Energy Weekly Digest

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Energy Weekly Digest

4Q 2019 Earnings - MRO, AR, NBL, PDS, DO, NOV, AM, NBLX, DCP, E&P Super Model 2.0, MRO Case Study, Valaris fleet status report and more

Exploration & Production

4Q 2019 Earnings

(MRO) Marathon Oil (/-)

Quick Look (Published on Feb 13, 2020)

MRO's 2020 outlook thoughts. Doing more in the Eagle Ford and Bakken - feels good as the Eagle Ford beat our estimates and the Bakken declined but was inline. Doing more in Oklahoma does not feel good - 4Q19 volumes missed our estimate even though Springer wells were solid. Delaware 4Q and 2020 was inline and remains relatively small. MRO needs the $200MM of REx to add inventory as 7.6 years-to-peak production typically would signal M&A or more bolt-on asset deals. Early REx indication in the Austin Chalk (1,200 bo/d) and Delaware Woodford look encouraging.

Negative Quarter. Including REx spending, MRO had a $39MM outspend vs. our estimate of $35MM free cash flow. Excluding REx spending, as MRO prefers to disclose, FCF was $111MM. The miss vs. our model was on lower oil prod'n, worse realizations (mainly international) and higher opex.

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Follow-Up (Published on Feb 14, 2020)

Struggling to find a bull case. Our 2021+ FCF outlook weakens and our NAV is down -9% post earnings. MRO now ranks #14/37 in our STM factoring in the updated 2020 and 2021 guidance compared to a #3/37 ranking when we upgraded the stock on 11/13/2019. A discounted valuation (4.4x 2020 EV/EBITDA vs. 7.0x for peers) a healthy 5.4% FCF yield and ~2% dividend yield buffers downside risk, but lack of upside potential puts MRO in the Middle Tier. For things to improve materially for MRO the Louisiana Austin Chalk or Texas Delaware need to significantly outperform expectations.

What changed. 2020 cash flow is up +$139MM to $2,886MM compared to capex up +$138MM to $2,395MM. 2020 FCF is unchanged at $490MM. FCF would have been down if not for in-the-money hedge additions. Our 2020 oil prod'n estimates are relatively unchanged at 219.8 Mbo/d with equivalent volumes down -2% to 416.6 Mboe/d. 2021 Cash flow was little changed (down <1%) as -4% lower oil prodn was partially offset by lower opex. 2021 Capex increased +$70MM to $2,347MM and our FCF estimates are down -$88MM to $700MM. NAV came down on higher capex, lower growth and worse realizations.

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Related: MRO on discover.energy

MRO, AR and NBL metrics - click to explore

(AR) Antero Resources (+/)

Quick Look (Published on Feb 12, 2020)

Cost-cutting a continued step in the right direction, but outspend still high. Our first pass using AR's 2020 guidance shows a ~$75MM lower outspend as reduced capex/opex and higher liquids mix more than offsets lower realizations. AR's 2020 budget is based on $825/ft well costs vs. previous guidance of $830-870/ft and 4Q19 average of $860/ft. Well cost targets look ambitious, but AR did reduce costs -4% q/q and expects further savings from reduced water usage in completions. 2020 outspend of ~$250MM (before +$200MM of AM and settlement payments) is still high for a levered company; AR would benefit tremendously from better NGL prices and/or asset sales. 4Q19 was an overall positive as lower opex drove a +16% EBITDA beat vs. our estimates, more than offsetting the slight prod'n miss vs. our model.

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Follow-Up (Published on Feb 14, 2020)

Our model gets slightly better as lower capex reduces the outspend in 2020. Targeted asset sales of $750-$1,000MM in 2020 will be the real needle mover as AR's leverage is too high and debt maturities loom starting in 2021. The company is assessing different options (AM units, hedges, acreage, royalties) but low commodity prices create an overhang. AR is ranked in our Bottom Tier at #35/37 in the STM.

What changed. 2020 cash flow is up +1% on a combination of higher liquids prod'n and lower opex; capex is down -5% (-$62MM) on lower well costs. Overall our 2020 outspend improves by $71MM to -$260MM vs. -$331MM previously (not including $200MM of AM payments and settlements). 2021 cash flow is up ~1% on lower opex; 2020 outspend is little changed at -$94MM vs. -$91MM previously.

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Related: AR on discover.energy

(NBL) Noble Energy (/)

Quick Look (Published on Feb 12, 2020)

Summary thoughts - Mixed update. Concerns around 2020 guide largely played out, oil volumes just below the Street, offset by lower than expected capital; aggregate cost guide basically inline with us, but with revenues lower on volumes, cash flow is implied lower, partially offset by lower capital, implying a modest hit to our FCF. 1Q20 prod'n guide was light, even vs. our lower than Street estimates and 4Q20 light vs. us on unexpected downtime in West Africa in preparation for 2021 Alen gas monetization. With the potential negative guide out of the way the path seems more clear for NBL shares to outperform, which clearly requires execution on NBLs part.

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Follow-Up (Published on Feb 13, 2020)

Soft update on 2020 prod'n as feared, but clears the path for shares from here. We have our updated model available, which saw our volume estimates fall, with impacts to financials somewhat mitigated by lower operating costs and capex, but negatively impacted by higher interest (less capitalized) and slightly higher cash taxes. Offsetting these impacts somewhat further in our 2021+ estimates is a higher assumed gas price realization in EG as Brent linked pricing kicks in with the Alen gas monetization ramp. Our new model has NBL trading at ~6.5x 2020 hedge adjusted EV/EBITDA vs. 6.8x previously. Our NAV moved to ~$39/sh from ~$34/sh on a combination of lower operating expenses, lower USO capital costs, higher LT EG gas realizations, and the inclusion of options proceeds.  ​​​​​​

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Related: NBL on discover.energy

VNOM guidance supports our Diamondback estimates

Published on Feb 12, 2020

Inline oil guide from Viper is supportive of our FANG 1H20 and FY 2020 oil estimates. We have heard some concern around FANG's 1H20 oil volumes, and while VNOM guide is not entirely indicative of FANG's outlook, we view this inline VNOM guide as incrementally supportive of our FANG prod'n model (which includes a VNOM prod'n model). VNOM has exposure to ~70% of FANG's gross completions in 2020; non-FANG operated wells (4.2 net in process of 9.9 net total in process) have been modeled conservatively in the 2020 guide with regards to spud-to-first prod'n. Our FANG model for VNOM results will be available later today.

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Occidental Petroleum 4Q19 results and 2020 guidance follow-up

Published on Feb 12, 2020

Negative update by our read. Yesterday morning's pre-release had optically better capital efficiency, but worse operating cost guide vs. us; shares outperformed on the day. OXY pre-released better 4Q19 prod'n vs. us and Street on capex lower vs. the Street (higher vs. us), with marginally better implied 2020 prod'n vs. us on ~$100MM less capex vs. prior guidance. US pricing was also provided, which was mixed vs. us. Operating costs were higher vs. us for both US T&G and total corporate G&A and Other operating expenses, both of which offset the flow-forward of slightly better 4Q19 volumes and slightly better NGL pricing into 2020. The higher opex also had a heavy impact on our NAV as T&G in particular was higher vs. us with limited expectations of forward reductions. Net impact was a -2%/-0.6% impact to our 2020/2021 EBITDA, with a ~12% hit to NAV to ~$28/shr vs. ~$32/shr previously.  ​​​​

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Related: OXY on discover.energy

E&P Super Model 2.0 - Evolution of HEA upstream modeling

Published on Feb 14, 2020

We are as dialed into our upstream coverage, our modeling, and how companies are thinking after two months of intensive work. We completely overhauled our models, starting from a new, empty template and improved upon our prior models; to put it bluntly, this was a massive undertaking. Our goals with this effort were multifaceted:

  1. First and foremost, we wanted to create a modeling framework and interface that is more user-friendly and intuitive for our clients to work with.
  2. At the same time, we were also obviously aiming to improve our modeling outputs from this clearer, more easily vetted framework of inputs. Our updated 1,700+ type wells showed, while an oversimplification, lower EURs, with lower oil mixes, which was largely a function steeper than expected long term declines.
  3. We also created a process that will allow for faster, more dynamic flexing and revisiting of assumptions as inbound data arrives, be it from updated state well data, quarterly company financial data, or inbound data points from clients, companies, or others in the industry.  

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Cabot modeling observations and type well review

Published on Feb 11, 2020

Reviewing the state data on COG's Marcellus wells we were somewhat concerned with the trend in well data at COG as we fit our historical type curve fits ("fit plots"); our assumption is this is likely a function of increased well-spacing density as COG has developed more and more of its field in Susquehanna County, PA. Figure 1 highlights these trends; to be fair, 2019 data is limited and PA data is at times messy but it does help answer some questions we had with our old model - in our old model we were having to run increasing amounts of downtime to make prod'n fit given the number of TILs. We assume a ~5% increase to 2019 vintage productivity to make the 2020 outlook work.

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Related: COG on discover.energy

Whiting modeling observations and type well review

Published on Feb 11, 2020

We cleaned up our approach to modeling WLL's Williston assets, breaking the basin into "Williston Central" (McKenzie and Williams, ND; Richland, MT), "Sanish" (Mountrail, ND) and what we call "Williston South" (Stark and Billings, ND). With the central area providing WLL most meaninful runway were were particularly keen on making sure our assumptions in this area alinged with reported data. Our new model incorporates lower type curves (Figure 1) in this key, "Williston Central" operating area, which in part takes our NAV to ~$6.50/shr from ~$17.50/shr. Notably, with nearly $30/shr in debt, we still have substantial total asset value within our WLL model.

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Related: WLL on discover.energy

WPX Felix modeling observations and type well review

Published on Feb 11, 2020

WPX's acquisition of Felix Energy required some additional work and discussions with the company. The company expects to move back to more-2018 well pad and designs in 2H20 with a focus on the upper Wolfcamp and 6 well pads. WPX gets a ~3 Mbo/d boost to 2020 volumes as the Felix deal is expected to close in March vs. April previously.

  • 2017 wells - 21/24 wells were ~4,800' laterals with flowback parent wells.
  • 2018 wells - 35/40 wells were ~10,000' laterals on 6+ pads primarily in the upper Wolfcamp.
  • 2019 wells - 36/37 wells with data are 10,000-12,000' wells and include much bigger pads, more wells per pad, and include the 3rd BoneSpring and Wolfcamp C.

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Related: WPX on discover.energy

Callon Modeling observations and type well review

Published on Feb 11, 2020

We lowered our type well to mirror the historical average. Our examination and binning of well results by quarter showed higher early life production, but the declines at month 24+ are steeper and production stabilizes at a lower level.

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Related: CPE on discover.energy

SM Energy modeling observations and type well review

Published on Feb 11, 2020

Our prior Spraberry type well was too high, as it was based on early wells. We observed similar first ~10 month cumulative volumes, but as we rolled in additional wells the wells declined more steeply in the second year. Figure 1 and 2 show the cumulative oil volumes adjusted for lateral length. Our new type wells in the model reflect a steeper year-2+ decline profile.

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Related: SM on discover.energy

EOG modeling observations and type well review

Published on Feb 11, 2020

EOG Resources was one of the few companies with improving well results and a NAV increase. Increasing variability and uncertainty in our model - EOG's Eagle Ford has been a consistent driver of historical performance. We note that the company's future is dependent on the more variable and less drilled Delaware and Powder River Basin.

Our go-forward Eagle Ford type curve is conservative compared to historic results to account for longer laterals.  

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Related: EOG on discover.energy

ConocoPhillips observation - risks shifting as Delaware emphasized

Published on Feb 11, 2020

Sometimes we need to make calls that are out of consensus and we suspect this is one of those calls. Conoco has been a pronounced outperformer in the E&P space since ~4Q16, although not without some interim periods of underperformance. With COP shares ranking lower than OXY, XOM, and CVX it stands out as a clear candidate for the Bottom Tier. Notably, we see headwinds already emerging to COP's 10yr outlook as laid out in late 2019 with 2020 providing an underwhelming start along this long term path. Meanwhile, we have troubles making COPs 2020-2029 payout math work in our new model although there is plenty of time for that to play out in COPs favor.

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Related: COP on discover.energy

Occidental model update observation - DJ case study

Published on Feb 11, 2020

Our work on OXY provided an interesting case study on our new vs. old modeling inputs and outputs and the improvements we are pushing through our new models.

Historical calibration keyed off APC disclosures. Historically we had calibrated APC's DJ model off of the company's equivalent type curve, as shown in Figure 1. While comping this against the state data on an equivalent basis resulted in what appeared to be a reasonable type curve (Figure 2), and the implied product mix approximated APCs old disclosures (shown in Figure 1), breaking the curves into the component streams highlighted an issue with our old oil curves, shown in Figure 3.

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Related: OXY on discover.energy

Case study Marathon Oil - Balancing operating efficiency and capital spending​​​​​​​

Published on Feb 14, 2020

Marathon's 2019 results provide an opportunity to study the balance between operating efficiency and capital spending. Figure 1 shows that Marathon's original objectives for 2019 were to bring 320-350 gross operated wells to sales for $2.4B of development capital spending. The company's actual results exceeded those expectations as they brought on 374 wells with a ~10% reduction in completed wells cost per lateral foot. That enabled MRO to stay within their $2.4B of capital, but makes us ask why they didn't exceed their production objectives even though they brought on more wells? MRO's 2019 US Onshore targets were 185-195 Mbo/d and 320-330 Mboe/d, they produced within the range delivering actual results of 191 Mbo/d and 324 Mboe/d. 1Q20 guidance doesn't show a big uptick with US oil at 192-202 Mbo/d and equivalents at 325-335 Mboe/d

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Related: MRO on discover.energy

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Oilfield Services

4Q 2019 Earnings

(PDS) Precision Drilling​​​​​​​ (+)

PDS on discover.energy
Quick Look (Published on Feb 13, 2020)

Solid Q4 results. Q4 headline EBITDA of C$105MM was well ahead of HEA/consensus at $89MM. However, the results benefited from both 1) an accounting change that reclassified a portion of opex to capex; and 2) $3MM of idle but contracted payments in the US. We estimate the accounting change reduced costs by ~$6MM. Netting out the impact of the accounting change and IBC payments, still yields EBITDA of $96MM, or an 8% EBITDA beat.

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Related: PDS on discover.energy

(DO) Diamond Offshore​​​​​​​ (/+)

DO on discover.energy

Quick Look (Published on Feb 10, 2020)

Summary thoughts. A revenue-driven beat is a marginal positive. The -$53MM outspend was +$29MM better than our -$82MM estimate on 4Q CapEx of $76MM, -$43MM below our $119MM estimate and implied guidance of $110MM-$130MM. The lower capex is expected to slip into 1H20. This is DO's 7th consecutive quarter of negative FCF, with 2019 consuming $317MM. Relatively light FSR with ~$50MM of backlog added by a one-year extension. We expect investor interest on the call will focus on Q1 OpEx guidance and updated marketing commentary, particularly regarding dayrate momentum for both high-spec DP (though DO's have strong contract coverage) and moored assets.

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Follow-Up (Published on Feb 11, 2020)

What changed. We are reducing our '20 EBITDA estimate to $97MM from $137MM, compared with Street's $158MM. Our '20 estimate includes a $25MM contract termination fee receivable in Q4. Our Q1 EBITDA estimate of $8MM - cut from $43MM - compares to guidance in a range of (-$3MM) to +$13MM and Street (pre-call) of $45MM.  We leave our '21E EBITDA at $110MM, compared with Street at $164MM. We estimate negative FCF of -$167MM/ -$79MM for '20/'21. ​​​​​​​

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(NOV) National Oilwell Varco

Follow-Up (Published on Feb 10, 2020)

What changed. NOV's +29% beat vs. consensus 4Q19 EBITDA included accelerated conversion of backlog to revenue. That higher level of throughput, plus some risk to coronavirus-related supply chain disruption, results in lowering our 1Q20 estimate -12% to $189MM from $215MM, and toward the bottom half of implied Q1 EBITDA guidance between $180MM-$230MM. The lower Q1 estimate drives a -2% cut to our full-year '20 estimate to $1.0B from $1,025MM. We estimate '20 FCF at $648MM, up +$168MM Y/Y, including a $92MM contribution from reduced working capital. We see an improving cash return story as we expect NOV will begin to repurchase meaningful shares starting in 2H20.

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Related: NOV on discover.energy

Valaris provides the fleet status report

Published on Feb 14, 2020

VAL website

Neutral. VAL's updated FSR includes additional backlog for five floaters and one jackup that weren't disclosed in the updates announced by VAL in Nov/Dec, adding ~700 days of floater backlog and 30 days of jackup backlog. Since the last FSR, VAL has added $560MM of contract backlog for '20+, with additional contract coverage in '20/'21 of 4.4 floater rig years and 6.1 jackup rig years. While new rates remain undisclosed, additional drillship backlog added in '21 has a dayrate of $225k/d, including ~3 months for a priced-option (DS-10) and ~7 months for a new contract on the DS-7 off West Africa, with a rate that we estimate of at least $230k/d starting Sep '20, compared to our estimate for the period of $227k/d. We are adjusting our 4Q19E EBITDA to $30MM from $33MM (Street is at $30MM). We are adjusting our '20/'21 EBITDA estimates to $321MM/$569MM from $342MM/$567MM (Street at $298MM/$576MM).

Related: VAL on discover.energy

Noble Corp. adds 3.5 years of drillship backlog​​​​​​​

Published on Feb 12, 2020

Noble announced it will continue to provide drilling services in the Guyana-Suriname Basin to ExxonMobil (XOM $60.53 - BT) under a framework agreement including NE's three drillships with XOM off Guyana and the potential inclusion of other rigs. The agreement adds 3.5 years of backlog with an additional 6 years depending on future development decisions and govt. approvals. New backlog under the agreement will be priced at the "prevailing market rate", with dayrates updated at least twice annually, subject to a "scale-based discount" that is potentially offset by a performance bonus. As the first contract under this agreement starts in Dec '20, our '20E EBITDA is unchanged at $245MM (Street at $289MM), and we raise our '21E EBITA to $284MM from $274MM (Street at $378MM) due to higher utilization estimates related to the additional backlog.

Related: NE on discover.energy

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Midstream

4Q 2019 Earnings

(AM) Antero Midstream (/-)

AM on discover.energy
Quick Look (Published on Feb 12, 2020)

Negative quarter, but neutral on 2020. The company missed 4Q19 estimates on lower G&C revenue and less per well water usage. For 2020, EBITDA guidance is -1% below consensus while maintaining previous $300-325MM capex guidance.

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(NBLX) Noble Midstream Partners (/+)

Quick Look (Published on Feb 11, 2020)

Summary thoughts. Overall positive on better than consensus 2020 EBITDA guidance. 4Q19 missed with some one-time items negatively impacting the quarter, but we view 2020 EBITDA guidance as a positive as we think most investors have been more punitive considering recent activity level attrition. Capex guidance in 2020 is inline with our model, but does represent an increase over previous guidance. Based on the company's 4Q19 miss and lower than modeled 1Q20 EBITDA guidance, we do think there is execution risk created by the steeper ramp throughout 2020 and reliance on EPIC pipelines ramping strongly.

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Related: NBLX on discover.energy

(DCP) DCP Midstream (/-)

DCP Midstream on discover.energy

Quick Look (Published on Feb 11, 2020)

Summary thoughts. 2020 guidance misses estimates due to lower commodity prices, and high 2019 spending leads to higher structural leverage than previously thought. DCP's 2020 EBITDA guidance is based on +15-20% above strip commodity assumptions, and using strip pricing would be -3%/-2% vs. HEAe/consensus on inline capex. DCP spent +$87MM more than the high end of their 2019 capex budget (~10% above guidance high end), which exacerbates interim leverage concerns. The company is pulling back a planned y-grade pipeline expansion, which makes us question whether DCP will exercise its 30% option for 2 Sweeny fracs in 4Q20 due to concerns about spending/leverage. 4Q19 EBITDA beat our estimate and was basically inline with consensus but on much higher spending.

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