to Stamford Bridge.

Tomorrow the Toffees under new management host top of the table Gooners and in the Midlands Villa entertain the Foxes. The Bees host the Saints, and in the Riviera derby the Cherries go to the Seagulls. The Eagles are at the Theatre of Dreams, Wolves host Liverpool and the Magpies entertain the Hammers.

On Sunday Forest host Leeds and in what used to be a top of the table clash the Noisy Neighbours go to White Hart Lane, although maybe not looking over Harry Kane any more.

Racing is at Sandown Park tomorrow.

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Directorate change | BOE Report


February 1, 2023

Shell plc (the “Company”) announces the following Board and Committee changes:

Euleen Goh, Deputy Chair and Senior Independent Director has informed the Board that she does not wish to stand for re-election as Director of the Company at the Annual General Meeting (AGM), currently scheduled for May 23, 2023, having served as a Director for nine years.

Dick Boer, a Non-executive Director, has been appointed Deputy Chair and Senior Independent Director, and as a member of the Remuneration Committee with effect from the conclusion of the 2023 AGM.

Catherine Hughes, a Non-executive Director, has been appointed as a member of the Audit Committee with effect from the conclusion of the 2023 AGM and will step down as a member of the Remuneration Committee on the same date.

Jane Holl Lute, a Non-executive Director, has been appointed as a member of the Remuneration Committee with effect from the conclusion of the 2023 AGM.

Martina Hund-Mejean, a Non-Executive Director has decided not to stand for re-election as Director of the Company at the 2023 AGM.

Mr. Boer, Ms. Hughes, and Ms. Holl Lute’s appointments are subject to their respective re-appointment by shareholders at the 2023 AGM.

Sir Charles Roxburgh has been appointed as a Non-Executive Director of the Company, effective from March 13, 2023 and will become a member of the Audit Committee as of the same date.

Leena Srivastava has been appointed as a Non-Executive Director of the Company, effective March 13, 2023, and will become a member of the Safety, Environment and Sustainability Committee as of the same date.

Sir Andrew Mackenzie, Chair of Shell plc said: “I’d like to thank Euleen for her nine years of distinguished service to Shell. During that time she brought a unique perspective on finance and management issues as Shell underwent significant change, not least with the acquisition of BG Group PLC in 2016, on which she provided expert counsel to the then CEO and Chairman. She has provided invaluable advice to me as Chair and I wish her all the best for her future endeavours.

“I’d also like to thank Martina for her contribution to Shell since joining the Board in 2020. Her expertise in technology leadership has been invaluable as Shell navigates its way through the energy transition, and I’ve valued her sound advice on many issues.

“I’m delighted to welcome Sir Charles and Leena to the Board. Sir Charles brings a wealth of experience in economics, financial management and government, and I know he will make a great contribution to the Shell board.

“Leena is a leading global authority on climate science, based in India — an important market and operational centre for Shell. Her decades of experience on energy, environment and climate change policy, as well as her expertise in sustainable development, will further strengthen Shell’s energy transition efforts as we continue to deliver the energy the world needs today, while working to decarbonise our own activities and those of our customers.”

Pursuant to Listing Rule 9.6.13 (1) there is no information to disclose for Sir Charles. However, Ms Srivastava was previously a Non-Executive Director of Shree Cement Limited until August 2019 and Bharti Infratel Limited until November 2020. There is no information to disclose pursuant to Listing Rule 9.6.13 (2) to Listing Rule 9.6.13 (6) inclusive for either Sir Charles or Ms. Srivastava.

Following the conclusion of the 2023 AGM, the membership of each of the Board Committees will be as follows:

AUDIT COMMITTEEAnn Godbehere (Chair)
Dick Boer
Catherine Hughes
Cyrus Taraporevala
Sir Charles Roxburgh
Neil Carson
Jane Holl Lute
Bram Schot
Leena Srivastava
Dick Boer
Ann Godbehere
Neil Carson (Chair)
Bram Schot
Jane Holl Lute
Dick Boer

Anthony Clarke
Deputy Company Secretary


Shell Media Relations
International, UK, European Press: +44 20 7934 5550

Cautionary Note
The companies in which Shell plc directly and indirectly owns investments are separate legal entities. In this disclosure “Shell”, “Shell Group” and “Group” are sometimes used for convenience where references are made to Shell plc and its subsidiaries in general. Likewise, the words “we”, “us” and “our” are also used to refer to Shell plc and its subsidiaries in general or to those who work for them. These terms are also used where no useful purpose is served by identifying the particular entity or entities. ‘‘Subsidiaries’’, “Shell subsidiaries” and “Shell companies” as used in this disclosure refer to entities over which Shell plc either directly or indirectly has control. Entities and unincorporated arrangements over which Shell has joint control are generally referred to as “joint ventures” and “joint operations”, respectively. “Joint ventures” and “joint operations” are collectively referred to as “joint arrangements”. Entities over which Shell has significant influence but neither control nor joint control are referred to as “associates”. The term “Shell interest” is used for convenience to indicate the direct and/or indirect ownership interest held by Shell in an entity or unincorporated joint arrangement, after exclusion of all third-party interest.

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Forward-Looking Statements
This disclosure contains forward-looking statements (within the meaning of the U.S. Private Securities Litigation Reform Act of 1995) concerning the financial condition, results of operations and businesses of Shell. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements are statements of future expectations that are based on management’s current expectations and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. Forward-looking statements include, among other things, statements concerning the potential exposure of Shell to market risks and statements expressing management’s expectations, beliefs, estimates, forecasts, projections and assumptions. These forward-looking statements are identified by their use of terms and phrases such as “aim”, “ambition”, ‘‘anticipate’’, ‘‘believe’’, ‘‘could’’, ‘‘estimate’’, ‘‘expect’’, ‘‘goals’’, ‘‘intend’’, ‘‘may’’, “milestones”, ‘‘objectives’’, ‘‘outlook’’, ‘‘plan’’, ‘‘probably’’, ‘‘project’’, ‘‘risks’’, “schedule”, ‘‘seek’’, ‘‘should’’, ‘‘target’’, ‘‘will’’ and similar terms and phrases. There are a number of factors that could affect the future operations of Shell and could cause those results to differ materially from those expressed in the forward-looking statements included in this disclosure, including (without limitation): (a) price fluctuations in crude oil and natural gas; (b) changes in demand for Shell’s products; (c) currency fluctuations; (d) drilling and production results; (e) reserves estimates; (f) loss of market share and industry competition; (g) environmental and physical risks; (h) risks associated with the identification of suitable potential acquisition properties and targets, and successful negotiation and completion of such transactions; (i) the risk of doing business in developing countries and countries subject to international sanctions; (j) legislative, judicial, fiscal and regulatory developments including regulatory measures addressing climate change; (k) economic and financial market conditions in various countries and regions; (l) political risks, including the risks of expropriation and renegotiation of the terms of contracts with governmental entities, delays or advancements in the approval of projects and delays in the reimbursement for shared costs; (m) risks associated with the impact of pandemics, such as the COVID-19 (coronavirus) outbreak; and (n) changes in trading conditions. No assurance is provided that future dividend payments will match or exceed previous dividend payments. All forward-looking statements contained in this disclosure are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. Readers should not place undue reliance on forward-looking statements. Additional risk factors that may affect future results are contained in Shell plc’s Form 20-F for the year ended December 31, 2021 (available at and These risk factors also expressly qualify all forward-looking statements contained in this disclosure and should be considered by the reader. Each forward-looking statement speaks only as of the date of this disclosure, February 1, 2023. Neither Shell plc nor any of its subsidiaries undertake any obligation to publicly update or revise any forward-looking statement as a result of new information, future events or other information. In light of these risks, results could differ materially from those stated, implied or inferred from the forward-looking statements contained in this disclosure.Shell’s net carbon footprint
Also, in this disclosure we may refer to Shell’s “Net Carbon Footprint” or “Net Carbon Intensity”, which include Shell’s carbon emissions from the production of our energy products, our suppliers’ carbon emissions in supplying energy for that production and our customers’ carbon emissions associated with their use of the energy products we sell. Shell only controls its own emissions. The use of the term Shell’s “Net Carbon Footprint” or “Net Carbon Intensity” are for convenience only and not intended to suggest these emissions are those of Shell plc or its subsidiaries.

Shell’s net-Zero Emissions Target
Shell’s operating plan, outlook and budgets are forecasted for a ten-year period and are updated every year. They reflect the current economic environment and what we can reasonably expect to see over the next ten years. Accordingly, they reflect our Scope 1, Scope 2 and Net Carbon Footprint (NCF) targets over the next ten years. However, Shell’s operating plans cannot reflect our 2050 net-zero emissions target and 2035 NCF target, as these targets are currently outside our planning period. In the future, as society moves towards net-zero emissions, we expect Shell’s operating plans to reflect this movement. However, if society is not net zero in 2050, as of today, there would be significant risk that Shell may not meet this target.

Forward Looking Non-GAAP measures
This disclosure may contain certain forward-looking non-GAAP measures such as cash capital expenditure and divestments. We are unable to provide a reconciliation of these forward-looking Non-GAAP measures to the most comparable GAAP financial measures because certain information needed to reconcile those Non-GAAP measures to the most comparable GAAP financial measures is dependent on future events some of which are outside the control of Shell, such as oil and gas prices, interest rates and exchange rates. Moreover, estimating such GAAP measures with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. Non-GAAP measures in respect of future periods which cannot be reconciled to the most comparable GAAP financial measure are calculated in a manner which is consistent with the accounting policies applied in Shell plc’s consolidated financial statements.

The contents of websites referred to in this disclosure do not form part of this disclosure.

We may have used certain terms, such as resources, in this disclosure that the United States Securities and Exchange Commission (SEC) strictly prohibits us from including in our filings with the SEC. Investors are urged to consider closely the disclosure in our Form 20-F, File No 1-32575, available on the SEC website

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Not All Solar Stocks Have Sunny Charts


My deep dive into solar has been a good news story.   I am finding companies growing revenue and generating cash.

Solar has tremendous growth ahead of it.  The Inflation Reduction Act (IRA) will great a boom for years to come.

But not every stock has been a tempting buy.

If the story has an Achilles heel, I can tell you where: Financing.

Solar installations need credit.  Preferably cheap credit.

Today credit conditions are going in the wrong direction.  Liquidity has tightened a lot.  Rates are higher.  It is creating pockets of stress in solar financing.

There is no better example of this than the mess that Sunlight Financial (SUNL – NASDAQ) has found for itself.

 1 sunlight stock chart


Sunlight Financial came to the public market as a SPAC in January 2021.

Sunlight was born out of the Spartan Acquisition Corp II.  At the time of the business combination, they were valued at $1.3 billion.

Today Sunlight has a market capitalization of just under $100 million – or a 90%+ decline.

What happened?

Rates happened.  Sunlight got caught on the wrong side of the rise in interest rates.  Here’s how:

Sunlight is in the business of lending for residential solar installations and home improvement.

Most of Sunlight’s lending is on the solar side.  In Q3 22, 84% of their loans were solar installations.  These are loans to homeowners that let them put solar panels on their rooftops.

Sunlight is a big player in residential solar financing: it has an 8% market share in the US.

They get customers via a network of solar installers.  When a Sunlight approved installer sells a system to a homeowner, they offer a financing option to purchase the array with no money down, with the loan originated via Sunlight.

A loan gets made, the system installed, and some of the revenue from the electricity produced goes toward paying interest and principal on the loan.

These are decent sized loans, averaging just under $46k in Q3:

 2 average loan balances

Source: Sunlight Financial Q3 Results Presentation

While only 20% of residential solar system sales were financed with solar loans in 2015, by 2020 63% of residential solar loan sales were financed.  It is a large market and a growing one.


In 2019 Sunlight added a new business when it began to originate home improvement loans.

Sunlight makes its home improvement loans in the same way as its solar loans.  A contractor agrees to a job with a homeowner, but in this case to pay for a new roof or new windows.  Sunlight has a network of ~1,000 contractors that act as their loan originators.

3 contractor growth

Source: Sunlight Financial Q3 Results Presentation

I’m not thrilled with this business.  Home improvement loans are a bit more dicey than solar.   They aren’t backed by a revenue stream.  These are loans that seem more likely to go south.

On the other hand, this is a small business compared to Sunlight’s solar lending (it is about 1/5th the size and was only 6% of revenue in 2021), the loans are a lot smaller ($17.8k average in Q3) and interest rates on the loans are far higher.  Sunlight also seems to be making loans to credit-worthy customers

4 customer interest rate
5 customer fico

Source: Sunlight Financial Q3 Results Presentation

At any rate, it isn’t the home improvement lending that causes Sunlight’s book to go south.


Solar lending should have a lot going for it.   There are subsidies, electricity rate advantages, and a relatively constant stream of cash.

Considering that ~85% of Sunlight’s loans are solar, you might think that this is a safe bet – cash flows that cover debt and happy lenders.

What could go wrong?

We always hear about 100-year storms.   We hear about them so often that it seems impossible that there could be one every 100-years.

The same goes for financial storms.  There is a 100-year financial storm about every 10-years.   Inevitably when one happens, boats get caught and capsize.

Sunlight found itself caught in the storm.  It remains to be seen if they capsize, but it’s going to be rough sailing.


The storm that caught Sunlight was the speed of the rate hikes.

Throughout 2022 Sunlight made more loans than at any time in their history.

6 funded loans
Source: Sunlight Financial Q3 Results Presentation

But because rates rose so fast those loans quickly went underwater – before Sunlight could sell them to investors.

Sunlight is a point-of-sale lender.  Contractors and installers approach households with their solar product and offer Sunlight financing.  Sunlight approaches investors to funds loan.  Loans are matched up with lenders.

7 investor presentation
Source: Sunlight Financial 2021 Investor Presentation

There are two ways a loan can get funded.  Either before it is made or after it is made.

Sunlight’s preferred model is to pre-fund the loans.  Investors agree to a rate before the loan is even made.  This was the process described in Sunlight’s initial investor presentation:

8 spac
Source: Sunlight Financial SPAC Conversion 2021 Investor Presentation

The key in the above slide is the term “pre-agreed dollar price”.  Sunlight clarifies this in the footnote:

9 footnote

Source: Sunlight Financial 2021 Investor Presentation

For a pre-funded loan, there is no lag between originating the loan and funding it.  If rates rise sharply and suddenly, that is on the investor, not Sunlight.

But then how did Sunlight get in trouble?


Here’s how.

Historically, most of Sunlight’s loans are pre-funded (they called it direct lending).  At the time of the SPAC acquisition around 90% of lending was direct:

10 funded by channel
Source: Sunlight Financial 2021 Investor Presentation

Direct lending soared after the pandemic.  Money was cheap.  Banks were bursting with deposits.  Investors jumped at the chance to fund solar installs.

But in more normal times Sunlight has more loan volume than it can pre-fund.  In that case they take a different tact.

Sunlight uses an intermediary – a bank – to hold onto the loan while Sunlight looks for an end buyer.

They call these “indirect loans”.  They are basically loans that are warehoused with the bank until they can be sold to investors.

The process takes 3-4 months.

11 direct indirect
Source: Sunlight Financial 2021 Investor Presentation

This happens all the time with mortgage loans.   There is nothing wrong with the warehousing model.

But for Sunlight, the model went south when rates went north.

The Fed hiked rates by over 4% in less than a year.  Last cycle it took 3 years for the Fed to raise rates 2.5%.

12 federal funds
Source: CNBC

This broke Sunlight’s funding model.  Sunlight was forced to move more loans to indirect funding.

In the first quarter of 2021 Sunlight funded $581 million of loans.  $84 million of that was from the indirect channel (15%).

In the first quarter of 2022 Sunlight funded $593 million of loans and $164 million were indirect (28%).

In the third quarter Sunlight funded $834 million of loans and $264 million was from indirect (34%).

At the same time, rising rates and widening spreads made loans only a month or two old underwater – with Sunlight holding the exposure.

On the Q3 call they said:

“we also continue to see interest rate increases of unprecedented speed and magnitude, which… will affect our ability to profitably monetize indirect channel loans originated earlier this year… loans in the indirect channel will be sold at a loss”


Adding to their woes, in late September Sunlight announced an “installer liquidity event”.

That “event” was the bankruptcy of one of their largest solar installers, Pink Energy.

The bankruptcy hit Sunlight in a few ways.

First, Pink was a large partner and the loss of their business cut into new loan originations.

Second, Sunlight advanced money to Pink to build the customer projects.  Sunlight estimated they had about $32.4 million of advances that they would not recover.

Third (maybe most important), this was a hit to Sunlight’s credibility at exactly the wrong time


Sunlight is in a tough spot.  They are going to have to sell underwater loans and that means sell them at a loss.
They disclosed as much in a December 13th 8-K filing.

The filing announced several changes to the agreement with the bank partner.

The good news is that Sunlight’s bank partner increased their lending capacity.  More of Sunlight’s loans can be held on their balance sheet.

The bad news is that amendments changed the fee structure (likely not in Sunlight’s favor) and tightened Sunlight’s collateral requirements on non-current loans.

Sunlight also said in the filing that they will have to “sell a significant portion of their backbook loans in December”.

They will take a loss on these sales.  The impact is expected to reduce total platform fees in Q4 to only $0-$5 million – down from $31 million in Q3.

That still leaves $275-$300 million of backbook loans at the bank partner, which Sunlight plans to sell in the first half of 2023.

The long and short of it is that these sales will “significantly reduce the Company’s cash balance and may result in materially less available liquidity through the first half of 2023”.

Not surprisingly, Sunlight is looking at strategic alternatives: selling the company or raising capital.

They said they have “received interest from parties both in investing in the company and in acquiring the company”.


I have no idea how this plays out.  It will come down to whether Sunlight can find a partner with deep pockets, either to buy the company or provide capital to get them out of this jam.

That could happen.  Most of the loans are solar loans so these are long-term loans.   Long-term rates have come down a lot from the peak.

But Sunlight is distressed.  It is difficult to imagine them having much leverage in a negotiation with a potential partner.

That makes me want to sit this one out and just watch.

There may or may not be something worth owning once the dust settles.  If there is, subscribers will be the first to know.

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Obsidian Energy Announces 2023 Guidance and Significant 2022 Reserves Value Increase with Year-End Reserves Report – Energy News for the Canadian Oil & Gas Industry |

2023 capital expenditures includes development and exploration/appraisal programs with optionality for second half expansion

• 46 well development program across all core areas in 2023 expected to generate seven percent growth in production over 2022 and significant free cash flow at WTI US$80/bbl

• Board approves share buyback program for up to 10 percent of shares outstanding

• Reserve replacement of 144 percent, 214 percent and 393 percent of 2022 production on a proved developed producing, total proved, and total proved plus probable basis, respectively

Calgary, Alberta–(Newsfile Corp. – January 30, 2023) – OBSIDIAN ENERGY LTD. (TSX: OBE) (NYSE American: OBE) (“Obsidian Energy“, the “Company“, “we“, “us” or “our“) is pleased to announce our 2023 guidance that builds on our successful 2022 drilling results across all three areas, the introduction of a share buyback program, and the results of our independent reserves evaluation for the year ended December 31, 2022 (the “2022 Reserve Report“).

“Our 2022 drilling success positions us to continue to deliver both year-over-year production growth and strong free-cash flow generation in 2023,” said Stephen Loukas, Obsidian Energy’s Interim President and CEO. “Since introducing our 2023 preliminary forecast, we have seen a decline in oil prices, continued service cost inflation, and widening of heavy oil differentials, as well as a decline in our share price such that it trades materially below intrinsic value. Accordingly, our 2023 strategy now focuses on a balance between several components, including capital for development and exploration/appraisal wells, continued debt reduction and return of capital to shareholders via a share buyback, while also preserving acquisition optionality. The majority of our 2023 capital is allocated to core development but includes a component to further delineate our large land base, mainly in the Clearwater formation in the Peace River area. Our program optionality allows us to quickly adjust depending on well results, changes in commodity prices, and acquisition opportunities. We look forward to executing on our plans to create future value for our shareholders and the Company.”

Stephen Loukas continued, “We had an active year in 2022 with a successful capital program that was expanded mid-year and includes the acquisition of additional land in the Peace River area. These results, combined with higher commodity price forecasts, led to a substantial increase in our reserve values and volumes over 2021, replacing reserves across all categories. This represents the sixth year in a row of greater than 100 percent reserve replacement on total proved (“1P“) reserves and total proved plus probable (“2P“) reserves, excluding acquisitions and dispositions, and economic factors. As a result, our proved developed producing (“PDP“) and 1P reserve net present values increased by $438 million to $1.6 billion, and $700 million to $2.1 billion, respectively, at December 31, 2022 (before tax, discounted at 10 percent).”


With a strong start to our 2023 development program, Obsidian Energy expects to grow average production to approximately 32,000 to 33,500 boe/d in 2023 – a seven percent increase from 2022 at the mid-point. While still growing production, we are electing to moderate our capital spending and growth profile in this environment of increasing service costs and WTI crude oil prices, which are approximately US$20 per barrel lower from mid-year 2022 levels. At this time, we prefer to redirect capital previously earmarked for development towards the initiation of a normal course issuer bid (“NCIB“).

We are pleased with our 2022 results, which will be announced in February and are reflected in the increases in our 2022 Reserve Report. Our fourth quarter 2022 capital program remained active despite extreme cold weather in December that hampered operations and production. Fourth quarter capital was approximately $97 million, bringing full year capital slightly below our 2022 guidance at $319 million (including the Peace River gas plant acquisition in September). Production averaged 31,742 boe/d for the fourth quarter, bringing full year 2022 production to 30,682 boe/d, which is slightly below the low end of guidance of 30,800 boe/d due to the impact of the cold weather on operations and facilities. Concerning wells spud in 2022, three wells (2.9 net) were rig released in January 2023 and eight (7.8) net wells are expected to be brought on production in 2023.

During 2023, the Company is planning between $260 and $270 million in capital expenditures for development and exploration/appraisal activities, plus an additional $26 to $28 million in decommissioning expenditures that accelerates our asset retirement obligations (decommissioning expenditures are higher in 2023 than in 2022 as the Alberta Energy Regulator increased industry spend targets for oil and gas companies in Alberta). Capital expenditures are primarily focused on development wells in all areas and incorporate the impact of inflationary pressures on drilling consumables and service costs, which were approximately 30 percent higher at the end of 2022 compared to 2021. Obsidian Energy has contracted rigs and services for the first half 2023 program to minimize the impact of future inflation. Our active first quarter 2023 development program will continue the momentum from the 2022 program, resulting in production growth and expected strong free cash flow. Should commodity prices be favourable, we are well positioned to act on opportunities and adjust the program upward during the second half of the year.

Net operating expenses are expected to be slightly lower than 2022 levels as higher production helps offset the impacts of inflationary pressures and planned facility turnaround activity during the year. Free cash flow (“FCF“) generated in 2023 will be directed toward further debt reduction and to shareholders through the NCIB, resulting in a 2023 net debt to funds flow from operations (“FFO“) of approximately 0.5 times (prior to any shares repurchased under an NCIB). Any FCF above expected guidance levels could be allocated towards additional development and exploration/appraisal activities, potential acquisitions and/or additional shareholder return of capital. Our full year 2023 guidance is presented below.

2023E Guidance
Production1boe/d32,000 – 33,500
% Oil and NGLs%67%
Capital expenditures2$ millions260 – 270
Decommissioning expenditures$ millions26 – 28
Net operating costs$/boe13.50 – 14.40
General & administrative$/boe1.60 – 1.70
Based on midpoint of above guidance
WTI RangeUS$/bbl80.00
FFO3$ millions395
FCF (prior to NCIB)$ millions105
Net debt (prior to NCIB)4$ millions215
Net debt to FFO4times0.5

(1) Mid-point of guidance range: 12,330 bbl/d light oil, 6,885 bbl/d heavy oil, 2,565 bbl/d NGLs and 65.8 mmcf/d natural gas. Average production volumes include a minimal amount of forecasted production associated with exploratory capital expenditures.
(2) Capital expenditures include approximately $25 million for exploration/appraisal well activity with minimal impact on forecasted production volumes.
(3) Pricing assumptions outlined are forecasted for the full year of 2023 and include risk management (hedging) adjustments as of January 27, 2023. Guidance FFO and FCF includes approximately $6 million of estimated charges for full year 2023 related to the deferred share units, performance share units and non-treasury incentive plan cash compensation amounts which are based on a share price of $9.00 per share.
(4) Net debt figures estimated as at December 31, 2023, prior to the impact of any share purchased under the NCIB.

Guidance Sensitivity Table
VariableRangeChange in 2023 FFO ($ millions)
WTI (US$/bbl)+/- $1.00/bbl8.6
MSW light oil differential (US$/bbl)+/- $1.00/bbl5.5
WCS heavy oil differential (US$/bbl)+/- $1.00/bbl3.1
Change in AECO ($/GJ)+/- $0.25/GJ3.2


Our 2023 program incorporates activity in all three areas, including first quarter 2023 development drilling in Viking following the successful step-out well in 2022 and an expanded Clearwater exploration/appraisal program in Peace River to further assess our extensive land position. With rigs and services contracted, the first half 2023 program is well underway with five rigs in the process of drilling 25 wells (24.8 net) of our 46 well (44.2 net) operated program that includes:

  • Seven Cardium wells (6.8 net) in Willesden Green and Pembina
  • Three Bluesky development wells (3.0 net) and two (2.0 net) exploration/appraisal wells in Peace River
  • Two Clearwater exploration/appraisal wells (2.0 net) in Peace River
  • 11 wells (11.0 net) in the Viking area

Obsidian Energy also plans to drill up to four vertical non-productive oil sands exploration wells to collect additional reservoir data in the Peace River area. In addition to the 2023 program wells, three wells (2.9 net) from our 2022 development program were rig-released in 2023, and eight wells (7.8 net) are expected to come on production in early 2023. We expect to further optimize the second half 2023 program as new results from offset wells and first half exploration/appraisal drilling provide additional information.

gross (net) wells
gross (net) wells
Willesden Green (Cardium)5 (5.0)6 (6.0)11 (11.0)11 (11.0)
Pembina (Cardium / Devonian)2 (1.8)6 (4.4)8 (6.2)8 (6.2)
Peace River (Bluesky)3 (3.0)7 (7.0)10 (10.0)2 (2.0)2 (2.0)12 (12.0)
Peace River (Clearwater)2 (2.0)2 (2.0)4 (4.0)4 (4.0)
Viking11 (11.0)11 (11.0)11 (11.0)
TOTAL21 (20.8)19 (17.4)40 (38.2)4 (4.0)2 (2.0)6 (6.0)46 (44.2)

(1) Three wells (2.9 net) were spud in 2022 and rig-released in 2023; they are included in these totals.
(2) 45 wells (43.0 net) rig-released in 2023 are expected to be brought on production by the end of 2023 with one well expected in early 2024.

Additional detail regarding our planned 2023 activity is as follows:

  • Peace River: Continuing on the success of our development of the Bluesky formation, we plan to drill an additional 12 Bluesky wells (12.0 net) in 2023. Two wells (2.0 net) are exploration/appraisal wells planned for the first quarter of 2023 to delineate and further expand our Bluesky play. The first well on the Walrus 16-20 Pad was successfully rig-released in mid-January; it encountered excellent reservoir quality and is being brought on production. A second well is currently being drilled to further delineate the South Walrus area. This provides the opportunity for additional follow up locations in the area, including on land purchased in 2022.With approximately 500 sections of prospective Clearwater and Bluesky formation rights, Obsidian Energy plans exploration/appraisal drilling in both formations to further delineate the multizone heavy oil potential in the area. Spud in mid-December 2022, the Dawson Clearwater well (1.0 net) encountered good quality reservoir with oil quality of 12.4o API, providing key information for our 2023 program. The Company currently plans to drill four Clearwater wells (4.0 net) in 2023, following up on the information gained from our 2022 activity.
  • Willesden Green: We plan to drill 11 wells (11.0 net) targeting the Cardium formation in Willesden Green to follow up on the success of our 2022 program, which exceeded expectations and achieved notable top Alberta production rates at our 3-03 Pad and 4-17 Pad. Willesden Green continues to provide strong high quality economic results for the Company.In 2023, we will also focus on managing facility capacity from new production additions across our Cardium areas (Willesden Green and Pembina). At the same time, we will be utilizing existing pads to lower capital and help mitigate the impact of inflation and higher service costs.
  • Pembina: In late December 2022, we brought on a strong three-well pad at Lodgepole in the Pembina area. We will continue our successful development in this area with eight wells (6.2 net) planned for 2023, including two low-cost Devonian vertical wells in the second half of the year on new land acquired in 2022.
  • Viking: Continuing the success of our re-entry into Viking in 2022, we plan to drill 11 wells (11.0 net) in the first half of 2023 prior to spring break-up. These wells will follow-up the 2022 step-out well that tested the western extent of the play and displayed strong production rates with a shallower decline, resulting in faster payouts and strong economic returns. The 2023 program will extend our Viking footprint to the west, offsetting the step-out well with a full development program and associated infrastructure. Future producing locations in the western portion of the field will be refined and developed as we incorporate the results of our early 2023 drilling program, which is expected to be brought on production towards the end of the first quarter.


Obsidian Energy is committed to returning capital to our shareholders. Execution of our corporate plans over the last several years and our 2023 guidance is expected to generate FCF and liquidity to allow us to achieve this goal. Based on our guidance, net debt to FFO is expected to be well below 1.0 times in 2023, and the strength of our 2022 Reserves Report and operations provides us the opportunity to further enhance our liquidity position.

Our Board of Directors have authorized a NCIB of up to 10 percent of our public float, which we are applying to the Toronto Stock Exchange (“TSX“) for approval. To enhance our liquidity, we are pursuing increasing our debt capacity, which will facilitate execution under a NCIB. Any NCIB purchases will be subject to the Company maintaining at least $65.0 million of liquidity and complying with the terms and positions of our current credit facilities. In addition, our July 2027 Senior Unsecured Notes (the “Notes“) have a provision whereby we are required to make an offer to noteholders to repurchase their Notes, subject to a cap of $63.8 million, based on the amount of excess FCF (calculated on a semi-annual basis) and the amount of liquidity available to the Company. Based off current strip pricing and our projected first half 2023 results, we expect that we would be able to make such an offer in addition to continuing to execute our NCIB. Further details regarding the NCIB will be provided when it has been approved by the TSX.

Considering the Company’s current production profile, our net debt target is $225 million, which we expect to achieve in the second half of 2023 based on our guidance (and subject to shares purchased under an NCIB). As we approach this debt level while maintaining our liquidity threshold, we will evaluate additional return of capital plans. The NCIB is initially being implemented as we believe the intrinsic value of our shares far exceeds our current trading price as evidenced, in part, by the net present value, before-tax, discounted at 10 percent (“NPV10“) of our 2022 PDP reserves less net debt (at September 30, 2022), which exceeds $15 per share.


We are pleased to announce our independent reserves evaluation for the year ended December 31, 2022, prepared by GLJ Ltd. (“GLJ“).

“The strength of the Company’s high-quality assets and successful 2022 capital program combined with improved pricing are shown in the results of our 2022 Reserves Report,” said Stephen Loukas. “The future price deck increased roughly 30 percent from year-end 2021, helping to mitigate the impact of inflation and rising expenses on finding and development costs. We also aligned our future development capital in our reserve book to reflect our expected future capital activity, increasing our five-year program to approximately $250 million per year. With the addition of over 80 new locations (primarily in the Cardium and Viking areas), we are well positioned to further enhance our reserve book through development and exploration/appraisal activities in 2023 as we further develop our strong land base.”


With the largest development program undertaken in several years, Obsidian Energy drilled wells in all three core areas in 2022. Focused on delineating our substantial land position and expanding our opportunity base, we renewed activity in Viking and Peace River and increased our reserve base through extensions, step-out wells, and new exploration/appraisal drilling. We also increased our Peace River land position during the year, providing additional potential Bluesky locations to our portfolio. These activities, combined with significantly improved commodity price forecasts compared to 2021, had a significant impact on our reserve evaluation.

  • Reserves NPV10 increased over 2021 levels as follows:
    • PDP: 38 percent increase to $1.6 billion.
    • 1P: 49 percent increase to $2.1 billion.
    • 2P: 54 percent increase to $2.8 billion.
  • We replaced 144 percent of 2022 production on a PDP basis, 214 percent on a 1P basis and 393 percent on a 2P basis.
    • Our drilling program combined with technical revisions generated reserves replacement of 2022 production of 113 percent for PDP, 177 percent for 1P and 347 percent for 2P, excluding the effects of acquisition and disposition activity and commodity price changes from year-end 2021.
  • Our optimization capital program continued to deliver strong results for the fourth year in a row, successfully adding 2.3 mmboe of PDP reserves through capital expenditures of $13.3 million, providing a compelling PDP reserve addition cost of $5.74 per boe.
  • Future development capital (“FDC“) was added to appropriately adjust the undeveloped reserves and generate a five-year program of approximately $250 million per year.
    • Finding and development (“F&D“) costs including changes in FDC were $20.48/boe for PDP, $26.88/boe for 1P and $19.21/boe for 2P.
    • Development and acquisition (“FD&A“) costs including changes in FDC were $20.53/boe (PDP), $26.63/boe (1P) and $19.06/boe (2P).
  • The strength and profitability of our assets was demonstrated through 2022 recycle ratios of 2.4x for PDP, 1.9x for 1P and 2.6x for 2P, based on our expected 2022 operating netback of $49.82/boe and F&D costs (including changes in FDC).
  • Our total undeveloped proved plus probable reserve locations increased by over 80 new net locations to 311 total net locations booked (including 236 net locations in the Cardium, 22 net locations in the Bluesky, 2 net locations in the Clearwater, 49 in the Viking, one Devonian and one Mannville).
    • These locations are booked with a highly achievable total FDC of $1,255 million (approximately $250 million per year).
  • Obsidian Energy maintains a strong reserve life index (“RLI“) of approximately 6.8, 9.9 and 13.3 years on a PDP, 1P, and 2P basis, respectively.


GLJ conducted an independent reserves evaluation of 100 percent of our reserves effective December 31, 2022, using a four-consultant average (“IC4“) of forecast commodity prices and assumptions at December 31, 2022. This evaluation was prepared in accordance with definitions, standards, and procedures set out in the Canadian Oil and gas Evaluation Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101“). Reserves included below are company share gross reserves which are the Company’s total working interest reserves before the deduction of any royalties and excluding any royalty interests payable to the Company. The numbers in the tables below may not add due to rounding.

Summary of Reserves1
As at December 31, 2022

Light &
Medium Oil
Heavy Oil
& Bitumen
Natural Gas
Natural Gas
Barrel of Oil
Reserve Category(mmbbl)(mmbbl)(mmbbl)(bcf)(mmboe)
Developed producing31.28.57.3175.376.2
Developed non-producing0.
Total Proved56.610.312.1285.0126.5
Total Probable23.35.15.0123.654.1
Total Proved plus Probable79.915.517.1408.6180.6

(1) Reserves are shown on a gross working interest basis.

Reserves Reconciliation – Total Proved

Light &
Medium Oil
Heavy Oil
& Bitumen
Natural Gas
Natural Gas
Barrel of Oil
Reconciliation Category(mmbbl)(mmbbl)(mmbbl)(bcf)(mmboe)
Total Proved
December 31, 202155.411.39.6224.4113.7
Infill Drilling0.
Improved Recovery0.
Technical Revisions(4.0)(0.8)
Economic Factors1.
December 31, 202256.610.312.1285.0126.5

Reserves Reconciliation – Total Proved Plus Probable

Light &
Medium Oil
Heavy Oil
& Bitumen
Natural Gas
Natural Gas
Barrel of Oil
Reconciliation Category(mmbbl)(mmbbl)(mmbbl)(bcf)(mmboe)
Total Proved Plus Probable
December 31, 202169.515.812.8297.5147.8
Infill Drilling2.
Improved Recovery0.30.10.3
Technical Revisions(4.0)(1.4)
Economic Factors1.90.60.410.84.8
December 31, 202279.915.517.1408.6180.6

Summary of Before Tax Net Present Values
As at December 31, 2022(1)

Net Present ValuesDiscount Rate
$ millionsUndiscounted5 Percent10 Percent15 Percent20 Percent
Developed producing1,9941,8811,5791,3541,193
Developed non-producing2217141110
Total Proved3,3382,7262,1421,7451,470
Total Probable1,9911,046653451333
Total Proved plus Probable5,3283,7722,7942,1961,803

(1) The December 31, 2022, reserve net present values include only active Obsidian Energy existing well, facility, and pipeline decommissioning liability estimates, which totals $28 million NPV10 (2021 – $22 million).

Future Development Capital
As at December 31, 2022

$ millionsTotal ProvedTotal Proved
Plus Probable
2028 and subsequent99
Total, Undiscounted9801,255
Total, Discounted @ 10%769979

F&D and FD&A Costs
As at December 31, 2022

($ millions, except as noted)Proved Developed
Total ProvedTotal Proved
Plus Probable
Exploration and development capital expenditures314.8314.8314.8
Total change in FDC11.3324.1523.5
F&D capital, including total change in FDC326.1639.0838.3
Reserve additions, including revisions (mmboe)15.923.843.6
F&D per boe20.4826.8819.21
($ millions, except as noted)Proved Developed
Total ProvedTotal Proved
Plus Probable
F&D capital, including total change in FDC326.1639.0838.3
Acquisitions, net of dispositions4.64.64.6
Acquisitions, FDC
Dispositions, FDC(4.3)(4.3)
FD&A capital, including total change in FDC330.7639.2838.6
Reserve additions, including revisions and
acquisitions (mmboe)
FD&A per boe20.5326.6319.06

(1) Capital expenditures are unaudited.

F&D Costs by Year

($/boe)2022202120203-Year Average
F&D costs, including total change in FDC1
Proved developed producing20.489.579.4113.74
Total proved26.8813.683.3217.29
Total proved plus probable19.2110.2711.1915.51
FD&A costs, including total change in FDC2
Proved developed producing20.539.079.7713.70
Total proved26.6312.873.3916.63
Total proved plus probable19.069.6211.5014.84

(1) The calculation of F&D includes the change in FDC and excludes the effects of acquisitions and depositions.
(2) The calculation of FD&A includes the change in FDC and includes the effects of acquisitions and dispositions.

Summary of Pricing and Inflation Rate Assumptions

As at December 31, 2022(1)

Canadian LightNatural Gas
WTISweet CrudeAECO-CExchange Rate
IC4Cushing, Oklahoma40° APISpot

(1) Prices escalate at two percent after 2033, with the exception of foreign exchange which stays flat.
(2) Pricing forecasts utilized IC4 pricing (GLJ, Sproule & Associates Ltd., McDaniel & Associates Consultants and Deloitte Resource Evaluation & Advisory).

The financial and operating information in this news release is based on estimates and is unaudited. Some of the terms below do not have standardized meanings. Further detail can be found in the “Oil and Gas Advisory” section contained in this release. Additional reserve information as required under NI 51-101 will be included in our Annual Information Form as at December 31, 2022 which will be filed on SEDAR, EDGAR, and posted to our website once we file our year-end 2022 financial documents.


The Company continues to focus our hedging program on near term WTI positions to protect cashflow given our first half capital program. As at January 27, 2023, the following financial oil and gas contracts are in place on a weighted average basis:

WTI Oil Contracts

TypeRemaining TermVolume
Bought Put
Price (C$/bbl)
Sold Call
Price (C$/bbl)
Swap Price (C$/bbl)
WTI CollarOctober 202210,000109.75130.07
WTI SwapNovember 20221,950123.97
WTI CollarNovember 20227,000106.07126.77
WTI CollarDecember 20222,000105.00130.20

AECO Natural Gas Contracts

TypeRemaining TermVolume
Swap Price
AECO SwapOctober 202226,0654.74
AECO SwapDecember 2022 – March 202314,9766.18
AECO SwapApril 2023 – October 202344,0733.63


In association with this release, our Interim President and CEO, Mr. Stephen Loukas and other members of management will host a webcast presentation online on Tuesday, January 31, 2023, at 9:30 a.m. Mountain Standard Time (11:30 a.m. Eastern Standard Time) (the “Presentation“).

The Presentation will be broadcast live on the Internet and may be accessed either through our website or directly at the webcast portal. Those who wish to listen to the Presentation via phone should connect five to 10 minutes prior to the scheduled start time through the following numbers:

Canada / USA:1-800-319-4610 (toll-free)

A question-and-answer session will be held following the Presentation. If you wish to submit a question to the Company, participants can do so ahead of time after registering on the webcast portal on the Intranet or by emailing questions to [email protected]. The updated Presentation will be available for replay following the webcast on our website,


We intend to release our fourth quarter and full year 2022 financial and operational results before North American markets open on February 23, 2023. In addition, the 2022 management’s discussion and analysis and the audited 2022 consolidated financial statements will be available on our website at, on SEDAR at, and on EDGAR at on or about the same date.



This news release contains a number of oil and gas metrics, including “F&D costs”, “FD&A costs”, “Operating netback”, “Recycle Ratio” and “RLI” which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics are commonly used in the oil and gas industry and have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.

F&D costs are the sum of capital expenditures incurred in the period, plus the change in estimated future development capital for the reserves category, all divided by the change in reserves during the period for the reserve category. F&D costs exclude the impact of acquisitions and divestitures.

FD&A costs are the sum of capital expenditures incurred in the period for the reserves category and including the impact of acquisition and disposition activity, all divided by the change in reserves during the period for the reserve category.

Operating netback is the per unit of production amount of revenue less royalties, net operating expenses and transportation expenses.

Recycle Ratio is calculated by dividing the operating netback by the F&D costs for the year. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves.

RLI is calculated as total Company gross reserves divided by GLJ’s forecasted 2023 production for the associated reserve category.

Under NI 51-101, proved reserves estimates are defined as having a high degree of certainty to be recoverable with a targeted 90 percent probability in aggregate that actual reserves recovered over time will equal or exceed proved reserve estimates. For proved plus probable reserves under NI 51-101, the targeted probability is an equal (50 percent) likelihood that the actual reserves to be recovered will be greater or less than the proved plus probable reserve estimate. The reserve estimates set forth above are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

Barrels of oil equivalent (“boe“) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.


Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery. Readers are cautioned that short term rates should not be relied upon as indicators of future performance of these wells and therefore should not be relied upon for investment or other purposes. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered preliminary until such analysis or interpretation has been completed.


OilNatural Gas
APIAmerican Petroleum InstituteAECOAlberta benchmark price for natural gas
bblbarrel or barrelsmcfthousand cubic feet
bbl/dbarrels per daymmcfmillion cubic feet
boebarrel of oil equivalentbcfbillion cubic feet
boe/dbarrels of oil equivalent per daymmcf/dmillion cubic feet per day
MSWMixed Sweet BlendNGLnatural gas liquids
mmbblsmillion barrels
mmboemillion barrels of oil equivalent
WCSWestern Canada Select
WTIWest Texas Intermediate


Throughout this news release and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position, and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS“) and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss) and cash flow from operating activities as indicators of our performance.

Non-GAAP Financial Measures

The following measures are non-GAAP financial measures: FFO; net debt; net operating costs; and FCF. These non-GAAP financial measures are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of these measures, how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures.

Non-GAAP Ratios

The following measures are non-GAAP ratios: net debt to funds flow from operations, which uses net debt and funds flow from operations as a component; and net operating costs ($/boe), which uses net operating costs as a component. These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of these non-GAAP ratios, how these non-GAAP ratios provide useful information to an investor, and the additional purposes, if any, for which management uses these non-GAAP ratios.

Supplementary Financial Measures

The following measure is a supplementary financial measures: general and administrative costs ($/boe). See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of this measure.


This release contains future-oriented financial information (“FOFI“) and financial outlook information relating to the Company’s prospective results of operations, operating costs, expenditures, production, FFO, adjusted FFO, FCF, net operating costs, and net debt, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth below under “Forward-Looking Statements“. The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, such FOFI, or if any of them do so, what benefits the Company will derive therefrom. The Company has included this FOFI to provide readers with a more complete perspective on the Company’s business as of the date hereof and such information may not be appropriate for other purposes.


Certain statements contained in this document constitute forward-looking statements or information (collectively “forward-looking statements“) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “budget”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “objective”, “aim”, “potential”, “target” and similar words suggesting future events or future performance. In addition, statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: our 2023 capital plan and associated guidance including production and associated weighting, net operating costs, general & administrative costs, FFO, FCF (prior to NCIB), net debt (prior to NCIB) and net debt to FFO; our intentions regarding a NCIB and the belief that our shares our undervalued; our ability to deliver on production growth and FCF; our 2023 strategy in regard to development and exploration/appraisal capital, continued debt reduction and return of capital to shareholders while also preserving acquisition optionality; our expectations for drilling, locations and on production dates; our ability to optimize our program based on various results achieved; how we plan to lower capital and help mitigate the impact of inflation and higher service costs; our pursuit to increase our debt capacity and the impact that has on the NCIB, our belief in our ability to complete the NCIB and make an offer on the Notes if necessary, per the terms and conditions, based on certain underlying assumptions; our expected timing on certain debt targets; that we are well positioned to further develop our reserve book through development and exploration/appraisal activities in 2023; the hosting of the Presentation and subsequent posting on our website; that additional reserve information, as required under NI 51-101, will be included in our Annual Information Form which will be filed on SEDAR, EDGAR and our website on or about February 23, 2023; our expected RLIs; and our hedging program.

With respect to forward-looking statements contained in this document, the Company has made assumptions regarding, among other things: that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than stated herein (provided that, except where otherwise stated, the forward-looking statements contained herein do not assume the completion of any transaction); the impact of regional and/or global health related events, including the ongoing COVID-19 pandemic, on energy demand and commodity prices; that the Company’s operations and production will not be disrupted by circumstances attributable to the COVID-19 pandemic and the responses of governments and the public to the pandemic; global energy policies going forward, including the ability of members of OPEC, and other nations to agree on and adhere to production quotas from time to time; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic (including the Alberta Site Rehabilitation Program) or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; our ability to execute our plans as described herein and in our other disclosure documents and the impact that the successful execution of such plans will have on our Company and our stakeholders; future capital expenditure and decommissioning expenditure levels; future operating costs and general & administrative costs; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future crude oil, natural gas liquids and natural gas production levels; future exchange rates, inflation rates and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events, such as wild fires and flooding, infrastructure access and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to continue to extend the revolving period and term out period of our credit facility, our ability to maintain the existing borrowing base under our credit facility, our ability (if necessary) to replace our syndicated bank facility and our ability (if necessary) to finance the repayment of our Notes on maturity; and our ability to add production and reserves through our development and exploration/appraisal activities.

Although the Company believes that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the possibility that we change our 2023 capital plans in response to internal and external factors, including those described herein; the possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full, and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize; the possibility that the Company is unable to complete one or more of the potential transactions being pursued, on favorable terms or at all; the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection with the COVID-19 pandemic and other regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, including the ongoing COVID-19 pandemic, and the responses of governments and the public to the pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that there is another significant decrease in the valuation of oil and natural gas companies and their securities and in confidence in the oil and natural gas industry generally, whether caused by a resurgence of the COVID-19 pandemic, the worldwide transition towards less reliance on fossil fuels and/or other factors; the risk that the COVID-19 and/or other pandemics adversely affects the financial capacity of the Company’s contractual counterparties and potentially their ability to perform their contractual obligations; the possibility that the revolving period and/or term out period of our credit facility and the maturity date of our Notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew or refinance our credit facilities on acceptable terms or at all and/or finance the repayment of our Notes when they mature on acceptable terms or at all and/or obtain debt and/or equity financing to replace one or all of our credit facilities and Notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our Notes; the possibility that we are forced to shut-in production, whether due to commodity prices decreasing, extreme weather events or other factors; the risk that OPEC and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for crude oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; the risk that our costs increase significantly due to inflation, supply chain disruptions and/or other factors, adversely affecting our profitability; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires and flooding); the risk that wars and other armed conflicts adversely affect world economies and the demand for oil and natural gas, including the ongoing war between Russia and Ukraine; the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company’s ability to obtain financing on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments and consumers to the ongoing COVID-19 pandemic and/or public opinion and/or special interest groups. Additional information on these and other factors that could affect Obsidian Energy, or its operations or financial results, are included in the Company’s Annual Information Form (See “Risk Factors” and “Forward-Looking Statements” therein) which may be accessed through the SEDAR website (, EDGAR website ( or Obsidian Energy’s website. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

Unless otherwise specified, the forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

Obsidian Energy shares are listed on both the Toronto Stock Exchange in Canada and the NYSE American in the United States under the symbol “OBE”.

All figures are in Canadian dollars unless otherwise stated.


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Offshore Energies UK (OEUK) today warns that more action is needed from both government and industry to support supply chain companies in playing a critical role in sustaining oil and gas activity while helping to build the UK’s low-carbon future energy systems.

OEUK’s new Supply Chain report calls on government to provide a stable regulatory and fiscal framework which gives the supply chain a predictable and attractive business environment to continue investing in the UK’s energy security. It also asks government to work closely with industry to inform decision-making and policies which ensure suppliers have better visibility and certainty of opportunity and improve their ability to invest in technology development, skills and innovative ways to deliver a net zero future.

The report encompasses the hundreds of firms of all sizes providing the array of products and services operators require to run North Sea oil and gas installations and whose skills help ensure UK energy security. The report comes at a time when OEUK is urging the sector to develop and maintain strong business relationships with the supply chain with priority areas including fair allocation of contractual risk and reward and encouraging innovative ways of working.

Katy Heidenreich, OEUK’s Supply Chain and People Director said

“Our offshore energy supply chain is an amazing and strategic national asset. In 2022, these companies helped the UK oil and gas industry contribute £28 bn gross value added (GVA) to the economy. Over the next decade, this sector plans to spend over £200bn, providing jobs for over 200,000 people, as it expands low-carbon energy production.

“A world-leading, diversifying energy supply chain is developing, but through engaging with our members and feedback from two surveys, we know they face major headwinds on a number of fronts.  Our sentiment survey revealed there’s a lack of confidence across the sector. Around a fifth of supply chain companies surveyed said poor visibility of the future UK projects is affecting their ability to plan and service activity both in the near and longer term, a problem that OEUK is working with industry to address.”

The report outlines how the UK’s energy supply chain ranges from major contractors with a global presence delivering integrated oilfield services to small-scale local firms with specialist capabilities. Many firms are evolving to support emerging energies including offshore wind, carbon capture & storage and hydrogen production.  In 2021, Government recognised the supply chain’s critical role in the North Sea Transition Deal, which aims to accelerate the shift to a low-carbon energy mix, reduce greenhouse gas emissions and build a UK-based low-carbon supply chain with globally exportable expertise.

The businesses surveyed by the new report support the jobs of around 80% of the 200,000 people employed by the offshore sector. This supply chain is spread across the UK from Shetland to Southampton and Great Yarmouth to Morecambe Bay, with low-carbon energy hubs emerging in areas including Teesside and Humberside.

Katy Heidenreich commented:

“We are seeing businesses battling to control inflation and at a national level, we know Brexit has had an impact, making it harder to import and export goods and take advantage of business opportunities within EU countries. Most recently companies or all sizes in our sector have been hit by the uncertainty created by the increase of the energy profits levy (EPL)when we were already the most highly taxed industry in the UK.”

OEUK’s report includes feedback from its Working as One survey, which assesses how the sector is treating its supply chain. Based on the industry’s Supply Chain Principles, which set out what good procurement behaviours look like, the survey pinpoints areas where the sector can improve in areas including the prompt payment of invoices, fair allocation of risk and reward between buyer and supplier, plus openness to supply-chain-led innovation. All three of these comprise the focus of work groups OEUK has established to ensure industry addresses these issues.

Ms Heidenreich said:

“Our UK supply chain is critical to our efforts to deliver a carbon neutral basin by 2050 and our new report highlights the scale of the challenge ahead. Both industry and government have a vital role in ensuring this strategic national asset can continue to sustain current demand for oil and gas energy, while building the capability to deliver a home-grown low carbon energy economy.

“Failing to act now means we will see investment, equipment and resources being diverted overseas, so the race is on. We must ensure we work together to create an industry-wide solution to this challenge. We are stepping up our work with government to make sure the UK is competitive as a destination for manufacturing and investment and sharpening efforts to help ensure our supply chain captures at least half of the project activity ahead.

“Boosting our supply chain will enable us to develop engineering, manufacturing, services and technology expertise to support the evolving low carbon energy mix and create a globally competitive energy supply chain of international repute. The time to act is now.”

The report is available at

Key facts:

-Input to the Working as One survey was provided by firms of all sizes from oil and gas operators, major contractor firms and small to medium enterprises (SMEs) which collectively represent 98% of total production activity on the UK Continental Shelf

-Supply chain contract margins are being eroded by inflation with Consumer Prices Index (CPI) rising to 11% in 2022.

-81% of companies suffered higher administrative costs following Brexit.

– Almost all OEUK supply chain members reported up to 20% increase in operating costs since early 2021.


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Big Oil Saw Record $199Bn Profits In 2022 But 2023 Will Be Different

ExxonMobil, Chevron, Shell, TotalEnergies, and BP reaped almost $200 billion collectively last year but fears of an economic slowdown, plunging natural gas prices, cost inflation and uncertainty over China’s re-opening are dimming the outlook for 2023.

The five companies are expected to report $198.7 billion in combined 2022 profit in the coming days, 50% higher than the previous annual record set more than a decade ago, according to data compiled by Bloomberg.

The tsunami of cash generated by the group over the past 12 months means the industry can sustain dividend increases and share buybacks, analysts said. Crucially for shareholders, management teams held off on spending increases as commodities boomed, in stark contrast with previous cycles.

Instead, they opted to repay debt and swell investor returns: Chevron stunned shareholders with a $75 billion stock-repurchase announcement on Wednesday — five times the company’s current annual outlay for buybacks.

“Commodity prices are down across the board relative to record 2022 levels, but it still looks like it’s going to be a very strong year,” said Kim Fustier, head of European oil and gas research at HSBC Holdings Plc. “It could very well be the second-best year in history for overall distributions and share buybacks.”

Fourth-quarter earnings, while one of the three highest on record, will likely be reduced by lower oil and gas prices. Guidance from Exxon and Shell suggests refining margins held up more than expected. Chevron is scheduled to kick off Big Oil earnings season at 6:15 a.m. New York time on Jan. 27.

While the pullback in energy prices has been sharp — crude and gas are lower now than when Russia invaded Ukraine in late February — it may help put the global economy and energy companies on a firmer long-term trajectory. Lower energy costs are helping take some of the sting out of inflation, easing pressure on central banks to carry on raising interest rates.

Across the board, the biggest oil explorers are focused on funneling record profits back to shareholders while keeping a check on spending. That strategy has provoked political attacks from Brussels to Washington DC by politicians wanting more supply to bring down prices.

Shares of the five supermajors are up at least 18% since Russia’s invasion despite an 11% drop in the price of crude. The top ten performers in the S&P 500 last year were all energy companies, with Exxon advancing 80% for its best annual performance on record. Oil companies now generate about 10% of the index’s earnings, despite making up just 5% of its market value, according to data compiled by Bloomberg.

“Investors are attracted to a lot of the characteristics this sector has to offer now,” said Jeff Wyll, a senior analyst at Neuberger Berman Group LLC, which manages about $400 billion. “It was trying to be a growth sector and that failed. It reinvented itself as a cash distribution and yield play, which is attractive in this environment.”

Key to the oil majors’ fortunes is whether they can stick to shareholder-return pledges made last year during the months-long run up in commodity prices.

“I expect them to maintain those shareholder returns,” said Noah Barrett, lead energy analyst at Janus Henderson, which manages about $275 billion. “The base dividends are incredibly safe at almost any oil price, balance sheets are in good shape and I expect them to continue buying back shares.”

Investors are also keen to hear executives sticking to the mantra of capital discipline. It was the huge growth in spending over much of the last decade that eroded shareholder returns and left the sector vulnerable to oil crashes in 2016 and 2020.

“There is still an aversion to big capital expenditure increases, period,” Wyll said. “The problem the sector got into in the past is doing too many megaprojects at one time. Now it’s much more focused.”

So far that discipline appears to be holding. Exxon and Chevron both raised spending targets for this year but the increases were driven largely by inflation rather than ramping up long-term growth projects. Despite a 500% increase in oil prices from early 2020 to mid-2022, global oil and gas capital spending fell in real terms, Goldman Sachs Group Inc. said in a Jan. 9 note.

One crucial question for executives this earnings season is how much they’re reserving for European windfall-profit taxes. Exxon estimated a $2 billion charge but is pursuing legal action. Shell says its 2022 bill may total $2.4 billion.

Earlier this month, Exxon indicated that fourth-quarter earnings took a hit of about $3.7 billion from weaker oil and gas prices compared with the previous quarter, but analysts noted that refining margins were much stronger than expected. The US oil giant reports on Jan. 31.

Shell, whose newly appointed Chief Executive Officer Wael Sawan will host his first earnings call, also noted stronger refining and pointed to a rebound in gas trading. TotalEnergies pointed to similar trends in a Jan. 17 statement.

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Analyst takes: 11 energy trends you should know about in 2023 | Enverus

With the first month of 2023 almost in the books, we wanted to take a moment to look back at some of the key analyst takes on energy trends published by our Enverus Intelligence® | Research (EIR) team at the end of 2022, so you can confidently assess how they may affect your business decisions going forward.

Read on to stay ahead of the game when it comes to staying informed about current and future energy opportunities!

Oil prices to remain high through 2023: A constructive view driven by policy, investment and geopolitical factors (Dec. 22, 2023)

EIR’s constructive view on oil prices is driven by an interplay of policy, investment and geopolitical drivers, which will keep global oil supply tight through 2023 and beyond, pinning oil prices toward the top end of the post-COVID-19 range. High prices amid a spluttering global economy engender longer-term risks for oil however, since counter-cyclical high prices could deepen and prolong an economic recession, testing consumers’ tolerance until more violent demand destruction occurs.

Natural gas prices drop as warmer temperatures return: Will production freeze-offs repeat February 2021 event? (Dec. 19, 2022)

The prompt NYMEX contract has fallen more than 10% today to below $6.00/MMBtu as warmer temperatures have become more established for the latter part of the 15-day forecast. Near-term temperatures are expected to trend well below normal and bottom out around Christmas time. All eyes will be on the severity of production freeze offs and whether they will rival the February 2021 event which led to a 7 Bcf/d month-over-month decline in Lower 48 dry gas production. The Permian was the largest contributor to this decline with Midland, Texas, during the February 2021 event, recording about nine consecutive days of below freezing temperatures with the lowest daily mean temperature of 7.4 degrees Fahrenheit. Current forecasts are not nearly as dire and only show about three consecutive days of below freezing temps with Friday’s forecast of 14.7 degrees Fahrenheit being the coldest.

OPEC+ to rollover oil supply targets as group watches impact of EU sanctions, G7 proposals and Chinese demand (Dec. 2, 2022)

The OPEC+ oil producers are set to rollover their oil supply targets when they meet virtually this weekend, following on from the 2 MMbbl/d nominal cut they announced in October. Despite Saudi comments over the last month that further cuts could be made in order to stabilize balances that are under siege from worsening recessionary indicators, the producer group is now planning to allow more time to establish the impact of the EU sanctions on Russian oil exports, the G7-proposed oil price cap on Russian exports and a better sense of the outlook for Chinese oil demand in 2023 as Beijing’s COVID policies remain in flux. While there is no date for a subsequent meeting, the OPEC president can call a meeting at any time to discuss further cuts if they are needed. A likely OPEC+ rollover does not in EIR’s view mark a departure in OPEC oil supply policy that aims to keep global stocks well below the 5YA and pin Brent around $90/bbl.

OPEC’s denial of oil output hike report highlights finely balanced markets and relevance of Saudi Arabia’s influence (Dec. 2, 2022)

Yesterday’s Wall Street Journal report suggesting that OPEC+ would consider an oil output hike of 500 Mbbl/d at its next meeting was enough to cloak OPEC’s recent pivot to supply management in a large cloud of doubt. With financial markets already on edge over recession and the pace of monetary tightening, oil slid fast to test lows not seen since January, before the Ukraine war broke out. But Saudi Arabia didn’t hesitate to correct the record. Within hours, the energy minister had made an unusual formal statement denying the report, reiterating the existing cuts and pointing out that OPEC+ could cut deeper if needed to help balance markets. Oil prices responded by erasing most of the earlier losses. For a group of producers who have long preferred issuing smoke signals through unnamed sources, refuted reporting is hardly new. But it does underline two important conclusions for market participants at a febrile moment for oil markets. First, what Saudi Arabia says and does on oil supply is still highly relevant to global oil balances. Second, this oil market is finely balanced, and while EIR still see structurally tight supply as bullish heading into 2023, we also acknowledge the risks of a more violent collapse in demand. EIR is not forecasting that, but it is a tail risk.

Johan Sverdrup field boosts Norway’s oil production: Equinor’s Phase 2 development on schedule (Dec. 15, 2022)

Equinor has started production from Phase 2 of the Johan Sverdrup field on schedule. The development will boost oil production from 500 Mbbl/d to 720 Mbbl/d, contributing about a third of Norwegian oil production. EIR expects the field to increase 2023 Norwegian production to ~2.1 MMbbl/d. Norway’s oil production growth is key to offsetting output declines in EIR’s NOCAR region (not OPEC, Canada, U.S. or Russia).

APA and partner TTE discover non-commercial well in northern Block 58, oil resource below FID threshold in eastern Block 58 (Nov. 28, 2022)

APA announced a non-commercial discovery on the Awari well (operated by 50-50 partner TTE), which follows the Bonboni well as the second such result in the northern portion of Block 58. In the western portion of the block, gas-commerciality snags are deterring FID; in the east, oil resource from several black oil discoveries appears below the FID threshold (especially after considering operator TTE’s cost carry). EIR estimates the JV requires finding an additional 300 MMbbl of black oil before sanctioning its first oil development hub in the eastern part of Block 58 between Sapakara South and Krabdagu.

West Coast gas market tightness worsened by cold weather and maintenance: Canadian operators stand to benefit from record-breaking prices (Dec. 15, 2022)

Short term issues like colder than normal weather and maintenance on El Paso Natural Gas and Gas Transmission Northwest (GTN) have exacerbated gas market tightness that was already prevalent on the West Coast gas after the Pacific Gas and Electric storage reclassification in the summer of 2021. Malin basis settled at $26.10/MMBtu recently, with the potential for more record shattering basis prints to come as West Coast temperatures are expected to plunge over the next five days. Canadian gas operators TOU, ARX, OVV and NVA all hold firm transportation on the GTN pipeline, which provides exposure to these historic prices.

Net Power’s innovative oxy-combustion technology poised to revolutionize low-cost, clean power generation with upcoming IPO? (Dec. 15, 2022)

Net Power’s (NPWR) announced IPO via SPAC will be a positive step forward in funding the company as it aims to develop its first utility scale power plant. NPWR developed an innovative technology that generates reliable, low-cost, clean power from natural gas using an oxy-combustion process to inherently capture CO2 emissions. The nature of oxy-fuel combustion significantly reduces the cost of capture but increases parasitic loads. Company disclosure suggests they can capture CO2 around $10/tonne, well below our average breakeven estimate of $65/tonne for similar sized natural gas plants retrofitted with MEA capture technology. However, these aren’t quite apples to apples comparison, as Net Power’s technology cannot be retrofitted onto existing plants. Using the 45Q carbon capture tax credits to offset fuel and operating costs, NPWR suggests it can operate at a cost of only ~$4/MWh, meaning it could compete with thermal power assets for dispatch. NPWR also calculates a $21 levelized cost of electricity (LCOE) at $3.50/MMbtu gas, which competes for capital with new wind and solar projects. However, EIR expects carbon transportation and storage to be major challenges for this technology in regions that are less friendly to pipelines. If their claimed power generation capacities, capture costs and LCOE prove true then this technology could be a game changer for low carbon, baseload power generation.

E3 Lithium secures funding for pioneering Direct Lithium Extraction in Alberta: Commercialization expected in 2026 (Nov. 18, 2022)

E3 Lithium, who is pioneering Direct Lithium Extraction (DLE) in Alberta, announced that it has received $27 million from Canada’s Strategic Innovation Fund. Although yet to be proven commercially viable, E3 Lithium has started on the path to commercialization, expected in 2026, with the completion of their first lithium evaluation well Oct. 27, 2022. At the site of their Clearwater Project, the well drilled into the Leduc Formation showed lithium concentrations in the range of 76 ppm, equal to roughly 64 grams of lithium carbonate equivalent (LCE) per barrel. With anticipated production of 20,000 tonnes of LCE per year, the project will need to flow massive amounts of water, more than 282 million barrels per year, or about 845,000 barrels per day. This will require a lot of wells. At 60,000 bbl/d per well, which EIR views as optimistic, the project will require at least 15 production wells and an equal number of injection wells.

CVX’s acquisition of Mercuria Energy’s Beyond6 highlights importance of securing CNG demand for RNG economics in the US (Nov. 22, 2022)

CVX’s acquisition of Mercuria Energy’s subsidiary Beyond6, which includes a network of 55 compressed natural gas (CNG) stations across the United States, highlights the importance of securing CNG demand to further strengthen RNG economics. Competition to gain access to transportation markets will increase as RNG project-level economics significantly improve after the passing of the Inflation Reduction Act. The Beyond6 deal is interesting as only 6% of Beyond6’s stations are in the California, the state where the maximum value for RNG occurs. Still, manure- and landfill-based biogas projects selling into transportation markets outside of California/LCFS-eligible state generate IRRs of 114% and 172% after the IRA.

Chevron’s Gorgon CCS project struggles with reservoir pressure challenges, offsets purchase suggests unforeseen reservoir heterogeneities (Nov. 17, 2022)

Chevron recently cited reservoir pressure challenges due to water management systems as the main contributor to its inability to meet targeted 2021 CO2 injection volumes at its Gorgon CCS project (1.65 Mt of CO2 injected vs. target of 4 mtpa). We believe suboptimal reservoir quality, possibly including unforeseen small scale reservoir heterogeneities, could be worsening the problem. The operator’s intention to purchase offsets suggests that the anticipated injection rates from reservoir modelling may not have accounted for such variability in the reservoir rock.

Staying ahead of the game

EIR’s analyst takes can make all the difference when it comes to your business decisions. Staying ahead of the game is paramount in this fast-paced sector, and monitoring new developments is key to success. To further stay informed on the energy industry, subscribe to EIR’s LinkedIn page, where you’ll find more insights on what’s in store for 2023 and beyond. We look forward to providing more valuable insight into navigating today’s ever-changing energy landscape.

About Enverus Intelligence Research
Enverus Intelligence Research, Inc. is a subsidiary of Enverus and publishes energy-sector research that focuses on the oil and natural gas industries and broader energy topics including publicly traded and privately held oil, gas, midstream and other energy industry companies, basin studies (including characteristics, activity, infrastructure, etc.), commodity pricing forecasts, global macroeconomics and geopolitical matters. Enverus Intelligence Research, Inc. is registered with the U.S. Securities and Exchange Commission as a foreign investment adviser.

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Cyprus Gas Ambitions: From Dreams To Reality In 2023?

Presidential elections slated for 5 February are set to crown a winner who could write their name in Cyprus’ history books as the President who oversaw the birth of a gas export industry. For more than a decade the Mediterranean island’s gas dreams have all but hinged on the fate of its first discovery, December 2011’s 4.5tcf Aphrodite. But with a string of finds since 2018’s Calypso on Block 6, there is renewed hope that 2023 will see decisive moves to finally get gas out of the ground.

Following Calypso’s discovery by Italian firm Eni in February 2018 came US major ExxonMobil’s Glaucus find on Block 10 twelve months later. Then Eni, which operates Block 6 with 50% alongside French major TotalEnergies (50%), came up trumps again last year, making back-to-back discoveries with 2.5tcf Cronos and 2-3tcf Zeus (MEES, 23 December 2022).

While Eni CEO Claudio Descalzi provided an initial reserve estimate of 6-8tcf for Calypso and ExxonMobil gave an estimate of 5-8tcf for Glaucus, MEES understands that those figures were somewhat premature. Although Eni has yet to drill an appraisal well at Calypso, Exxon’s appraisal well at Glaucus last year, following which the US major made no official announcement, appeared to indicate smaller reserves than initially estimated, MEES learns.

This would appear to indicate that the carbonate play analogous to Egypt’s Zohr that has yielded the Block 6 and 10 finds in the deepwater southwest of Cyprus is more complex than first anticipated. And though Aphrodite was discovered in the Miocene or ‘Tamar Sands’ which yielded Israel’s 23tcf Leviathan and 13tcf Tamar, MEES understands that the geology here is also complex, potentially adding to development costs and as such raising the barrier to commercialization.

The Aphrodite reservoir is compartmentalized, helping explain why the latest recoverable reserves estimate (2C) of 4.5tcf is below the initial 5-8tcf estimate given by then-operator Noble Energy following the field’s late-2011 discovery (MEES, 9 January 2012).

Operator Chevron (35%), which purchased Noble in 2020, and partners Shell (35%) and Israel’s NewMed Energy (30%) are planning to drill a third well at Aphrodite (A3) during the first half of 2023. Chevron has contracted the Stena Forth drillship to drill this second appraisal well which would potentially also function as the field’s first production well (MEES, 24 June 2022). The Stena Forth currently remains on site at Chevron’s recent Nargis discovery off Egypt (MEES, 20 January). Stena’s current contract with Chevron lasts until April so presumably Aphrodite is next up, to be followed by a three-well campaign for Shell off Egypt (MEES, 20 January).

The upcoming A3 well is set to target the field’s middle chamber, which contains the largest share of overall volumes according to the current modeling of Chevron and its partners. The stakes are high: if drilling is unsuccessful Chevron may walk away from the project, MEES understands. And while the field’s complexity has played a role in the failure to move towards development, it is not the key reason holding the Aphrodite partners back.

With the Cyprus gas market currently non-existent, sanctioning development would require a gas sales export deal. Though this has yet to materialize, MEES understands that ongoing talks with Cairo have finally reached a breakthrough that could see a first gas export deal signed to supply Aphrodite gas to Egypt. Landfall would be Shell’s now underutilized WDDM facilities, adjacent to the Shell-operated 7.2mn t/y ELNG export facility at Idku, although what Egypt chooses to do with the gas will also depend on its own domestic needs.

Egypt is the obvious choice considering its proximity and its own waning gas output which slumped to a four-year low of 6.5bn cfd for 2022. With Egypt only managing to maintain substantial LNG exports last year thanks to record imports of Israeli gas (MEES, 20 January), state firm Egas is keen to tie up other regional supplies.

Aphrodite’s location also further complicates matters. It straddles the maritime border with Israel, in 1,700m water depth, increasing potential development costs. In 2019 the partners signed a revised production sharing contract with Nicosia (MEES, 8 November 2019) that outlined how they would proceed with development but they have to select their preferred development option for Aphrodite, despite Nicosia’s hopes that concept selection was to be submitted by year-end 2022.

“There is still some work to do including the A3 drill before submitting a full development plan,” a source involved in the project tells MEES. The preferred development option, MEES understands, is the construction of a 340km subsea pipeline from the field to the Shell-operated Burullus/WDDM processing facilities, at Idku, which lie directly alongside the ELNG export terminal north of Alexandria, with Egas expected to use the Aphrodite volumes to bolster its LNG exports.

The WDDM facilities have plentiful spare capacity, with WDDM output having fallen from a peak of 2bn cfd in 2008 to just 300mn cfd for 2022. Sources with knowledge of the project say a further fall to 200mn cfd this year is expected. The facilities also processed gas from BP’s Giza and Fayoum fields (WND Phase-2) until those fields’ reserves fully depleted in 2021 (MEES, 1 July 2022).

An alternative would be for gas processing to take place on a semi-submersible platform located directly above the field, enabling output to be directly tied back to ELNG, bypassing the WDDM facilities. This was long the favored option of former operator Noble. Another option that has also not been fully ruled out, MEES understands, is combining Aphrodite development with the expansion of the nearby 23tcf Leviathan gas field in Israeli waters, which is also operated by Chevron (39.66%) and partnered by NewMed (45.34% – Israeli firm Ratio has the remaining 15%).

NewMed presentation material continues to indicate as a “potential” development option a pipeline from Aphrodite hot-tapping a pipeline linking Leviathan with ELNG. While Chevron has cooled on the prospect of piping Leviathan gas to Egypt as part of that field’s expansion from 1.2bn cfd to 2.1bn cfd, the high cost of constructing a FLNG, the partners’ preferred option, could yet force a change of heart. Concept selection for Leviathan expansion is due by July this year (MEES, 9 December 2022).

It would not be unreasonable to suggest that with the timeframe of both fields’ concept selection lining up, and with Chevron and NewMed partners at both projects, a tie-up could be on the cards.

“Until we publish the concept selection, nothing is off the table, though a co-development is not the leading concept currently,” the Aphrodite source tells MEES.

Spare capacity at the WDDM processing facilities in Egypt, Shell’s involvement in both Aphrodite and at ELNG (along with WDDM) and a breakthrough in negotiations with Cairo may ultimately be the over-riding factor in the decision-making process.

Shell presentations of upcoming and planned projects continue to list Aphrodite tie-back to Egypt as a ‘pre-FID option’. Whilst Shell previously gave a production figure of 125,000 boe/d (700mn cfd), it now describes the project as providing “backfill” given the ongoing steep decline in WDDM output.

With a small portion of Aphrodite (estimated at around 10%) overlapping into Israeli waters, first Cyprus and Israel will need to come to an agreement on a compensation mechanism.

While Israel and Lebanon managed to reach an (indirect) agreement on their maritime border last year, despite non-existent diplomatic relations (MEES, 28 October 2022), Cyprus and Israel, which are considered friendly states, have so far been unable to reach a unitization deal. Cyprus’ Energy Minister Natasa Pilides and her former Israeli counterpart Karine Elharrar did make progress on reaching a compromise, MEES learns, but a recent change in government in Israel may throw a spanner into the works (MEES, 6 January).

Ms Pilides is also set to depart her role as Energy Minister next month with her tenure drawing to a close and following Cypriot presidential elections, which will likely see a change in government, further complicating matters.

However, a Cypriot government official is confident that discussions will remain on course despite a change of minister. “I don’t expect any qualitative shift. Main priorities will remain. No substantial changes should be expected,” the official says. The two countries have agreed to appoint an independent expert to adjudicate the case but have yet to appoint one, though Israel’s energy ministry remains hopeful that a deal will be reached soon.

“The intended result of the negotiations will be the signing of an Intergovernmental Agreement, that will detail, inter alia, the expert procedure. We are optimistic for this to happen within a few months,” an Israeli ministry spokesperson told MEES in December.

With Aphrodite development having gone nowhere fast in the years following the field’s 2011 discovery (MEES, 10 April 2015), potentially the most significant well offshore Cyprus from a geological standpoint came not in Cypriot waters at all but in Egypt, with Eni’s August 2015 discovery of the giant Zohr field just across the Egyptian maritime border.

This launched a search for an extension of the same “Zohr-like” carbonate play on the Cypriot side of the border. And with Eni either operating or partnering TotalEnergies on the key blocks on the Cypriot side of the border, it was well placed to look for ‘more Zohr’ in Cyprus.

Though the first such well, July 2017’s Onesiphoros on Block 11 (Total 50%op, Eni 50%), only discovered sub-commercial volumes of gas it did indeed confirm the extension of the ‘Zohr’ carbonate play into Cypriot waters (MEES, 15 September 2017).

Subsequent wells by Eni with Total at Calypso, Cronos, Zeus, and by ExxonMobil with partner QatarEnergy at Glaucus and Delphine have all confirmed the existence of the carbonate play, with all but Delphine discovering gas (MEES, 1 February 2019). With significant assets across the border in Egypt, including Zohr which supplies 40% of the country’s gas output, Eni is eying fast-track development of its Block 6 discoveries, which will likely see it take advantage of the already-existing infrastructure.

One option could be tie-back to the firm’s Zohr processing facilities, which are adjacent to the 5mn t/y Segas LNG export facility at Damietta, where Eni is operator with 50%. The facilities here were built to cater to Zohr’s 3.2bn cfd nameplate capacity but water infiltration issues have resulted in Eni placing a 2.6bn cfd cap on output, providing potential spare capacity for tie-ins (MEES, 22 April 2022).

Eni has been doubling down on Egypt in recent months taking extensive new acreage, mainly situated in the north of Sinai offshore region, where along with Chevron it made the Nargis discovery and where it continues to drill the highly anticipated Thuraya well (MEES, 20 January).

FLNG has also been discussed as a potential solution for developing the gas finds in Cyprus’ southwest acreage, as Nicosia seemingly moves away from its long-stated aim of building a land-based facility on its southern coast at Vasilikos. With no official figure for reserves at Glaucus or Calypso, it may be the case that Cyprus is not sitting on the 15tcf of gas that would make a land-based project viable.

FLNG though remains an expensive option, as Chevron and its Leviathan partners have found out, and a relatively new and barely tested technology that has faced numerous challenges, something Shell can attest to following multiple shutdowns of its Prelude FLNG offshore Australia.

Eni is eying further drilling offshore Cyprus this year, following its 2022 successes. MEES understands the firm could return to drill the ‘Cuttlefish’ prospect on Block 3, having previously been blocked by Turkish warships in 2018 (MEES, 16 February 2018).

Exxon is also eying two wells this year. “One hopefully in Block 5 after seismic interpretation and one in Block 10,” an informed source tells MEES. Norway’s PGS last year shot seismic over a large portion of Block 5 and Block 10, while also covering the Egypt side of the maritime border (MEES, 1 July 2022). This is likely behind the US major’s venture to take two ultra-deep offshore blocks just across the border from its Cypriot acreage, which would form one giant conterminous area (MEES, 13 January).

As for development of Cyprus’ existing finds, decision time is looming with Chevron and its partners at Aphrodite set to drill a third well and submit concept selection in the coming months. Nicosia will be hoping for FID on Aphrodite within the next 12 months while decisions on Eni’s new gas finds may take longer. But, make no mistake, this is the closest that Cyprus has come since Aphrodite’s late 2011 discovery to realizing its lofty gas ambitions.

Time of course, is of the essence, with the window for developing its gas discoveries slowly closing as the EU pushes member states to reduce their carbon footprints. Russia’s February 2022 invasion of Ukraine appears to have bought Cyprus some time though, with the EU now firmly focusing on diversifying its gas supplies and potentially extending the deadline for its net-zero carbon mandate.

While the preferred destination for its gas appears to be non-EU member Egypt, the two LNG export facilities here do provide a route to Europe. 2022 saw Europe overtake Asia as the top destination for Egyptian LNG (MEES, 13 January), while the EU last year signed an MoU with Israel, which supplies Egypt with piped gas, and Cairo, that earmarks more LNG for Europe (MEES, 17 June 2022).

Speaking this week to Bloomberg, Egypt Petroleum Minister Tarek El Molla said that Cairo is “working on boosting cooperation with Italy to facilitate exporting LNG to European markets.”

Cyprus’ gas ambitions have faced hurdles at nearly every step of the way. Around every corner and with the prospect of new drilling, Turkey has tended to pop its unwanted head. Ankara argues that any gas discovered offshore Cyprus should be shared between the internationally-recognized Greek Cypriot government in the south and the Turkish-controlled north (TRNC).

Not only did threats from Turkish warships block Eni from drilling the ‘Cuttlefish’ prospect in 2018 but it has harassed drillships operating in Cypriot waters at every opportunity, shooting seismic south of the island and drilling wells that lie within its dubiously claimed continental shelf (MEES, 9 October 2020).

That said, with Ankara racing to develop its own Sarkaya gas discovery in the Black Sea, Turkey has remained uncharacteristically quiet regarding Eni’s Cronos and Zeus discoveries.

And, while energy policy will remain unchanged, Cyprus’ foreign policy may alter with a new president.

Favorite to win next month’s Cypriot elections remains former foreign minister Nicos Christodoulides who has been backed by numerous pro-partition parties. If Mr Christodoulides is elected on 12 February, that could pave the way for the legal partition of the island, in turn greatly increasing the likelihood that Ankara annexes the TRNC, creating a hard border on the island.

Though the permanent division of Cyprus would seemingly reduce the rationale for Turkish claims to waters south of the island, Turkey is a non-signatory to the UN Convention on the Law of the Sea (UNCLOS) and at times its claims have typically been outside international norms.

That said, with Turkey the top destination for Egyptian LNG in 2022, it is certainly a possibility that ‘Cypriot gas’ could indirectly end up in Turkey later this decade.

Key Cyprus Offshore Acreage & Drilling Activity

Key Cyprus Offshore Acreage & Drilling Activity

Tables included

Cyprus Gas Discoveries

AphroditeDec11Chevron(35%), Shell (35%), NewMed (30%)124.5tcf2 wells drilled to date. A3 well and concept selection due in 1H23
CalypsoFeb18Eni (50%), Total (50%)61-2tcf1 well drilled. No plans set for appraisal drilling
GlaucusFeb19ExxonMobil (60%), QatarEnergy (40%)103-4tcfAppraisal drilling has downgraded initial 5-8tcf reserves announcement
CronosJun22Eni (50%), Total (50%)62.5tcfEni & Total are eying fast-track development
ZeusAug22Eni (50%), Total (50%)62-3tcfEni & Total are eying fast-track development

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Chevron reports record-breaking profits for 2022 – Oil & Gas 360

2022 Third Quarter Highlights:

  • Net cash from operating activities of approximately $850 million, adjusted cash flows from operations, a non-U.S. GAAP metric defined below, of approximately $700 million and oil and gas capital investments of approximately $260 million.
  • Approximately $440 million of adjusted free cash flow (“FCF”), a non-U.S. GAAP metric defined below.
  • Returned approximately $295 million of capital to shareholders through the repurchase of approximately 4.2 million shares, or approximately 4.5 percent of common stock outstanding, and a $0.35 base dividend.
  • Reduced debt by approximately $300 million, exiting the quarter with approximately $1.4 billion in long-term debt and a leverage ratio of 0.5x.
  • Total production of 23.0 million barrels of oil equivalent (“MMBoe”) or approximately 250,000 Boe per day and oil production of 7.4 million barrels (“MMBbls”) or approximately 81,000 Bbls per day.
  • Published the Company’s 2022 environmental, social and governance (“ESG”) materials providing a roadmap on progress of our key metrics, material initiatives and successes in 2021. We remain committed and on track to achieve our long-term goals of reducing greenhouse gas and methane emission intensity by 60% and 50%, respectively, by 2025.

CEO Commentary

President and Chief Executive Officer, Bart Brookman, commented, “The third quarter generated solid results for PDC. This marks the first full quarter reflecting the benefits of the Great Western acquisition. I am proud of our team who worked diligently to fully integrate this transaction on schedule and under budget. Results for the quarter are highlighted by $440 million of free cash flow, shareholder returns of approximately $295 million through our accelerated share buyback program, and a $0.35 per share base dividend. Quarterly production averaged 250,000 Boe per day, the midpoint of our guidance, as we began to see the synergies of the consolidated asset base. Our low cost and efficient operations are reflected in our strong free cash flow, as lease operating, and G&A expenses came in at a combined $4.75 per Boe.

“Additionally, our regulatory team has worked tirelessly and thoughtfully to move our Guanella CAP permitting application forward. This CAP, along with our prior OGDPs, represent our planned Wattenberg Field turn-in-line activity through 2028. We are scheduled for the COGCC public hearing on December 7, 2022. The locations included under the CAP application represent approximately 450 wells in our Summit and Plains areas in the core Wattenberg Field.”

Operations Update

In the third quarter of 2022, PDC invested approximately $260 million while delivering total production of 23.0 million Boe, or approximately 250,000 Boe per day, and oil production of 7.4 million barrels, or approximately 81,000 barrels per day. Total production and oil production represent a sequential increase of 7 percent and 8 percent, respectively, compared to the second quarter of 2022, primarily driven by the production volumes from the Great Western acquisition and turn-in-line activities in the third quarter of 2022.

In the Wattenberg Field, the Company invested approximately $230 million to operate an average of three drilling rigs and approximately one completion crew in the third quarter, resulting in 47 spuds and 41 TILs. As a result of the longer laterals and improved efficiencies, we completed approximately 15 percent more stages in the third quarter compared to the previous quarter. Total production was 20.2 million Boe, or approximately 219,000 Boe per day, while oil production was approximately 6.3 million Bbls, or approximately 69,000 Bbls per day. PDC exited the third quarter with approximately 200 drilled, uncompleted wells (“DUCs”) and approximately 400 approved permits in-hand.

In the Delaware Basin, PDC invested approximately $30 million to operate one drilling rig, resulting in 3 spuds and 1 TIL. Total production was 2.8 million Boe, or approximately 31,000 Boe per day, while oil production was approximately 1.1 million Boe, or approximately 12,000 Boe per day.

Q3 2022 Shareholder Returns and Financial Position

The Company returned approximately $295 million of capital to shareholders in the third quarter through the repurchase of approximately 4.2 million shares of common stock and a $0.35 per share base quarterly dividend. The Company has a $1.25 billion share repurchase program authorized, which is expected to be utilized by year end 2023. PDC remains committed to returning a minimum of 60 percent of its annual post-dividend FCF to shareholders through the Company’s share repurchase program and a year-end special dividend, if needed.

The Company reduced its debt by approximately $300 million during the quarter. At quarter end, the company had approximately $45 million cash on hand and approximately $450 million drawn on its credit facility. The leverage ratio was 0.5x at September 30, 2022.

In October 2022, as part of our credit facility semi-annual redetermination, our borrowing base increased to $3.5 billion from $3.0 billion as a result of the reserves acquired from the Great Western acquisition. The Company maintained the elected commitment amount of $1.5 billion.

Guanella Comprehensive Area Plan (“CAP”)

On August 2, 2022, the Company passed a major milestone in the permitting process by receiving the Completeness Determination on its Guanella CAP from the Colorado Oil & Gas Conservation Commission (“COGCC”). The Guanella CAP covers approximately 35,000 consolidated net acres in rural Weld County with approximately 450 well locations accessed by only 22 surface locations.

On October 2, 2022, the Company completed the 60-day public comment period. We are scheduled for the COGCC public hearing on December 7, 2022 which could potentially continue on December 8, 2022 given the size and scale of the Guanella CAP. The CAP, along with our prior OGDPs, represent our planned Wattenberg Field turn-in-line activity through 2028.

Fourth Quarter and Full Year 2022 Outlook

For the fourth quarter, the Company expects total production to be in a range of 245,000-255,000 Boe per day and 80,000-84,000 Bbls per day of oil production.

For the full-year 2022, we reaffirm our production guidance range of 230,000 Boe to 240,000 Boe per day, of which approximately 73,000 Bbls to 77,000 Bbls is expected to be crude oil. Our planned 2022 capital investments in crude oil and natural gas properties are expected to be approximately $1.075 billion, which is at the high end of our previously reported full-year guidance range. This is a result of bringing on the second completion crew at the end of September, as planned, paired with continued operational efficiency that ultimately increases the number of stages completed and incremental spuds as well as continued cost pressures.

Environmental, Social and Governance (“ESG”)

Through the first nine months of 2022, the Company is on schedule with its planned projects to meet its 15% and 30% GHG and methane reduction targets for the full year 2022, respectively.

During the third quarter, the Company published its 2022 ESG materials. The 2022 ESG reports are aligned with the Sustainability Accounting Standards Board (“SASB”), the Taskforce on Climate-related Financial Disclosures (“TCFD”), and the American Exploration and Production Council (“AXPC”) ESG metrics frameworks.

For more information about PDC’s sustainability efforts and to download the 2022 ESG reports, please visit

Third Quarter Oil and Gas Production, Sales and Operating Cost Data

Crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, were $1,201 million, a 3 percent decrease compared to second quarter of 2022 of $1,238 million. The decrease in sales between periods was due to a 10 percent decrease in the weighted average realized sales price per Boe to $52.25 from $57.81 partially offset by a 7 percent increase in production from 21.4 MMBoe to 23.0 MMBoe. The decrease in sales price was primarily driven by a 15 percent decrease in weighted average realized crude oil and NGLs prices partially offset by an 8 percent increase in weighted average realized natural gas prices. The combined revenue from crude oil, natural gas and NGLs sales and net settlements on commodity derivative instruments was $948 million in the third quarter of 2022 compared to $939 million in the prior quarter.

The following table provides weighted average sales price, by area, excluding net settlements on derivatives and transportation, gathering and processing expense (“TGP”), for the periods presented:

Three Months EndedNine Months EndedSeptember 30,
September 30, 2022June 30, 2022Percent Change20222021Percent Change
Crude oil (MBbls)
Wattenberg Field6,2995,54514%16,67613,59523%
Delaware Basin1,1101,299(15)%3,4302,76224%
Weighted average price$91.88$108.24(15)%$98.05$64.0053%
Natural gas (MMcf)
Wattenberg Field46,63143,2448%127,538113,28013%
Delaware Basin6,3166,573(4)%18,34515,43419%
Weighted average price$6.03$5.578%$5.21$2.54105%
NGLs (MBbls)
Wattenberg Field6,0835,5759%15,94912,68526%
Delaware Basin664688(3)%1,9461,43436%
Weighted average price$29.75$34.99(15)%$32.93$23.4141%
Crude oil equivalent (MBoe)
Wattenberg Field20,15318,32810%53,88145,16019%
Delaware Basin2,8273,082(8)%8,4346,76825%
Weighted average price$52.25$57.81(10)%$53.29$32.8262%

Production costs for the third quarter of 2022, which include LOE, production taxes and TGP, were $200 million, or $8.69 per Boe, compared to $190 million, or $8.85 per Boe, in the second quarter of 2022. The decrease in production costs per Boe was primarily due to a 7 percent increase in production volumes partially offset by a 10 percent increase in production taxes as a result of increased ad valorem rates associated with the acquisition of Great Western.

The following table provides the components of production costs for the periods presented:

Three Months EndedNine Months Ended September 30,
September 30, 2022June 30, 202220222021
Lease operating expenses$69.2$70.6$193.9$129.8
Production taxes98.189.3250.3101.1
Transportation, gathering and processing expenses32.329.689.974.5
Three Months EndedNine Months Ended September 30,
September 30, 2022June 30, 202220222021
Lease operating expenses per Boe$3.01$3.30$3.11$2.50
Production taxes per Boe4.
Transportation, gathering and processing expenses per Boe1.411.381.441.43
Total per Boe$8.69$8.85$8.57$5.88

Financial Results

Net income for the third quarter of 2022 was $798 million, or $8.30 per diluted share, compared to $662 million, or $6.74 per diluted share in the second quarter of 2022. The quarter-over-quarter change was primarily due to a $306.7 million commodity risk management gain in the third quarter of 2022 compared to a $102.0 million commodity risk management loss in the second quarter of 2022 partially offset by (i) a gain on bargain purchase from the Great Western acquisition of $100.3 million recognized in the second quarter, (ii) an increase in income tax expense of $101.3 million, and (iii) a decrease in crude oil, natural gas and NGLs sales of $37.1 million between periods. Adjusted net income, a non-U.S. GAAP financial measure defined below, was $363 million in the third quarter of 2022 compared to $502 million in the second quarter of 2022. The movement between periods is primarily attributable to the bargain purchase gain and, to a lesser extent, the change in sales and settled derivatives.

Net cash from operating activities for the third quarter of 2022 was approximately $848 million compared to $747 million in the second quarter of 2022. Adjusted cash flows from operations, a non-U.S. GAAP metric defined below, was approximately $701 million and $695 million in the third and second quarter of 2022, respectively. The quarter-over-quarter increase in adjusted cash flows from operations was primarily due to a $45.8 million decrease in derivative settlement losses and a $5.5 million decrease in general and administrative expense partially offset by a decrease in sales and an increase in production taxes and TGP between periods. Adjusted free cash flows, a non-U.S. GAAP metric defined below, increased to $440 million from $404 million in the second quarter of 2022.

G&A, which includes cash and non-cash expense and $4.9 million in Great Western transaction and transition related expense, was $40 million, or $1.75 per Boe in the third quarter of 2022 compared to $46 million, which includes $13.0 million in Great Western transaction and transition related expense, or $2.13 per Boe, in the second quarter of 2022. Excluding the transaction and transition costs associated with the Great Western acquisition, G&A was $1.53 and $1.52 per Boe in the third and second quarter, respectively.

Reconciliation of Non-U.S. GAAP Financial Measures

We use “adjusted cash flows from operations,” “adjusted free cash flow (deficit),” “adjusted net income (loss)” and “adjusted EBITDAX,” non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.

Adjusted cash flows from operations and adjusted free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe adjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities and to return capital to stockholders in the period in which the related transactions occurred. We exclude from this measure cash receipts and expenditures related to acquisitions and divestitures of oil and gas properties and capital expenditures for other properties and equipment, which are not reflective of the cash generated or used by ongoing activities on our existing producing properties and, in the case of acquisitions and divestitures, may be evaluated separately in terms of their impact on our performance and liquidity. Adjusted free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from the adjusted free cash flow measure.

We are unable to present a reconciliation of forward-looking adjusted cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of adjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations.

Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance.

Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, and acquisitions and to service our debt obligations.

Cash Flows from Operations to Adjusted Cash Flows from Operations and Adjusted Free Cash Flow
Three Months EndedNine Months Ended September 30,
September 30, 2022June 30, 202220222021
Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow:
Net cash from operating activities$848.4$747.4$2,084.8$1,027.8
Changes in assets and liabilities(147.1)(52.7)(150.1)31.7
Adjusted cash flows from operations701.3694.71,934.71,059.5
Capital expenditures for midstream assets(5.7)(3.0)(8.7)
Capital expenditures for development of crude oil and natural gas properties(240.2)(346.7)(773.7)(428.8)
Change in accounts payable related to capital expenditures for oil and gas development activities(15.0)58.810.7(21.2)
Adjusted free cash flow$440.4$403.8$1,163.0$609.5
Net Loss to Adjusted Net Income (Loss) and Adjusted Earnings Per Share, Diluted
Three Months EndedNine Months Ended September 30,
September 30, 2022June 30, 202220222021
Net income (loss) to adjusted net income (loss):
Net income (loss)$798.0$662.4$1,428.4$49.2
Loss (gain) on commodity derivative instruments(306.7)102.0363.3707.2
Net settlements on commodity derivative instruments(252.8)(298.7)(713.1)(215.4)
Tax effect of above adjustments (1)124.236.474.1
Adjusted net income (loss)$362.7$502.1$1,152.7$541.0
Earnings per share, diluted8.40$6.8314.660.49
Loss (gain) on commodity derivative instruments(3.19)1.043.747.04
Net settlements on commodity derivative instruments(2.63)(3.04)(7.32)(2.14)
Tax effect of above adjustments (1)1.290.370.76
Adjusted earnings (loss) per share, diluted$3.77$5.11$11.82$5.38
Weighted average diluted shares outstanding96.198.297.5100.5


(1)   Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the nine months ended September 30, 2021.

Adjusted EBITDAX
Three Months EndedNine Months Ended September 30,
September 30, 2022June 30, 202220222021
Net income (loss) to adjusted EBITDAX:
Net income (loss)$798.0$662.4$1,428.4$49.2
Loss (gain) on commodity derivative instruments(306.7)102.0363.3707.2
Net settlements on commodity derivative instruments(252.8)(298.7)(713.1)(215.4)
Non-cash stock-based compensation7.
Interest expense, net18.617.649.159.2
Income tax expense (benefit)229.3128.0358.50.1
Impairment of properties and equipment0.
Exploration, geologic and geophysical expense11.80.312.40.9
Depreciation, depletion and amortization205.6191.1547.7478.6
Accretion of asset retirement obligations3.
Loss (gain) on sale of properties and equipment(0.1)0.50.3(0.6)
Adjusted EBITDAX$714.6$814.3$2,078.0$1,106.0
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities$848.4$747.4$2,084.8$1,027.8
Gain on bargain purchase(4.6)100.395.7
Interest expense, net18.617.649.159.2
Amortization and write-off of debt discount, premium and issuance costs(1.4)(1.3)(4.1)(11.2)
Exploration, geologic and geophysical expense0.
Changes in assets and liabilities(147.1)(52.7)(150.1)31.7
Adjusted EBITDAX$714.6$814.3$2,078.0$1,106.0

Condensed Consolidated Statements of Operations
(unaudited, in thousands, except per share data)

Three Months Ended September 30,Nine Months Ended September 30,
Crude oil, natural gas and NGLs sales$1,200,619$703,136$3,320,678$1,704,396
Commodity price risk management gain (loss), net306,749(217,678)(363,283)(707,187)
Other income3,9219048,8334,058
Total revenues1,511,289486,3622,966,2281,001,267
Costs, expenses and other
Lease operating expense69,15545,649193,922129,848
Production taxes98,14244,654250,309101,114
Transportation, gathering and processing expense32,32726,73289,88274,453
Exploration, geologic and geophysical expense11,84322212,416862
General and administrative expense40,10330,847119,85996,367
Depreciation, depletion and amortization205,604169,644547,720478,617
Accretion of asset retirement obligations3,4842,8259,8239,185
Impairment of properties and equipment184771,637329
Loss (gain) on sale of properties and equipment(86)(220)287(561)
Other expense3032,496
Total costs, expenses and other460,756320,7331,225,855892,710
Income (loss) from operations1,050,533165,6291,740,373108,557
Interest expense, net(18,629)(20,098)(49,139)(59,199)
(Adjustment to) Gain on bargain purchase(4,621)95,652
Income (loss) before income taxes1,027,283145,5311,786,88649,358
Income tax benefit (expense)(229,318)(210)(358,500)(110)
Net income (loss)$797,965$145,321$1,428,386$49,248
Earnings (Loss) per share:
Weighted average common shares outstanding:
Dividends declared per share$0.35$0.12$0.95$0.24

Condensed Consolidated Balance Sheets
(unaudited, in thousands, except share and per share data)

September 30, 2022December 31, 2021
Current assets:
Cash and cash equivalents$45,649$33,829
Accounts receivable, net609,440398,605
Fair value of derivatives62,24617,909
Prepaid expenses and other current assets10,6308,230
Total current assets727,965458,573
Properties and equipment, net7,127,2914,814,865
Fair value of derivatives91,07515,177
Other assets81,75948,051
Total Assets$8,028,090$5,336,666
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable$213,473$127,891
Production tax liability247,94699,583
Fair value of derivatives389,234304,870
Funds held for distribution538,865285,861
Accrued interest payable19,51110,482
Other accrued expenses102,02491,409
Total current liabilities1,511,053920,096
Long-term debt1,393,528942,084
Asset retirement obligations152,709127,526
Fair value of derivatives100,86095,561
Deferred income taxes413,98326,383
Other liabilities474,610314,769
Total liabilities4,046,7432,426,419
Commitments and contingent liabilities
Stockholders’ equity
Common shares – par value $0.01 per share, 150,000,000 authorized, 92,857,134 and 96,468,071 issued as of September 30, 2022 and December 31, 2021, respectively929965
Additional paid-in capital2,950,6253,161,941
Retained earnings (accumulated deficit)1,037,229(249,954)
Treasury shares – at cost, 130,091 and 54,960 as of September 30, 2022 and December 31, 2021, respectively(7,436)(2,705)
Total stockholders’ equity3,981,3472,910,247
  Total Liabilities and Stockholders’ Equity$8,028,090$5,336,666

Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)

Nine Months Ended September 30,
Cash flows from operating activities:
Net income (loss)$1,428,386$49,248
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives(349,798)491,830
Depreciation, depletion and amortization547,720478,617
Impairment of properties and equipment1,637329
Exploratory dry hole costs11,536
Accretion of asset retirement obligations9,8239,185
Non-cash stock-based compensation19,95217,294
Loss (gain) on sale of properties and equipment287(561)
Amortization of debt discount, premium and issuance costs4,07511,195
Deferred income taxes357,500
Gain on bargain purchase(95,652)
Changes in assets and liabilities150,067(31,670)
     Net cash from operating activities2,084,7911,027,820
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties(773,748)(428,831)
Capital expenditures for midstream assets(8,747)
Capital expenditures for other properties and equipment(8,619)(363)
Cash paid for acquisition of an exploration and production business(1,068,241)
Proceeds from sale of properties and equipment6404,720
Proceeds from divestitures10,452
     Net cash from investing activities(1,848,263)(424,474)
Cash flows from financing activities:
Proceeds from revolving credit facility and other borrowings2,049,200502,800
Repayment of revolving credit facility and other borrowings(1,599,200)(670,800)
Repayment of convertible notes(200,000)
Payment of debt issuance costs(101)
Purchase of treasury shares for employee stock-based compensation tax withholding obligations(16,979)(5,836)
Purchase of treasury shares(556,035)(107,318)
Dividends paid(91,972)(23,600)
Principal payments under financing lease obligations(1,491)(1,293)
     Net cash from financing activities(216,578)(506,047)
Net change in cash, cash equivalents and restricted cash19,95097,299
Cash, cash equivalents and restricted cash, beginning of period33,8292,623
Cash, cash equivalents and restricted cash, end of period$53,779$99,922

2022 Third Quarter Teleconference and Webcast

The Company invites you to join Bart Brookman, President and Chief Executive Officer; Scott Meyers, Chief Financial Officer; Lance Lauck, Executive Vice President Corporate Development and Strategy; and David Lillo, Senior Vice President Operations for a conference call at 11:00 a.m. ET on Thursday, November 3, 2022, to discuss the 2022 third quarter results. The related slide presentation will be available on PDC’s website at

To attend the conference call or webcast, participants should register online at Once registered, participants will receive the dial in details and a unique PIN number. Participants are requested to register a minimum 15 minutes before the start of the call.

A replay of the webcast will be available two hours after the call and archived on the same web page for six months.

About PDC Energy, Inc.

PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and Delaware Basin in west Texas. Its operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones.


This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) and the United States (“U.S.”) Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are “forward-looking statements”. Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding permitting matters; future production, costs and cash flows; drilling locations, zones and growth opportunities; capital expenditures and projects; the return of capital to shareholders through buybacks of shares and/or payments of dividends; and ESG matters.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this press release reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this press release or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future,
they are subject to increased levels of uncertainty.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

  • market and commodity price volatility, widening price differentials, and related impacts to the Company, including decreased revenue, income and cash flow, write-downs and impairments and decreased availability of capital;
  • difficulties in integrating our operations as a result of any significant acquisitions, including the Great Western acquisition, or acreage exchanges;
  • adverse changes to our future cash flows, liquidity and financial condition;
  • changes in, and interpretations and enforcement of, environmental and other laws and other political and regulatory developments, including in particular additional permit scrutiny in Colorado;
  • the coronavirus 2019 (“COVID-19”) pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters;
  • declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments;
  • changes in, and inaccuracy of, reserve estimates and expected production and decline rates;
  • timing and extent of our success in discovering, acquiring, developing and producing reserves;
  • reductions in the borrowing base under our revolving credit facility;
  • availability and cost of capital;
  • risks inherent in the drilling and operation of crude oil and natural gas wells;
  • timing and costs of wells and facilities;
  • availability, cost, and timing of sufficient pipeline, gathering and transportation facilities and related infrastructure;
  • limitations in the availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells;
  • potential losses of acreage or other impacts due to lease expirations, other title defects, or otherwise;
  • risks inherent in marketing crude oil, natural gas and NGLs;
  • effect of crude oil and natural gas derivative activities;
  • impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events;
  • cost of pending or future litigation;
  • impact to our operations, personnel retention, strategy, stock price and expenses caused by the actions of activist shareholders;
  • uncertainties associated with future dividends to our shareholders or share buybacks;
  • timing and amounts of federal and state income taxes;
  • our ability to retain or attract senior management and key technical employees;
  • an unanticipated assumption of liabilities or other problems with the Great Western acquisition or other acquisitions we may pursue;
  • civil unrest, terrorist attacks and cyber threats;
  • changes in general economic, business or industry conditions, including changes in interest rates and inflation rates and concerns regarding a global economic recession; and
  • success of strategic plans, expectations and objectives for our future operations.

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the “Item 1A. Risk Factors” made in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the U.S. Securities and Exchange Commission for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this release. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this release or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

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Freeport News Fails to Stop Natural Gas Bears from Chomping Away at Forward Prices – Natural Gas Intelligence

With February only days away, the natural gas market may be closing the book on winter – and brushing off news of Freeport LNG’s impending restart – as forward prices continued to soften through the Jan. 19-25 period, according to NGI’s Forward Look.

The past week’s trading patterns continued the trends that have played out throughout much of the season, with the West and East coasts leading the step lower as intimidating cold has been lacking from recent forecasts.

NatGasWeather said a strong winter storm would exit the East on Thursday, while a colder system upstream was forecast to track across the Midwest over the next few days. This system is expected to open the door for reinforcing frigid shots to advance aggressively into the northern and central United States, however, the latest data backed off this possibility. It also didn’t show frigid air sticking around as long, especially in the Global Forecast System (GFS) model.

[2023 Natural Gas Price Outlook: How will the energy industry continue to evolve in 2023? NGI’s special report “Reshuffling the Deck: High Stakes for Natural Gas & The World is All-In” offers trusted insight and data-backed forecasts on U.S. natural gas and the global LNG markets. Download now.]

“The overnight European Centre is still impressively cold for Jan. 31-Feb. 4 for very strong national demand, but then moderates temperatures over the southern and eastern U.S. faster Feb. 5-8, like the GFS,” NatGasWeather said.

With storage inventories in the East tracking near seasonal levels, forward markets traders were content to take prices down a few more notches.

New England’s Algonquin Citygate tumbled $1.270 to $11.935 for February, Forward Look data showed. The summer strip (April-October) fell 12.0 cents to average $3.110, while the upcoming winter strip (November-March) managed to pick up a penny to average $13.077.

Similar price decreases were seen along Transcontinental Gas Pipe Line Co. Transco Zone 6 non-NY’s February contract slid $1.060 to $6.681. The summer strip lost a dime to reach $2.730. Prices for next winter were down 52.0 cents to $7.791.

The sell-off was even more pronounced on the West Coast. Notably, however, prices remain at a sharp premium over the rest of North America given the vastly different supply/demand picture out West.

For example, when it comes to storage, the Pacific region stands out as the only one where inventories are lagging historical levels – at more than 30% below the five-year average, according to government statistics.

At the same time, AccuWeather said the transition to spring from winter may be slow on the West Coast, with a few more waves of rain and mountain snow likely. The late winter and early spring storms in California may not be as frequent or as furious as the storms that kicked off 2023. However, they should continue to alleviate the drought conditions that have persisted for the past few years.

AccuWeather said the onslaught of storms from late December through early January completely erased the extreme and exceptional drought conditions across the state. More rounds of precipitation late in the winter and early spring should continue to lessen the severity of the ongoing drought across the region. This is in stark contrast to 2022, when a dry end to winter and start to spring caused the drought to worsen.

The rainy season should bode well for hydroelectric power generation this spring, with a recovery in output likely to put a damper on power burns. That said, the availability of that gas supply could finally make its way into storage, where it’s needed.

To that end, gas flows also may improve in the coming weeks.

Kinder Morgan Inc. on Wednesday asked federal regulators to lift the pressure restriction on Line 2000 of the El Paso Natural Gas Pipeline (EPNG) system to return the line to commercial service.

Work to repair the line was completed earlier this month following an August 2021 explosion near Coolidge, AZ. However, EPNG advised shippers that the Pipeline and Hazardous Materials Safety Administration would need time to review the request.

“If we were to assume a two-week turnaround for approval, this would place the line back into service near Feb. 7,” said Wood Mackenzie’s Quinn Schulz, natural gas analyst. “While this submittal is earlier than what we expected, the fact remains that we still cannot be certain how long this approval may take due to the circumstances surrounding this event: the fatalities, the length of the fix, etc.”

Bearish Macro Outlook

Price declines were a bit more tempered across most other U.S. forward curves, though the unsupportive market signals continued to have a strong influence on the market.

Aside from the increasingly bearish near-term weather outlook, the latest government storage data also did little to inspire a rebound for prices.

The U.S. Energy Information Administration (EIA) on Thursday said inventories for the week ending Jan. 20 fell by 91 Bcf. Though the withdrawal was larger than expected by most analysts, it still fell well short of normal pulls for this time of year. A pull of 217 Bcf was recorded during the same week last year, while the five-year average draw is 185 Bcf.

The East led all regions with a pull of 40 Bcf, while the Midwest followed with a draw of 36 Bcf. Mountain and Pacific region inventories each fell by 7 Bcf.

South Central stocks, meanwhile, decreased by a net 2 Bcf. The result reflected a 3 Bcf injection into salts that was more than offset by a pull of 5 Bcf from nonsalt facilities, EIA said.

Even with the larger-than-expected withdrawal, inventories as of Jan. 20 stood at 2,729 Bcf, which is 107 Bcf higher than a year earlier and 128 Bcf above the five-year average.

One participant on Enelyst, an online energy chat, said tighter numbers may arrive in the weeks ahead, especially considering the expected cold snap – brief as it may be. That said, it’s “too little too late in the big picture.”

At the very least, though, the slightly larger-than-expected withdrawal “should give some pause to this falling knife,” according to advisory firm Valor Analytics. “Still needs a lot of weather support. Otherwise, the big guys are gunning for a $1 handle soon.”

Indeed, with exports still languishing amid the continued outage at the Freeport liquefied natural gas terminal, ample production and lackluster demand have taken a swift toll on prices. Prices could turn around soon, though.

Freeport LNG on Thursday received FERC approval to begin commissioning, including cooldown, of Loop 1 transfer piping and to reinstate service of the boil off gas management system. It had asked the Federal Energy Regulatory Commission for permission to begin preliminary work to restart operations on Monday (Jan. 30).

NGI’s LNG Export Tracker showed modest amounts of feed gas being delivered to the 2.38 Bcf/d terminal on Thursday. Freeport LNG has been shut since a June explosion.

The Freeport news largely unfazed bears, though. February Nymex futures settled Thursday at $2.944, off 12.3 cents from Wednesday’s close.

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