2.20.2023 DEP Industry Observations: Energy Ruminations – Thrive Energy Conference Prominent Themes & Considerations; Q4 Earnings

Macro/Headlines/Events

Baker Rig Count-  The US onshore rig count was flat last week at 741 rigs.

FT- Blast-hit US gas export plant reopens but safety concerns persist Link

WSJ- Abu Dhabi to Sell 4% of Natural-Gas Business in IPO Link

FT- British companies face energy bill cliff edge, experts warn-  Link

FT- European natural gas prices fall to 18-month low as energy crisis ebbs  Link

NYT-Just How Good for the Planet Is That Big Electric Pickup Truck?   Link

FT-US energy groups queue to go public as sector returns to favour  Link

DEP Update:  THRIVE 2023 arrives this week, so here’s a quick update.  For those who wish to attend, you need to be registered.  If you’re not sure whether you are officially registered, email me tonight/tmw.  I’m happy to double check. In addition, a few important event details: (1) industry interest appears strong, thankfully, as registration stands at roughly 1,900 people from over 550 companies; (2) we still have a few sponsors who haven’t registered anyone, so we will aggressively bug a few of you on Monday; (3) guests will be able to watch the industry panels on the stadium big screen (El Grande) and on televisions throughout the ballpark; therefore, please don’t feel the need to rush Union Train station – there won’t be seats for everyone; (4) attire is business casual; and (5) please drink responsibly.  There are a ton of companies hosting suite parties and/or dinners/receptions offsite, so behave and be safe.

Research

Energy Ruminations (authored by Bill Herbert): Thrive Energy Conference Prominent Themes, Considerations and Questions

Macro Oil – Briefly Considered: The energy (oil + nat gas) markets continue to have near-term headwinds and longer-term tailwinds. Oil inventory trends, of late, have been bearish and are likely to remain a near-term burden due to the prospect of heavy refinery maintenance and anemic demand. Commercial crude inventories have increased materially for eight consecutive weeks. Notwithstanding, total US crude inventories, including SPR, remain exceedingly suppressed at ~20% below 5-yr average levels. Beyond the next several weeks/few months, the imperative for sustained reinvestment has never been higher due to the convergence of national and energy security, depleted domestic inventories, and evaporated OPEC spare production capacity. The domestic shale productivity supernova of yesteryear is transitioning to a less seamless, more labored reality with rising capital and service intensity, elongating lead-times and a gassier production mix. The US is projected to be the engine of global oil production growth over the current decade. In the category of all models are wrong but some are useful, the IEA’s L-T estimate of US total liquids production growth looks doable but far from guaranteed (IEA 2021-2030E ~4 MBD, with ~75% generated from shale).

The prominent macro wildcards entering 2023 were (and continue to be) China oil demand and Russian oil and product exports. China is the demand fulcrum for this year, representing 45% of the IEA’s projected global demand increase. In the event China’s emergence proves to be cathartic, oil prices will move higher, perhaps sharply. The opposite is also true – if the recovery is anemic, this will be a challenging year for oil and conventional energy stocks.  There is evidence to suggest a looming PUD (pent-up-demand) surge is in the early stages of unfolding. The IEA recently observed that leading-edge activity and mobility indicators are reflective of a “sharp uptick.” Kuwait’s state energy company head observed that China oil demand was increasing and that it wasn’t “a dead-cat bounce.” Saudi recently raised OSPs to Asia, Europe, and US for March delivery – the price increase for Asian shipments was the first since September (Bloomberg). Estimates for China 2023 demand growth are all over the map, ranging from ~500 KBD to 4 MBD y/y, with most congregating sub-1 MBD. The IEA’s estimate, at this juncture, looks reasonable (+900 KBD y/y, Q1 -220 KBD, Q2-Q4 +1.2-1.3 MBD). OPEC’s estimate, on the other hand, looks subdued (+590 KBD, Q1 +360 KBD, Q2 +800 KBD, 2H +600 KBD). Notwithstanding the building fervor for a China PUD surge, if one examines the IEA’s projected progression over the 2021–2023 time frame, rather than from the purgatorial depths of 2022, China demand is projected to expand by a more normalized 480 KBD. Viewed in this context, the IEA’s estimate isn’t a moonshot.

With respect to Russia, oil exports have been resilient since the invasion of Ukraine as heavily discounted barrels have found willing buyers (predominantly China, India). While IEA and OPEC Russian production assumptions strike us as penal (~-1MBD y/y), leading edge reports now convey increased friction in clearing barrels in Asia. Russia recently announced a 500 KBD production cut, beginning in March.  The announcement was laden with Russia’s unquenchable grievance and was, purportedly, in response to “the destructive energy policy of the countries of the collective west.” Some have surmised, however, that the recalibration is in response to the current surplus in the oil market. Moreover, with the recently implemented ban on refined products, some believe that Russia faces a greater challenge in maintaining exports. China and India, for example, have ample refining capacity. Additionally, limited clean tanker availability could force Russian refiners to lower crude inputs, resulting in reduced oil production. TTE’s CEO recently captured the uncertainty associated with Russia: “Russian crude oil is finding its place in the market…but the refined products of Russia…that’s a mystery.” Russian oil/gas revs in January were down 46% y/y (Bloomberg). Pierre Andurand recently expressed: “Russia has lost the energy war.” (FT). Time will tell.

Notwithstanding dispiriting domestic inventory trends, the prospect for tightening global market balances 2H is plausible.  Demand for this year is forecast (IEA) to increase by ~2 MBD y/y, with jet fueling ~1/2 of the expansion. Over the course (Q1-Q4) of this year, demand is projected to vault by ~3.5 MBD (vs. ~1.3 MBD last year). The projected demand surge contrasts with limited OPEC spare capacity, which continues to caress the low-end of the historical range at ~2.7% of global demand. The IEA’s call on OPEC production required to achieve inventory neutrality is projected to increase from 28.4 MBD in Q1 to 30.6 MBD in Q3 and 31.2 MBD in Q4. Current OPEC production is ~29 MBD (Saudi ~10.3 MBD). Lastly, while the EIA expects the US to grow black oil production by 590 KBD y/y (total liquids ~1 MBD), rising Permian GORs and natural gas price despondency (more below) are impacting E&P cash flow generation expectations and the pace of upstream reinvestment. We expect 2023 to be another wild ride.

1. US Oil Production Growth Prospects – Decelerating: US oil production, in 2022, has largely performed in-line with EIA projections (11.8-11.9 MBD) and the 2023 prophecy looks doable (1H’23 flattish with YE’22, 2023E +590 KBD y/y) and y/y growth optionality will be lubricated, in part, by easy y/y 1H comps (1H’22 avg production ~11.6 MBD, Nov ~12.4 MBD). The production growth estimates on the part of other benchmark agencies (OPEC estimate of US 2023 production growth = +750 KBD y/y) appear overly exuberant. Lastly, the EIA’s 2024 estimate was lowered from 12.81 MBD to 12.65 MBD, yielding 160 KBD of projected y/y growth for 2024.

1. Domestic Shale – Transitional Realities: We found the following quote from SLB’s CEO noteworthy: “I think it’s very well known that the limited access to Tier 1 inventory and acreage and the stretched capacity in the market has created a negative inflection on well productivity.” HAL’s CEO had an equally trenchant observation: “Domestic E&P capital spending increased by ~50% last year and US oil production expanded by ~6%.” US shale, not too long ago, represented a productivity dynamic of doing more with the same or less. This may no longer be the case as capital and service intensity appear to be rising.  CVX’s growth downshift for 2023, and its need to renew an optimal development plan, is emblematic of the transitional reality unfolding in the Permian from productivity supernova to a more mature phase which continues to be exceedingly consequential but less cathartic. XOM, following two consecutive years of 90 KBD Permian production growth is downshifting to 40-50 KBD of targeted growth in 2023 – DUC inventory exhaustion and the need to rebuild inventory as well as taking the foot off the gas pedal in an inflationary oilfield environment were cited as reasons for the downshift. COP L-48 BOE production growth in 2022 was ~27% and oil was ~19-20% – 2023 targeted y/y production growth is ~5%.

1. Permian GORs – Rising, with Associated Implications for E&P CF Generation, Reinvestment and US Oil Production Growth: The popular mythology of the Permian is that it’s an oil play, when, in fact, while it’s an indisputably important oil play, it’s increasingly becoming a hybrid gas play as Permian GORs continue to increase (NGLs + natty = ~40-50% of Permian production and rising?).  The evolution of PXD’s production mix is illuminating. In Q3’21, oil represented ~58% of its production stream, while NGLs comprised 23% and nat gas ~19%. A year later in Q3’22, oil had compressed to 54%, while NGLs had risen to ~25% and nat gas to 21%. Similarly, DVN’s Delaware Basin production stream has become gassier, with the oil % declining from 51% in Q4’21 to 49% a year later – Q4/Q4, oil production declined by 5-6%, nat gas production increased 8-9%. Waha nat gas pricing has been exceedingly volatile and, YTD, conspicuously weak, even during the recent W TX arctic blast. LNG export capacity in the US isn’t expected to materially increase until 2025-2026. The implications of continued Permian nat gas price weakness, over the intermediate term, for E&P cash flow and reinvestment as well as Permian oil production growth are worthy of consideration.

1. Nat Gas – Current Pricing Despondency, Increasing Volatility: The EIA’s February STEO (Short-Term Energy Outlook) was subdued with respect to current-year natural gas prices largely due to “significantly warmer-than-normal weather in January.”  January had 16% fewer heating degree days vs. the 10-yr avg and 9% fewer vs. the STEO’s forecasted assumption. As a result, the EIA now expects nat gas inventories to close the withdrawal season at the end of March at 1.8+ TCF (vs. March 2022 ~1.4 TCF), 16% higher than the 5-yr average.  Accordingly, the EIA’s 2023 forecasted HHUB nat gas price was reduced by 30+% to $3.40/MMBTU and is projected to stay below $4/MMBTU until December. HHUB gas prices averaged ~$3.37/MMBTU in January, down ~$2+/MMBTU m/m. Current (Feb 17^th) HHUB price is ~$2.25/MMBTU (down ~50% YTD), Waha ~$2.15/MMBTU, and it’s currently 21 degrees in Midland (Waha has oscillated between negative pricing and $2.50 for most of this year). While the longer-term outlook for US LNG expansion is visible and compelling, 2023 will likely be the first year since 2016 in which LNG nameplate capacity does not expand (WSJ). According to Bloomberg, the near-month contract for HHUB has been trading below its trailing five-year average price for the first time since 2021 and is currently below the $3.21/MMBtu average price seen through the 2010s. Permian gas prices are likely to remain under pressure until takeaway capacity materially expands.  Pronounced volatility has been incessant. Last year, there were 18 days when HHUB closing prices moved by more than 10%, the most since the Nymex nat gas contract was launched more than three decades ago (WSJ). While domestic nat gas pricing enervation could be more durable than desired, it isn’t likely to be structural given the secular growth outlook for LNG.

1. Nat Gas – The Long Game: Markedly increased domestic LNG export capacity, over the next ~two years (forecast to increase by more than 40%), and beyond, will help bridge regional gas pricing disparities and lead to growing convergence globally. According to BNEF (BloombergNEF), the global LNG market is projected to expand over 2021-2026 from ~387 million metric tons per annum (~51 BCFD) in 2021 to 460 MTA (~60 BCFD), or by close to 20%. Of the ~70-75 MTA in projected LNG growth by 2026, the US is expected to provide 38 MTA or over 50% of the global increase. According to BNEF, Q4 witnessed a record volume (~25 MTA) of consummated LNG contracts (typical duration ~15-20 years), with the US accounting for ~2/3 of the volume. Longer-term, according to Shell, the global LNG market is projected to expand to 700 MTA (close to doubling from 2021) by 2040.  Energy, however, is a long-lead time business and meaningfully increased domestic LNG export capacity won’t happen overnight – but it’s in the process of unfolding. Hurry people.

1. E&P – A Looming Surge in M&A? The FT recently expressed that it was “bracing for a deals boom among oil producers…Buyers and sellers are mobilizing teams as the market gears up for a flurry of buyouts and tie-ups.” Makes sense and in fact, a member of the DEP team was with a private E&P player this weekend who shared his company is preparing to put itself up for sale, a one-off example validating more M&A is reasonable.  Shale is transitioning from the productivity surge of the preceding decade+ to a more arduous reality. As Will VanLoh presciently conveyed in an interview two years ago, “we’ve drilled the heart out of the watermelon.” Notwithstanding, the Permian is expected to be the engine of global production growth over the next decade. A convergence between buyer and seller needs could/should unlock a consolidation wave. Buyers want/need augmented inventory breadth/depth, sellers want to monetize for a decent price. The convergence catalyst is the confluence of the deliverability challenge, the need for sustained reinvestment and improving duration – bid/ask spreads should narrow, accordingly.

1. The Riddle of US Gasoline – Resilient Consumer, Anemic Demand: On the one hand, the US consumer appears to be in decent shape, the US labor force is fully employed, and VMT resilient (cumulative travel through November +1.2% y/y). On the other hand, weekly products supplied (EIA proxy for demand) for gasoline continues to run below pre-pandemic levels – latest DOE weekly gasoline “demand” print ran 4% below the 2019 comparison (last week was 11% below). The EIA is calling for gasoline prices to decline in 2023 and 2024, after reaching multiyear highs in 1H’22. The forecast calls for retail gasoline prices averaging $3.39/gal in 2023 (2022 = $3.97) and $3.09 in 2024. For 2023, the EIA projects gasoline inventories to rise in the US. Average U.S. gasoline consumption increased by ~300 KBD in 2022 and the EIA forecasts a decline in gasoline consumption in 2023 by a like amount, followed by flattish domestic demand in 2024. Thus, gasoline demand is projected to be flattish over the 2022-2024 timeframe. The EIA expects US refiners will continue to produce gasoline, even as prices decrease, to meet higher global demand for diesel.  Annual US gasoline demand is expected to remain less than in 2019 (9.3 MBD) through the end of 2024. This is despite the EIA’s estimate that people drove more last year vs. 2019, pre-pandemic. The EIA forecasts a continuation of increased travel in 2023 and 2024, but increased fuel efficiency is expected to offset increases in VMT.

1. International Upstream Capital Spending – Robust 2023, Building Multi-Year Visibility:   ME, LAM, and Africa are expected to drive double-digit international upstream capital spending and activity gains in 2023, especially in offshore and natural-gas domains. This was consistent across the BKR, HAL and SLB calls. ME is expected to witness record levels of upstream investment related to expansion in production spare capacity for both oil and natural gas. SLB contends that 5-6 ME countries have committed to multi-year production-expansion projects, with visibility extending to 2030. The golden age of OFS was during the early part of this century, pre oil shale, when best-of-breed large cap OFS generated ~40% incremental margins, due to a combination of pricing and activity gains, propelled by the absence of readily available spare oil-production capacity.  While history may not precisely repeat itself, it often rhymes. The present environment, with the convergence of energy and national security, and constrained deliverability portends a durable reinvestment cycle, holistically and globally.

1. Deepwater/Offshore – Inflecting: While offshore awakened 18 months ago, the industry is witnessing a mix-shift to deepwater (DW).  Offshore is expected to strengthen in 2023 due to a combination of tie-back activity and new DW projects. DW is in the early stages of a resurgence and will witness the most meaningful rate of growth for 2023, according to SLB, as exploration and appraisal activity emerge from prolonged comas. SLB contends that DW/offshore revenue intensity is 5x that of onshore. HAL stat: over half of its total revs are international and 40% of revs are offshore.  Notwithstanding the building fervor for offshore exploration and development, NOV highlighted the collision between inflecting demand and radically reduced offshore rig capacity. On the one hand, offshore visibility, globally, is rapidly increasing due to rising development activity in Brazil and Africa, new basin development in Guyana, shallow-water activity in Mexico, the Arabian Gulf and India, brownfield tie-backs in the GOM and the NS, and promising exploration possibilities in Namibia, Suriname and the Eastern Med. Since 2011, however, close to 390 offshore rigs have been “scrapped.” The offshore drilling industry faces a Sisyphean challenge in reviving long-idled assets given the limited wherewithal on the part of drilling contractors to invest in industry renewal.  The two primary constraints for the offshore drilling contracting industry are capital and supply chain.  NOV observed that “the freshly restructured offshore drilling contractor industry has little access to or appetite for external capital to rebuild itself.” With respect to supply chain, a nettlesome blend of Covid workforce disruptions, lack of critical components and expensive and unreliable freight has amplified execution risk for all shipyard projects. All of this coalesces into increased cost and elongating lead-times. The offshore market is becoming “tighter, tighter, and tighter.” Notwithstanding supply chain occlusions, NOV completed 15 rig reactivations (mostly jackups) in Q4 and launched 23.

1. Big 3 OFS NAM 2023 Guidance – Constructive but Nuanced: While domestic natural-gas prices have imploded, the Big 3 outlook for NAM is constructive (and possibly dated?) but nuanced.  Major oils are expected to maintain strong onshore-drilling activity while GOM is expected to witness a material increase in upstream spending. Onshore, the outlook is constructive but nuanced. SLB calling for 1H increases (flat-to-down, thus far), 2H plateau. HAL calling for continued strength, with activity surprising to the upside (need some help from commodity prices?) along with rising service intensity. Majors are expected to drive the preponderance of Permian activity growth this year – and yet Permian production guidance is downshifting from the prior 1-2 years of cathartic growth. Keep in mind that Big 3 OFS earnings season took place a month ago and we’ve seen zero price relief for natty. It’s increasingly likely that E&P cash flow and reinvestment expectations will be revised lower due to anemic natural-gas prices. We’ll find out more during E&P earnings season.

1. OFS L-48 Pricing Momentum – Stalling: A rising Permian gas-cut converging with dismal nat gas pricing will impact E&P cash flow expectations and animal spirits.  This will be a headwind for OFS pricing.  And yet the Permian rig count has been resilient – latest oil count 349 (O+G current 352) vs. a recent peak of 353 (357). The US rig count is down ~25 rigs from its recent peak of ~770 and likely bleeds lower near-term (Haynesville).  While very few E&Ps are adding rigs, the recalibration, thus far, has been a trim rather than a meaningful reduction.

1. Valuation Framework for Energy – Fluid and Unsettled: Following two years of incandescent returns, conventional energy stocks have underperformed YTD and particularly over the past month (ex-offshore OFS/drillers, which have outperformed). The SPX, over the preceding month, is up ~2-3%, the NASDAQ ~6%, while energy stocks are down ~6%, with more than a few best of breed stalwarts down ~8-16%.  Q4 earnings season has been challenging, due to a combination of Permian-prominent majors downshifting targeted domestic upstream growth for 2023, and, in some cases, E&P capex running hotter than expected and cash flow cooler. Admittedly, markets continue to be febrile and domestic winter weather has been insufficiently accommodating. Recent USD strength, on renewed impetus for HFL (higher-for-longer) Fed policy rates, isn’t helping. YTD oil inventory trends have been relentlessly negative and nat gas prices have imploded. Current WTI price ~$76/bbl (down ~5% YTD), HHUB ~$2.25/MMBTU (down ~50% YTD). And while there are well-justified expectations for tightening market balances as the year unfolds, the stock market doesn’t seem to care. Notwithstanding the growing imperative for sustained reinvestment (and a lower cost of capital) and refortifying energy security and reliability (with concurrently improving duration prospects), the market feels like it’s trying to find its energy footing. Are energy stocks the same momentum vehicles of decades past or do we now have durable, quasi-secular investment themes supporting a longer-term valuation framework? Momentum investing is, in large part, about “when” it’s going to happen. Embracing durable themes is about “what’s” going to happen. Martin Romo, a PM with the Capital Group, recently extolled that the key to being a great cyclical investor is being completely contrarian: “Lean into the pain and leave the joy behind.” Currently, energy doesn’t feel especially painful, nor does it feel particularly joyful. What is contrarian at this stage? While investors speak of a new age of energy realism and the need for sustained reinvestment, augmented duration isn’t obviously reflected in current valuations. Although conventional energy isn’t as marginalized and stigmatized as it was during the era of pre-energy realism, it continues to punch below its weight (SPX weighting ~5%) relative to its critical importance to national and economic security.  So, what’s the right valuation framework? FCF yield? What is fair value? Mid-single, high-single, low double-digit FCF yield? How about earnings? With the prospect of duration should we think contemplate earnings power? The valuation framework for energy feels fluid and unsettled.

E&P Observations:  As earnings calls stream in, more budgets for 2023 are being released, and so far, the numbers are up significantly from full-year 2022 levels.  That said, commentary from the calls suggests that operators are seeing prices flattening and even cooling at the margin, with reductions in fuel, drilling fluids, and OCTG as activity has leveled off.  Maybe as a result, management forecasts for 2023 are generally flat to down from annualized Q4 levels (see table below).

Not everything in OFS is cooling off, however.  In the words of one company CEO this week: “Rigs are still well supported.”  For another company, the inflation they’re modeling is a result of legacy contracts rolling over to higher rates.  Still another suggests they’re baking in 10-15% cost inflation into their 2023 budgets.  Several E&Ps pointed out that service costs appear divorced from current strip pricing for oil and natural gas, suggesting that commodities need a boost or costs need to drop.  We vote for the former.

In other news, we had the following earnings-adjacent announcements:

ESTE released a Q4 operational update along with 2023 guidance.  The company intends to run a 5-rig program (3 Delaware, 2 Midland), drilling 82 gross operated wells.  Earthstone guided 2023 operated D&C spend to between $635mm and $680mm, with total capex ranging from $725-775mm.  Production is expected to average 96-104 MBOE/d for the year (44% oil), up 28% from 2022 levels.  Proved reserves stand at 367.9 MMBOE, with a PV-10 of $7.8B.

VTLE is acquiring the assets of Driftwood Energy Operating, LLC, for ~$213mm (1.58mm shares of stock plus $127.6mm of cash).  The deal adds 30 gross (23 net) operated Wolfcamp B locations in the Midland Basin, including 4 DUCs.  Driftwood has acreage of 16,500 gross acres (11,200 net) in Upton and Reagan Counties (91% HBP).

PDCE announced a quarterly dividend increase of ~14% to $0.40/shr (2.5% annualized yield) and an incremental $750mm addition to its existing $1.25B share-repurchase program.

Refining Observations:  PBF reported earnings this week, with both a bullish view on gasoline margins (low inventories meeting potentially lower FCC runs given Russian VGO losses) and an eye-catching figure paid by Eni in order to form a JV in PBFs St. Bernard Renewables project in Louisiana.  Eni is paying $835mm for its half, plus an additional $50mm if certain milestones are met.  This seems like a tremendous endorsement of the project, which was slated to cost ~$600mm to complete.  Like its peers, PBF is planning a lot of turnarounds for the first couple of quarters.

Weekly inventory data was also eye-catching, but not in a good way.  Crude oil inventories built by >16mm Bbls, and gasoline had a poor showing as well.  Margins for the quarter so far are still very high but have fallen precipitously over the past three weeks.  No one in the refining industry we’ve spoken with believes the real numbers are as dire as these reports, but it’s difficult to pin down exactly where the gap is coming from.  Heavy turnaround activity in the next few months could help the situation on the product side, at least.

Quarterly Earnings

DVN

• Production of 646 MBOE/d (~50% oil), up 3.6% sequentially.
• Full-year 2022 production of 610 MBOE/d.
• Production guide of 643-663 MBOE/d for 2023, up 7%, from 400 new wells.
• Q4 capex of $874mm.
• 2023 D&C guidance of $3.5B, up 39% from 2022, but flat with Q4 annualized.
• Averaged 25 rigs in Q4, 16 Delaware, 4 Anadarko ($100mm drilling carry w/ Dow), 3 EF, 1 Bakken, and 1 PRB.
• Continuing to see inflation with legacy contracts rolling off.
• Delaware getting 60% of spend vs 75-80% historically.  FT and basis swaps protect 95% of gas, access to Brent pricing via Pin Oak investment.
• Adding temporary frac crew in Delaware Basin for 1H ’23.
• Inventory of 4,500 locations (~12 years at current pace).
• Raising fixed dividend by 11%.

CRK

• Production of 1,445 mcfe/d (all gas), up 3% sequentially.
• Full-year 2022 production of 1,373 mmcfe/d.
• Q4 D&C of $303mm brings 2022 to $1,032mm.
• Cost per lateral foot of $1,425.
• D&C for 2023 expected at $950-1,150mm, up modestly from 2022 levels and down 13% from annualized Q4 spend.
• CRK is releasing 2 rigs on legacy Haynesville.
• Will continue to delineate Western Haynesville with 2 rig program.
• Announced 2^nd Western Haynesville exploration success with initial IP of 42 mmcf/d.
• Retired $100mm of debt during Q4.
• Reinstated quarterly dividend of 12.5c/share (3.8% annualized yield).

MGY

• Production of 73.8 MBOE/d (~43% oil), down 9.5% sequentially.
• Full-year production of 75.4 MBOE/d up 14% y/y.
• D&C in Q4 $140mm, FCF of $141mm.
• Full-year D&C $460mm.
• Dividend up 15% from Q3 at $0.12c/Q (~2% annualized yield).
• Repurchased 2.4mm shares in Q4.  8.9mm shares left on authorization.
• Maintaining 2-rig, 1-crew program in 2023 for ~10% production growth.  Spending limited to 55% of EBITDAX.
• Current 2023 guide of $490-520mm (~10% below Q4 annualized levels).  Seeing costs of some service lines flattening and even declining.
• Q1 spending is guided to $140-150mm.
• Production Q1 guide of 80-82 MBOE/d.

MRO

• Production of 333 MBOE/d (50% oil), down 6% sequentially.  Winter storm Eliot reduced oil volumes by 5 MBbl/d.
• Full-year 2022 production of 343 MBOE/d (48% oil).
• Guidance of 385-405 MBOE/d (48% oil) in 2023, up 15% (impacted by Ensign acquisition which closed 12/27).
• Q4 capex of $344mm.
• Full-year 2022 Capex $1.48B.
• Raised dividend by 11% (1.5% annualized yield).
• 2023 spending guide of $2B (60% weighted to 1H), up 35% from 2022, and up 42% from annualized Q4 levels (impacted by Ensign).  MRO is baking in 10-15% cost inflation into this assessment.
• Higher y/y capex growth rate is not apples-to-apples due to an acquisition
• Program will average 9 rigs and 3-4 frac crews, with 4 EF, 2 Bakken, 2.5 Permian, and 1.5 (JV) in OK.
• MRO expects 2023 FCF of $2.6B at 40% reinvestment rate.
• Equatorial Guinea LNG delinks from HH pricing in 2024, potentially raising EBITDAX by $0.5-1.0B from 2023 levels.

EQT

• Q4 Production of ~5 Bcfe/d (95% gas), down 6% sequentially.
• Guide of 5.3 Bcfe/d for 2023, flattish with 2022.
• 3.3 Bcf/d of certified RSG production.
• Capex of $396mm brings full-year 2022 to $1.43B.
• Guided 2023 capex to $1.7-$1.9B, up 25% from last year and up 14% compared with annualized Q4 spend.
• Budget assumes 10-15% OFS cost inflation, $100mm of TILs moved from ’22 to ’23 due to 3^rd party infrastructure constraints, but nothing incremental for Tug Hill and XcL Midstream acquisitions.
• FCF of $226mm in Q4.
• Repurchased 6mm shares since January 1^st. Just under $1.4B remains on authorization.
• Bought in $283mm of debt in Q4, bringing full-year to $1.1B.  Target is $4B

AR

• Production of 3.2 Bcfe/d (2/3 gas), up slightly sequentially.
• Production guidance of 3.3 Bcfe/d in 2023.
• Q4 D&C of $203mm brings 2022 to $781mm.
• D&C capital of $875-925mm expected in 2023, assumes 10% y/y OFS cost inflation.
• 2023 budget is up 15% from 2022 and 11% from annualized Q4 levels.
• Likely run a 3 rig and 2 frac crew program
• FCF in Q4 of $272mm.
• Purchased $199mm of shares.

OIS

• Revs + 7% q/q to $202M
• EBITDA = $21M, +30% q/q adjusted
• Quarterly book-to-bill at 1.5x
• Backlog +19% q/q to $308M with two $20M awards in Q4.
• Net debt/cap = 14% with cash = $42M.
• Q4 FCF = $11M.
• $25M buyback authorized
• Offshore/International inflecting in 2023
• Total revs guided +15% y/y with 2023 EBITDA guided to $92-$100M.
• 2023 capex = $25M vs. $20M in 2022

NEX

• Noteworthy and appreciated, NEX gave its call on L48 frac activity, seeing incremental demand for 20-25 fleets, thus a magnitude sufficient to absorb any gas-related slow down.
• We hope NEX is right, although we have a slightly more subdued view.
• That said, NEX is putting money where its mouth is as the company has already repurchased $139M in stock in roughly 4-5 months, or ~6% of outstanding shares.  Commendable.
• Revs = $871M, -3% q/q.
• Adjusted EBITDA = $213M, +9% q/q
• FCF = $91M.
• 34 active fleets, of which two are in the Hayneville
• Fleet count expected to be stable in 2023 as NEX plans to retire 150,000HP or roughly 3 fleets.
• Q1 revs guided to increase 6% q/q despite weather issues which resulted in lost revs of $30-40M.
• 2022 capex = $225M with 2023 capex budgeted at $350M.
• 2023 includes at least one electric fleet (we think two) and at least two Tier 4 DGB conversions.

PBF

• Throughput of 939 MB/d (92% utilization), down 3.5% sequentially.
• Gross margin, ex specials of $19.78/Bbl.
• Systemwide throughput guide of 845-905 MB/d in Q1, down 7% at the midpoint from Q4.
• PBF indicated heavy turnarounds in 2023 which will be 1H weighted.
• Adjusted EBITDA of $1,043mm in Q4, more than double year ago results.
• Announced St. Bernard Renewables JV with Eni Sustainable Mobility, a 50/50 partnership owning the renewable-diesel project at PBF’s Chalmette refinery.  Eni will contribute $835mm, plus another $50mm subject to certain project milestones.
• Gasoline appears especially tight heading into driving season and could take margin leadership this year over distillates.

Product Inventory, Demand, and Margin Chart

(Shaded areas show the 5-year range 2017-2021)

John M. Daniel

Managing Partner, Founder

Daniel Energy Partners, LLC

832-247-8215

jd@danielep.com

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