Europe Equity Research 03 March 2020
Global Energy Analyzer: Supercycle on the horizon Reap what you sow: $1tn capex hole + higher field declines = 2022 oil supply peak; asymmetric price risk
European Oil & Gas Christyan F Malek AC (44-20) 7134-9188 [email protected] Bloomberg JPMA MALEK
See page 62 for analyst certification and important disclosures, including non-US analyst disclosures. J.P. Morgan does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
This report also includes contribution from the following Table of Contents teams: Oil super-cycle in pictures...... 4 EMEA Oil & Gas Executive Summary – Sowing the seeds for the next Matthew Lofting, CFA AC (44-20) 7134-6301 supercycle: ‘oil aversion’ led by price volatility, ESG and [email protected] climate change...... 6 J.P. Morgan Securities plc …but developing economies to help drive c1mb/d growth from 2021...... 7 Alex Comer …but a shifting production mix will drive observed decline rates higher to the end of (44-20) 7134-5945 [email protected] the decade...... 10 J.P. Morgan Securities plc JPM Supply/Demand Summary: Sustained deficit from 2022 Jocelyn A Dsouza, CFA = Upside to Brent towards c$80/bbl...... 13 (91-22) 6157-3336 [email protected] 2. OPEC capacity ‘overhang’: Saudi to remain on ‘mute’ as inventory reduction > J.P. Morgan India Private Limited market share...... 16 Angelina Glazova 3. ‘Stranded’ assets: Global oil reserves a ‘mirage’ as lower carbon intensity (7-495) 967-7074 (pressured by climate change) and economic commerciality = 50% haircut to c1.7tn [email protected] ‘proven’ barrels...... 17 J.P. Morgan Bank International LLC Supercycle on the horizon...... 19 US Oil & Gas Arun Jayaram Super-cycle part 1: Non-OPEC decline rates to accelerate (1-212) 622-8541 as production mix shifts to deeper water and tighter rock.20 [email protected] Establishing regional and geological decline rates via the corporates – fundamental J.P. Morgan Securities LLC JPM analysis leverages reported production data across our global equities coverage Phil Gresh, CFA universe; 42% of non-OPEC production in 2018...... 22 (1-212) 622-4861 [email protected] Key drivers of corporate decline trajectories: field size, field J.P. Morgan Securities LLC consolidation/diversification...... 23 John M Royall, CFA Geology / portfolio mix the key determinant of regional decline rates...... 25 (1-212) 622-6406 JPM forecast: Production shift toward deepwater and shale to drive increased decline [email protected] rates from 2020+...... 26 J.P. Morgan Securities LLC Super cycle II: “Missing Trillion” – underinvestment in Sachin Sharma black oil sees supply peak in 2022 ...... 28 (1-212) 622-1304 [email protected] Tackling the Supply / Demand Bear Debates...... 35 J.P. Morgan Securities LLC Global Oil & Gas 1. US Shale: Key driver of global crude growth but the Rodolfo Angele, CFA ‘magic dust’ is running out, while lower oil = lower volumes (55-11) 4950-3888 ...... 36 [email protected] Banco J.P. Morgan S.A. US Shale (cont.) – Growth runway remains healthy but shareholder pressure on capital framework + productivity slowdown means 2020-25 growth quantum less Scott L Darling than in previous decade ...... 37 (852) 2800 8578 [email protected] US Shale (cont.) – A tighter capital frame on shale economics means greater J.P. Morgan Securities (Asia Pacific) asymmetry to oil prices; downside risk to volume growth at spot WTI as a larger Limited proportion of Permian growth diminishes ...... 38 Ricardo Rezende, CFA 2: OPEC capacity ‘overhang’: Saudi on ‘mute’ as inventory (44-20) 7742-6896 [email protected] reduction > market share...... 39 J.P. Morgan Securities plc OPEC (cont.) – As fiscal breakevens are expected to remain elevated in 2020, we expect OPEC to maintain its policy of prioritizing revenue over market share, seeking to put a ‘floor’ on Brent of c$60/bbl...... 40
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
OPEC (cont.) – 2021/22 the ‘Tipping Point’: Saudi fiscal breakeven ~$70/bbl and emerging oil market deficit = OPEC growth to resume...... 41 3: ‘Stranded’ assets: Global oil reserves a ‘mirage’ of oil as carbon intensity and economic commerciality = 50% haircut to global liquids reserves of 1.7tn barrels...... 42 Reserves (cont.) – OPEC members have added over 800bn bbls of reserves since 1980 (i.e. a 190% increase), with Venezuela and Saudi Arabia accounting for c50% of total OPEC reserves ...... 43 Reserves (cont.) – Non-OPEC has added c230bn bbls of reserves since 1980 (i.e. an 89% increase), with Canada, Russia, the US and Kazakhstan the primary source of additions ...... 44 Reserves (cont.) – Commerciality in a low(er) oil price world = c50% fall in 1P reserves from the 10 largest global sources ...... 45
Reserves (cont.) – Commerciality in a low(er) carbon world -> CO2 intensity an increasingly important consideration in project sanctioning...... 46 Reserves (cont.) – Corporate overlay: IOCs running to stand still as, despite global reserves growth, corporate levels remain broadly unchanged at c300bn boe; reserve life continues to fall to multi-year lows on reduced exploration finds...... 47 4. ‘Peak’ oil demand / climate change: Reality check needed; delivering cheap energy to developing economies means black oil is not ‘dead’ in Energy Transition ...... 48 Demand (cont.) – Emerging Markets: developing economies’ growth ‘engine' still highly dependent on oil ...... 49 Demand (cont.) – Risk Scenarios: Demand growth to fall to as low as c700kb/d pa to 2030 in a ‘global slowdown’ scenario; meeting SDS implies demand to fall to c95mb/d by 2025...... 50 JPM Scenario Summary...... 51 Scenario 1: Sanctions Removal on Iran and Venezuela from 2022...... 52 Scenario 2: Oil demand falls in-line with the IEA’s Stated Policies Scenario (STEPS) ...... 53 Scenario 3: “Value over Volume” – OPEC production growth of c2mb/d pa needed if IOC & Shale capex remains flat...... 54 Scenario 4: Decade-long underspend leads to higher declines – A 1% increase in non-OPEC non-US declines = c$300bn additional capex needed by 2030...... 55 Appendices ...... 56 Appendix A – JPM Supply estimates...... 56 Appendix B – Global Reserves Background...... 57
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Oil super-cycle in pictures Figure 1: JPM supply/ demand model to 2030e. Market to balance in Figure 2: JPM Updated oil demand forecasts, including an 2021 (v 2020 previously); sustained supply shortfall set to take hold assessment for the impact of COVID-19 on oil demand in 2020 from 2022, stemming from non-OPEC declines and diminished spend on oil developments as the industry distances itself from oil
Source: J.P. Morgan estimates. Company Data. Wood Mackenzie, Source: J.P. Morgan Commodities Research estimates.
Figure 3: JPM corporate supply analysis reveals accelerating non- Figure 4: …driven by a shift in post-peak production mix towards OPEC non-US decline rates over the medium term… higher decline ultra-deep-water and unconventional fields
Source: J.P. Morgan estimates. Company Data. Wood Mackenzie Source: J.P. Morgan estimates. Company Data. Wood Mackenzie
Figure 5: JPM US E&P team models shale growth to 2030, but it is Figure 6: OPEC – we expect further cuts in 2020 in response to exclusively driven by growth in the Permian basin, with other basins COVID-19 and model muted growth in 2021/22 as OPEC prioritizes flat inventory reduction over market share
Source: J.P. Morgan US E&P research estimates. Source: J.P. Morgan estimates.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Figure 7: Capex a key input into the forecast of potential supply Figure 8: Production impact of current direction of travel for growth in outer years. We show that the current rate of investment in investment. Underspend equates to ~1.5 mb/d loss of oil supply liquids is well below what is required to meet oil demand in 2022+
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates.
Figure 9: In order for supply to meet the JPM base case demand Figure 10: 'Reap what you sow’: pressure from lower Brent prices in forecast, an incremental $210bn is needed by 2025, compounded to 2020 is likely to cause negative adjustments to current year capex – $1tn by 2030 further exacerbating the long term supply risk 60.0 45.0 30.0 15.0
% 0.0 -15.0 -30.0 -45.0 -60.0 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 E E 0 0 0 0 0 0 1 1 1 1 1 1 1 1 1 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 0 0 2 2
Oil price change (%) Bull case 2020 (%) Bear case 2020 (%) Base case 2020 (%)
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates.
Figure 11: Gap between stranded vs. commercial reserves widening; Figure 12: Applying the ‘low carbon’ ‘low breakeven’ overlay to as low carbon mandates are considered alongside commercial global 1P reserves, implies a near halving of the 1P R/P ratio down to viability just 25 years.
Source: J.P. Morgan estimates, BP statistical review of world energy 2019, Wood Mackenzie Source: J.P. Morgan estimates, BP statistical review of world energy 2019, Wood Mackenzie
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Executive Summary – Sowing the seeds SUPERCYCLE: A multi-decade-long wave in the economic cycle (when for the next supercycle: ‘oil aversion’ led by looking at financial markets, from RN Elliot). Adapting to oil & gas: price volatility, ESG and climate change
Wave 1 (“too early to buy”: from an oil perspective we suggest 2016-19e) – Is the oil supply crunch thesis ‘dead’? The ‘crying wolf’ in oil markets was a first wave of the supercycle; (capex-led) supply shock that never was. Over the past five years the industry has fundamental news is universally materially cut investments and yet oil production has continued to grow. This can be bearish, most recent downtrend (2014- 2016) considered to be still in force, attributed to: (i) lower than expected decline rates as oil companies invested more in analysts continue to revise estimates optimizing producing asset performance, (ii) large inventory of funded greenfield lower. projects sanctioned during the previous upcycle coming to fruition; (iii) capital continued to flow into US shale despite oil prices falling as the industry pivoted to Wave 2 (“time to buy”: JPMe 2020e- short-cycle projects and capital markets continued to fund incremental capex; (iv) 2022e): news remains generally bad, deflationary oil field service pricing and a supply chain conducive to producing an prices test lows, market sentiment remains bearish, but some positive increased proportion of brownfield volumes for fewer dollars invested. signs emerge (such as pricing of commodities and services). So why call for a production peak now? We leverage our global oil equities team company models to show that as liquid hydrocarbon supply from higher-decline-rate Wave 3 (“too late to buy”: JPMe unconventional and deepwater sources increases, global observed decline rates will 2023e-2030e): news flow turns increase by c1% to c8% by 2030E, equivalent to an additional annual supply loss of positive, earnings upgrades re-appear, share prices rise quickly, corrections c300kb/d. Taken together with IOCs’ capital flight from black oil, led primarily by fast are short-lived. emerging energy transition mandates, equivalent to c$1tn of underspend to 2030 (incorporates material improvements in F&D costs), we model a supply peak in 2022 Energy transition pressures have seen at 102mb/d. In layman terms, the ‘wall’ of new supply emerging from shale and non- IOCs pivot to developing gas OPEC that has characterized the oil market over the past few years should be likened resources and a disproportionate to a ‘waterfall’ which when walking through reveals significantly fewer barrels from spend in low-carbon businesses 2022.
Current levels of oil investment are Figure 13: JPM supply/ demand model to 2030e. Market to balance in 2021 (previously we only sufficient to meet demand assumed 2020); sustained supply shortfall set to take hold from 2022, stemming from non-OPEC growth until 2022 as supply peaks declines and diminished spend on oil developments as the industry distances itself from oil during the period….
…to offset this shortfall our proprietary capex model (survey of 100 top oil producers) suggests the industry needs circa $210bn cumulative spend hike (~$35bn p.a.) vs the prevailing trend by 2025, rising to ~$1.0 trillion (c$80bn p.a.) by 2030
While OPEC budget fiscal breakevens remain elevated in 2020/21, we expect the group to maintain its policy of prioritizing revenue over Source: J.P. Morgan estimates. Note: *We assume OPEC crude production falls by 1.5mb/d 2020 vs 2019 to c28mb/d, before market share, seeking to put a ‘floor’ reverting to growth of c500kb/d in 2021 and c1mb/d in 2022/23. on Brent of c$60/bbl… While oil demand growth is expected to remain depressed in 2020 owing to …in a global economic recessionary COVID-19 (we model growth of 210kb/d vs. c770kb/d previously), we assume scenario where demand is weaker renewed demand growth from next year and our baseline forecast is close to 1 (expanded on page 45) we would mb/d y/y from 2022 to 2025, reaching 105.4 mbd aggregate global demand in 2025. expect OPEC to respond through deeper cuts to help mitigate an We expect Emerging Markets to constitute a major driver of global demand growth inventory surplus through to 2030. Industrial and transport growth (including aviation, shipping and road) in developing market economies (particularly those experiencing large demographic and population growth) will be a major driver of oil demand to 2030 and beyond.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
While supply is plentiful, demand is ‘king’: COVID-19 headwinds = muted outlook in 2020… COVID-19 – V-shaped recovery is threatened by growing ex-China cases After recovering about a third of the January COVID-19 losses over the first three weeks of February, commodities markets were freshly roiled again last week as cases outside of China began to escalate, especially in South Korea, Japan, Iran and Italy. While the effectiveness of containment measures in China suggest a peak in domestic infections around early March, the pickup in infections across the rest of the world has fueled fears of a global pandemic. In aggregate, our J.P. Morgan Commodities team have cut their 2020 oil demand growth forecast by ~560kbd to ~210kb/d. —volumes that China may not be able to be fully recovered in the latter part of the year. For example, while manufacturing activity will likely rebound sharply in 2Q and 3Q, gasoline and jet fuel demand will likely not be recouped via catch-up travel later in the year. As a result, net demand growth between 2020 and 2021 has been reduced by c160kb/d.
The longer the duration of COVID-19 and its impact on oil prices, as demand remains depressed, the greater the expected response of the oil industry. Our long- term analysis suggests that for every 1% move in average oil price y/y the industry adjusts capex by ~ 1%. YTD average Brent oil price is ~8% below the FY19 average, given little support from the forward curve in 2020 we suggest downside risk to our most recent E&P capex forecast for 2020.
Figure 14: E&P capex (ex. MENA) and Brent oil price (% change YoY) – on a 15 year view oil industry capex adjusts ~1% for every 1% move in YoY oil prices - 2020 YTD is ~8% below 2019 average suggests 8% downside risk to our forecast (flat YoY ex-MENA) 60.0 45.0 30.0 15.0 0.0 -15.0 -30.0 -45.0 -60.0 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 E E 0 0 0 0 0 0 1 1 1 1 1 1 1 1 1 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 0 0 2 2 Oil price change (%) Bull case 2020 (%) Bear case 2020 (%) Base case 2020 (%)
Source: J.P. Morgan estimates, Bloomberg. Note 2020 oil price is an average of the Brent forward curve and YTD.
…but developing economies to help drive c1mb/d growth from 2021 Our J.P. Morgan Commodities team have constructed a framework to forecast oil demand growth over the next decade, assuming a base-case 2.6% annualized GDP growth to 2030. Our longer-term forecasts are also shaped by expectations for demand growth to slow on an absolute and percentage basis after 2025 based on the proliferation of renewables, EVs and technological efficiencies. However, as per our Energy Transition V2.0 analysis, absolute demand is expected to grow during the period. In our baseline forecast, we project oil demand growth to average close to 1 mbd y/y from 2022 to 2025, reaching 105.4 mbd in 2025.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
We model large oil consumers such as the US, China and India by evaluating structural changes in their economies and their energy intensities and expect US oil demand growth to average just 40 kbd y/y over the next 5 years, with growth actually flat-lining between 2022 and 2025 before contracting from 2026 onwards. However, while oil demand is expected to shrink in developed countries, we expect Emerging Markets to remain a major driver of global demand growth through to 2030.
Figure 15: Our base case demand sits mid-range between potential Figure 16: While we expect a 2020 nCoV demand shock, from 2021+ scenarios, and assumes a 2.6% GDP CAGR to 2030, as well as an our base case assumes renewed demand growth averaging c1mb/d annual improvement in energy intensities of 1.9%. to 2030
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Ignoring physical capex needs, headline global oil supply appears sufficient to meet demand growth to 2025… Exclusive of considerations for both project economics and medium-term corporate spending guidance (led by the global IOCs), we leverage our analysis of i) Non- OPEC non-US projects, combining production forecasts across our global equities coverage universe with Wood Mackenzie projections for the balance of remaining fields, ii) US Shale – led by our North American E&P research team, and iii) OPEC supply strategy to build a picture of unencumbered growth to 2030. For 2020 and 2021, we assume supply growth consistent with our JPM commodities forecasts.
Incorporating expectations for a deepened OPEC ‘COVID-19 cut’, we model net supply growth of 300kb/d/ y/y to a total 2020 liquids supply of 100mb/d, a c200kb/d surplus vs 2020E global liquids demand. Post 2020, our estimates based on notional unrestricted capex show non-OPEC supply growth averaging c1.25mb/d 2021-25, led by US Shale (which contributes 43% of 2020-25 cumulative supply growth from the top five countries), Brazil, OPEC, Norway and Canada.
Figure 17: We expect non-OPEC growth of c2mb/d led by US Shale, Figure 18: 2020-25E cumulative supply growth breakdown from the Norway (Sverdrup), Brazil (Buzios) and Canada (Oil Sands) - five largest growth sources - US Shale is set remain a key driver of partially offset by OPEC production cuts of c1.5mb/d y/y. supply growth to 2025
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates.
2020-30 supply outlook based on an unrestricted capex view is split into three key drivers: US Shale. We incorporate our US Shale team’s forecasts for L48 crude production growth of ~c770kb/d in 2020 to a 2020 average 10.7mb/d. What we observe is that all onshore and offshore basins outside of the Permian are forecast to deliver flat production over the next decade. Instead, ~100% of the theoretical 6.5mb/d of growth comes from the Permian basin in Texas and New Mexico. The future of the US, effectively half of global supply growth, therefore becomes Russia/Vostok – The Russian solely reliant on the continued inventory, productivity and efficiency growth in Arctic could yet offer a this specific (and prolific) basin. surprise. Whilst details are sparse at this juncture, OPEC. Geopolitical sanctions and production restrictions (justified through an Rosneft’s Vostok project inventory overhang and, at least near term, demand issues related to trade wars looks as though it could be and COVID-19 virus outbreak) cloud the MT supply picture. We expect the world’s largest oil project tightened production restrictions in 2020, before modelling c500kb/d of growth in with up to 2Mbbl/d of 2021 and an avg. c1mb/d of growth in 2022/23 (2022-30 avg 300kb/d). production. Click here for our CEEMEA team’s analysis Non-OPEC Non-US: We have good visibility on production from non-OPEC on the project non-US sources set to come on-stream in the next couple of years. These projects are mainly greenfield, and largely ramping up in 2020. As a result, we expect
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
supply growth to continue, located in Brazil (through projects such as Buzios and Mero), Norway (through Johan Sverdrup and Johan Castberg), and Russia (including the Vostok oil project). However, as demonstrated in Figure 20, 2020 represents the medium-term peak given the level of investment in recent years.
Figure 19: US Shale – the Permian remains the key driver of crude Figure 20: Non-OPEC non-US supply growth is set to be production growth to 2025, offsetting net declines on other fields increasingly driven by deepwater and ultra-deepwater projects
Source: J.P. Morgan US E&P Research Source: J.P. Morgan estimates.
…but a shifting production mix will drive observed decline rates higher to the end of the decade
Understanding observed global We leverage our global oil equities team supply models to conduct detailed analysis decline rates is key to predicting on the 15 largest publicly traded oil and gas producers by non-OPEC production the y/y change in supply from (42% of the 2018 non-OPEC total). The industry has benefitted from reduced decline post-peak fields and defines the rates in recent years: We estimate that compared to highs of >8% in the mid-2000s, required rate of future discovery decline rates fell to lows of <3% by 2014, before stabilizing in recent years at c6%. and production if global oil and We identify the key drivers of lower decline rates as 1) a migration towards larger gas demand is to be met fields, 2) increasingly focused drilling, 3) a relative imbalance of new vs. old fields (>c35% pre-peak rather than on decline) – a function of the significant growth in We focus our analysis on the 15 investments in the 2010-2014 period, and 4) currency depreciation/tax benefits. largest publicly traded oil and gas producers by non-OPEC Figure 21: Short-term benefit from declining oil prices is over - JPM Corporate analysis production given consistent interpretation of OPEC decline rates is a challenge due to the scale of exclusions from the dataset that need to be made – e.g. OPEC production cuts; sanctions on Iran/Venezuela, and disruptions in Libya/Nigeria.
Without assuming any increases in decline rate per field type, the shift in post-peak field mix to 2030 implies non-OPEC non-US Source: J.P. Morgan estimates, Company Data. decline rates will increase by c1% to c8% by 2030, equivalent to an additional annual supply However, while the above factors significantly impact the decline rate loss of c300kb/d. trajectories in individual fields, we show that understanding the portfolio mix (in terms of basin type) is key to estimating decline rates by region. For example, Russia and China (which contribute >60%% of the total production in our analysis) have an average 2016-2018 decline rate of 5.4%, significantly lower than their EU, US and LatAm peers (2016-18 avg 10%), which we view as a function of their
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
outsized exposure to conventional onshore fields. We estimate decline rates of c6% “Low growth” the capex mantra at conventional onshore fields, 8-13% at offshore fields, and c17% at unconventional of 2017-2020, as the industry onshore fields (excl. oil sands). continues to distance from oil…
…we see approaching supply As a result, we observe that the industry’s continued prioritization of ‘value challenges that even major over volume’ has led to outsized growth in both unconventional oil (i.e. US technological advances (or high Shale) and (ultra-)deep-water developments – both of which are higher-decline demand destruction) may not be type geologies. This suggests that in the future the industry should experience higher able to solve. The base of this declines than today; without adjusting for increased decline rates per basin type, analysis comes from our Global increasing field age or technological advancement. In aggregate, the shifting post- E&P capex model. Surveying peak field mix to 2030 implies non-OPEC non-US decline rates will increase by c1% over 100 of the top oil producers, it has historically to c8% by 3030, equivalent to an additional annual supply loss of c300kb/d. served as a good indicator of Moreover, we see potential further upside to this estimate as average field ages capex trends increase on a reduced rate of project startups.
Figure 22: A ‘value-over-volume’ mentality means non-OPEC Figure 23: Excluding the US (where observed decline rates are production growth has shifted towards premium-margin (ultra) obscured by continued ramp ups in Shale) we expect non-OPEC deepwater and unconventional projects, which exhibit the highest decline rates to increase to c8% by 2030, driven by a shift in declines production mix from post-peak fields
Source: J.P. Morgan US E&P Research. Source: J.P. Morgan estimates.
What headline production estimates ignore: capital flight from black oil to drive a decade of underspend equivalent to c$1tn with significant damage already done The above points to a supply growth ‘peak’ of ~107 mb/d in 2026. This ties closely to the forecast demand in the IEA’s Stated Policies Scenario, which suggests an outlook of balanced market dynamics. However, this analysis does not include a capex overlay, which we conduct in this report to arrive at a realistic supply scenario driven by prevailing activity on current projects and those yet to be sanctioned within IOC budget plans. Capex remains a key input in the supply picture given the declining nature of oil and gas fields. While we expect continued efficiency gains to occur (JPMe 3% CAGR 2020-30) as the industry readily takes up new technology, we still see a need for higher spending YoY vs. recent trends in order to meet demand growth over the medium term. Our analysis reveals current levels of investment are only sufficient to meet demand growth until 2022 as supply peaks during the period.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Figure 24: JPMe bottom-up capex required to meet future oil demand – Implies c$1tn missing Our analysis shows current spend to 2030 – Assuming a 3% capex efficiency gain pa, industry prevailing spend levels of investment are only sufficient to meet demand growth until 2022 as supply peaks during the period
To offset the 2025 shortfall, we calculate this needs circa $210bn cumulative spend hike (~$35bn p.a.) vs the prevailing trend, rising to >$1.0 trillion (>$80bn p.a.) by 2030
Source: J.P. Morgan estimates.
A number of factors have been considered in consideration of our estimate of industry prevailing spend: (i) risk of an increasing proportion of upstream capital budgets invested in gas, limiting potential liquids supply, (ii) an increasing proportion of total IOC budgets invested in renewables, limiting growth in upstream investment overall, (iii) capital available to US shale is declining, limiting rate of supply growth at the current time, (iv) oil service pricing overall is no longer deflating, (v) efficiency gains, primarily through faster uptake of technology, are still apparent and potentially increasing.
The recent trend in upstream investment has been a global mid-single-digit increase YoY (~5% CAGR from 2016 nadir, but only ~3% CAGR when adjusting to oil spend); assuming this were to continue implies the industry will be underspending ~$210bn cumulatively by 2025 and c$1tn by 2030. We estimate that this equates to ~5mb/d of cumulative production not materializing by the middle of the decade, with a ~ 1.5mb/d annual impact from 2023. In theory, this would also suggest that a production shortfall from capex underspend won’t be apparent until 2022. Moreover, if we apply the same logic out to 2030 we calculate a cumulative $1tn incremental spend is required to meet 2030 demand of 111mb/d.
Figure 25: Implied production shortfall assuming capex growth remains at prevailing 3% pa
Source: J.P. Morgan estimates. Note: We assume liquids supply in-line with our JPM Commodities forecasts to 2022. Capex risk applied 2023+
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James Thompson (44-20) 7134-5942 [email protected]
JPM Supply/Demand Summary: Sustained deficit from 2022 = Upside to Brent towards c$100/bbl
The supply story of oil is one of capital discipline and reduced investment, We summarize our aggregate exacerbated by depressed oil prices and IOCs efforts to diversify away from oil. The supply/demand estimates, result is a declining production profile, with supply expected to contract at a CAGR of reflecting our expectation for -0.1% through 2030. The demand story is more nuanced. The decarbonization efforts peak supply in 2022 at around in the OECD countries, where rise of renewables and improvements in energy 102mb/d, powered by a structural under-spend in oil efficiencies will lead to a relatively stable demand profile. Most increases in oil capex and accelerating declines. consumption instead will come from non-OECD countries with their stronger For 2020 and 2021 we model economic growth and increased access to marketed energy driving a 1% growth in supply growth of c0.3mb/d and global oil demand over the period 2019 to 2030. The combination of the supply and c1.0mb/d respectively, driven by demand side dynamics suggests that the global oil market could move into large and increasing non-OPEC sustained deficits past 2022, reaching an extreme 1.7 mbd by 2025. Running this production from US Shale, Brazil, and Norway scenario through our pricing model suggests these balances would lead to Brent oil prices rising steadily from 2022 onwards, averaging around $80/bbl in 2023, $100/bbl in 2024 and $190/bbl in 2025 as shown in below. We remain cognizant that COVID- 19 led demand weakness could continue to weigh on oil prices and model a bear case scenario that growth remains muted over the medium term. Should this occur our scenario analysis suggests a bear case of $40/bbl.
Table 1: JPM supply/demand summary: We forecast a sustained supply-deficit from 2022, driven by an increasing "capex risk" to supply. (mb/d) 2018E 2019E 2020E 2021E 2022E 2023E 2024E 2025E OPEC Total 36.9 34.9 33.5 34.0 35.1 36.0 36.1 36.2 OPEC Crude 31.4 29.4 27.9 28.4 29.6 30.4 30.6 30.7 OPEC Other Liquids 5.5 5.5 5.5 5.5 5.5 5.6 5.5 5.5 Non-OPEC Total 60.4 62.4 64.1 64.7 65.6 66.1 66.9 67.6 Non-OPEC Non-US Crude and Other 45.1 45.4 46.2 46.5 46.6 46.5 46.6 46.6 US Crude 10.5 11.8 12.6 12.9 13.6 14.0 14.5 15.1 US Other Liquids 4.9 5.2 5.3 5.3 5.5 5.6 5.7 5.9 Processing Gains and Others 2.3 2.3 2.4 2.4 2.4 2.4 2.4 2.4 Implied Capex Shortfall n/a n/a n/a n/a -1.2 -2.7 -4.2 -5.4 Total Liquids Supply 99.6 99.7 100.0 101.0 101.9 101.8 101.2 100.8 JPM Demand Estimate 99.0 99.6 99.8 101.1 102.2 103.2 104.3 105.4 Surplus (deficit) 0.6 0.1 0.2 (0.1) (0.3) (1.5) (3.2) (4.6) OECD Inventory (mm bbl) 2,837 2,916 2,943 2,931 2,901 2,649 2,079 1,239 Super-cycle scenario analysis $63/bbl $65/bbl $67/bbl $78/bbl >$100/bbl >$100/bbl JPM Global Equities Oil price forecast* $55/bbl $55/bbl $55/bbl $60/bbl $60/bbl $60/bbl JPM Commodities forecast** $63/bbl $58/bbl Source: J.P. Morgan estimates.*Our Global Equities price forecast is based on the forward curve to 2022 and MTM quarterly; from 2023+ we forecast $60/bbl LT; **At this juncture, Commodities 2- 3 years Brent oil price forecast remains unchanged at $60/bbl. However, if the baseline scenario of constrained supply comes to fruition, the long-term price should clearly reset higher. Our JPM commodities pricing model therefore indicates an asymmetric risk/reward on Brent towards c$80/bbl by 2023. This compares to our JPM equities We incorporate our global long-term Brent assumption at c$60/bbl, and a 2023 forward curve average c$53/bbl economics/commodities team’s as of 2nd March 2020T. Beyond 2023, a rising deficit and sustained OECD inventory forecasts for 2020-25 demand growth (updated with this note), drawdown indicate the potential for either significant demand destruction as oil prices averaging c1mb/d driven by rise, or a rapidly rising call on OPEC. However, as outlined in the key debates stronger economic growth and section that follows, we don’t believe OPEC will raise quotas until OECD increased access to marketed inventories move structurally lower, in line with historical averages as shown energy from non-OECD below in Figure 26. countries (as outlined on page 48)
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James Thompson (44-20) 7134-5942 [email protected]
Figure 26: We expect OPEC to closely monitor OECD inventories and only resume production growth once levels are broadly in line with historical averages
Source: J.P. Morgan estimates.
Clearly such sharp price increases will either elicit supply response or demand itself Of course, a model forecast is as will get destroyed. The model stipulates that by 2023 a dramatic change needs to good as its inputs and here the occur either on the demand or supply side to balance the market and prevent prices main risk to our conclusions on from spiking above the ‘comfort zone’ of the current $65-75/bbl range. For example, the demand side lies in the fact assuming an unchanged supply profile, for 2024 Brent oil price to average in the $65- that our demand analysis does 75/bbl range, almost 2.2-3.2 mbd of demand needs to be destroyed. And vice versa, if not account for economic demand were to prove sticky, supply needs to be scaled up by the similar amount to cycles, meaning our forward looking forecast is based on rebalance the market away from the $100/bbl price. The modal view on 2025 requires global growth remaining in and a 3.9-4.7 mbd net action to bring the Brent oil price back into the range. around potential with energy intensity deepening in non- Another uncertainty around growing COVID-19 cases is the potential impact on US OECD countries and remaining elections this year and the knock on effects to US energy policy and oil supply. As flat in OECD… Super Tuesday voting is underway in the US, the democratic primary has narrowed to …On the supply side, the main essentially a race between Bernie Sander representing the more left wing of the party risk is around the variability of and Joe Biden representing the moderate democrats. Yet just while some further OPEC+ arrangements and shale clarity around the likely democratic candidates has emerged, the spread of COVID- output in response to possible 19 has introduced a new dimension of uncertainty. A rapid spread throughout the US electoral changes that could alter energy policy in the US. could potentially disproportionately boost Democratic candidates who want to push for stronger public health systems such as Sanders. Yet a nomination of Sanders would also increase the potential for significantly more restrictive energy policy such as a push to ban fracking and fossil fuel exports. As we explored in a note last month, even a relatively more moderate scenario assuming no new lease extensions on public lands and waters after 2020 could lead to a decline in production from basins with federal exposure of 1.8 mbd versus our prior estimates by year-end 2025 and should warrant a risk premium of between $4-4.50/bbl for Brent prices (Commodities Strategy: US election risk premium worth $4-4.50/bbl for Brent oil price, Kaneva et al., 14 February 2020). We outline the key supply/demand bear debates in the next section
.
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James Thompson (44-20) 7134-5942 [email protected]
Addressing the key supply/demand bear debates
1. US shale: key driver of global crude growth but the ‘magic dust’ is running out, while lower oil = lower volumes US Shale - COVID-19 update: At Over the past four years, the oil market has been characterized by excess supply prevailing oil prices our US primarily driven by U.S. shale growth, and our US Shale team forecasts L48 crude shale team have published (click production up c770kb/d in 2020 to a 2020 average 10.7mb/d, largely driven by the here) a scenario which implies Permian Basin. Looking beyond 2020, we believe that US shale growth will largely 100-170kb/d of downside to 2020-21 production estimates, be shaped by the industry’s ability to reduce cycle times and mitigate declining and c1mb/d of downside by 2025 productivity as basins (the Delaware in particular) become more developed. - This supports our view shale growth is under pressure given However, the confluence of 1) an increasing mix of children wells, 2) constrained capital restrictions capex led by greater shareholder pressures on FCF and TSR and 3) a slow-down in productivity gains (albeit with still plenty of running room for efficiency gains) means that the net quantum of new barrels coming online over the next five years (JPMe 2020-24 aggregate growth 2.6mb/d) will be less than the during the previous period (JPMe 2015-19 aggregate growth 3.1mb/d). Moreover, with capital markets more constricted to the E&Ps and energy investors prioritizing free cash flow generation, some operators are now sacrificing full section NPVs to generate higher near-term economics (wider well spacing, lower proppant loading).
Figure 27: JPM US Crude Production Model – Unencumbered by capital constraints, the Permian We incorporate our Shale team’s remains the key driver of Shale growth to 2030, offsetting net declines on other fields retooled production model (here) into our global supply forecasts, which builds off the production models within their individual company forecasts While the shale growth runway remains healthy, shareholder pressure on capital framework + productivity slowdown means 2020-25 growth quantum less than in previous decade Moreover, a tighter capital frame on shale economics means greater asymmetry to oil prices; Source: J.P. Morgan estimates. downside risk to volume growth given spot WTI <$50/bbl as a With productivity and technology-led efficiency gains slowing, breakeven economics larger proportion of Permian growth diminishes will be key in assessing the second order of volume growth linked to oil prices. While breakevens have continued to drift lower as US shale remains competitive at $50/bbl, we believe they have normalized (ranging between $45/bbl in the Midland Basin to $55/bbl in the Delaware). This suggests that spot WTI <$50/bbl should have a negative impact on future volume growth as returns diminish. Under higher oil prices we expect marginal FCF to be prioritized to the shareholder over incremental capex/volumes.
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James Thompson (44-20) 7134-5942 [email protected]
Figure 28: Full-Cycle Oil Break-Evens - The bulk of US shale gravitates around $50-55/bbl breakeven (assuming 25% BTAX IRRs) vs spot WTI at c$50/bbl
While OPEC budget fiscal breakevens remain elevated in 2020, we expect the group to maintain its policy of prioritizing Source: J.P. Morgan estimates. revenue over market share, seeking to put a ‘floor’ on Brent of c$60/bbl… 2. OPEC capacity ‘overhang’: Saudi to remain on ‘mute’ as …In the same vein, in a global inventory reduction > market share economic recessionary While OPEC budget fiscal breakevens remain elevated in 2020 ($45-90/bbl) we environment where demand is weaker (expanded on page 50) expect the group to maintain its policy of prioritizing revenue over market we would expect OPEC to share, seeking to put a ‘floor’ on Brent of c$60/bbl. respond through deeper cuts to Saudi Arabia’s oil policy agenda has a natural bias towards ‘value’ over ‘volume’ as help mitigate an inventory we triangulate the Kingdom’s fiscal budget breakeven with Saudi Aramco’s cash surplus. breakeven (post dividend and capex) of $60/bbl, on average across 2019-20. With this in mind, we believe that in our base case scenario of an oil market deficit emerging in 2021, the response by OPEC+ will be muted as their collective agenda is to drive both US and OECD inventories back towards historical averages over and above mitigating a short-term move higher on the front-end of the curve. As a result, we think the back-end of the curve would have to move materially above $70/bbl to warrant a renewed production framework of higher quotas.
We look to 2021/22 as a ‘tipping point’ for relaxed OPEC production quotas. As a structural supply deficit emerges and with that a sustained inventory drawdown, we would expect the back-end of the curve to move higher. This in turn should instigate a production response by OPEC which we model from 2021, calibrated against a continued drawdown in global inventories. We model OPEC crude production growth of 500kb/d in 2021, c1mb/d in 2022/23, and averaging 300kb/d pa to 2030. As a result, we expect OPEC spare capacity, excluding members under sanctions, to fall to 2.1mb/d by 2030, broadly in line with the group’s historical level of circa 2mb/d.
Figure 29: We model OPEC Supply growth post 2021, led by Saudi, Iraq, the UAE and Kuwait OPEC production growth is conditional on global inventory drawdown and while fiscal breakevens remain elevated. This view is reinforced by our recent Global Oil & Gas CEO conference in November (here), where experts on Saudi oil policy pointed to c$65/bbl as the kingdom’s fiscal ‘comfort’ level in the absence of significant FDI.
Source: J.P. Morgan estimates. Note: production estimates stated excluding Iran, Venezuela and Libya given restrictions.
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James Thompson (44-20) 7134-5942 [email protected]
While we acknowledge that if sanctions on Iran and Venezuela were removed we could see a surge in production, we believe that OPEC+ (led by Saudi) will seek to absorb the additional barrels though respective quota cuts given their renewed focus to reduce global inventories. Equally, and in the same vain, in a global economic recessionary environment where demand is weaker (expanded on page 50) we would expect OPEC to respond through deeper cuts to help mitigate an inventory surplus.
3. ‘Stranded’ assets: Global oil reserves a ‘mirage’ as lower carbon intensity (pressured by climate change) and economic commerciality = 50% haircut to c1.7tn ‘proven’ barrels BP’s most recent Statistical Review of World Energy estimated 2018 global proven oil reserves at c1.7 trillion barrels, enough to meet over 50 years of demand at 2018 levels. This level is little changed since 2010 and includes for example Venezuela’s heavy crude deposits. However, we think a deepened understanding of the global oil reserves base is key to understanding the potential scale of globally ‘stranded’ assets, or whether, in fact, a need for further discoveries remains. We highlight: OPEC members have added over 800bn bbls of reserves since 1980 (i.e. a 190% increase), with Venezuela and Saudi Arabia accounting for c50% of total OPEC reserves. As of 2018, 71.8% of the world's proven oil reserves were located in OPEC Member Countries (inclusive of Ecuador and Qatar), equivalent to 1.2 trillion boe, or 87 years’ of supply at a 2018 OPEC production level of c39mb/d. Since OPEC started to set production quotas (partly) on the basis of reserves levels in the 1980s, many of its members have reported significant increases in their official reserves – for example, between 1983 and 1984 Kuwait’s reserves increased by c40%. Non-OPEC has added c230bn bbls of reserves since 1980 (i.e. an 89% increase), with Canada a primary source of additions. Canadian reserves increased by over 130bn boe in 1999 after the oil sands of Alberta were seen to be economically viable; however, this addition was controversial at the time as oil sands contain an extremely heavy form of crude oil known as bitumen which will not flow toward a well under reservoir conditions.
Commerciality in a low(er) oil price and low(er) carbon world = c50% fall in 1P reserves from the 10 largest global sources Although global proven reserves reached new highs in 2018, we overlay Wood Mackenzie estimates of commercial reserves (that is the reserves from fields on production, under development or likely to be developed under c$60/bbl Brent) to show that c40% of the proven reserves from the 10 largest countries by liquids reserves (which contribute c1.5tn to total global reserves of 1.7tn) are classified as ‘un-commercial’. Simply put, the 1.7tn headline masks large disparities in production costs for the economic recovery of the oil, and a divergence in reserve accounting standards.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Figure 30: Estimated proven liquids reserves from the 10 largest Figure 31: Layering a “High Carbon” cut off to global reserves global sources fall by c730bn bbls when applying a Wood- could exclude a further 15% of reserves. Chart shows an analysis Mackenzie commercial screen (min. 15% IRR at c$60/bbl Brent) of medium-term oil-biased field developments
Source: J.P. Morgan estimates, BP statistical review of world energy 2019, Wood Mackenzie. Source: J.P. Morgan estimates, Wood Mackenzie. Note we screen for low breakeven as <$60/bbl (at 15% discount rate), and low carbon as a CO2 intensity <$30kg/boe.
Rightly or wrongly, with consensus for ‘peak’ oil demand somewhere within 2030- 2040, and a growing appetite to minimize carbon emissions, we expect the Majors to re-engineer their portfolios towards barrels that sit not just at the low end of the cost curve, but also screen competitively on CO2 intensity. Screening through both project commerciality (defined as both those on production, under development or likely to be developed given an IRR>15% at $60/bbl Brent) as well as the carbon intensity of the barrels produced, we estimate that the level of commercial and low(er) carbon reserves is around c860bn boe. This level is c150bn boe below the level required in the (most aggressive) IEA’s Sustainable Development Scenario, and over 1tn bbls below their “current policies" scenario. Moreover, a reduction in global reserves of c900 billion barrels is equivalent to approximately 25 years of global production at 2018 levels, and would reduce the global 2018 R/P ratio to 25 years, below that seen in 1980.
Figure 32: Combined with the corporate screen as discussed on page 42, this results in a global proven, low-breakeven and low-carbon reserves level c150bn boe below the level required in the IEA’s SDS, and over 1tn bbls below their “current policies" scenario
Source: J.P. Morgan estimates, BP statistical review of world energy 2019, Wood Mackenzie.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Supercycle on the horizon n o z i r o h
e h t
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e l c y c r e p u S
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James Thompson (44-20) 7134-5942 [email protected]
Super-cycle part 1: Non-OPEC decline rates to accelerate as production mix shifts to deeper water and tighter rock Understanding observed global decline rates is key to predicting the y/y change in supply from We have conducted detailed analysis on the 15 largest publicly-traded oil and gas post-peak fields and defines the producers by non-OPEC production (42% of the 2018 non-OPEC total). The required rate of future discovery industry has benefitted from reduced decline rates in recent years: We estimate that and production if global oil and compared to highs of >8% in the mid-2000s, decline rates fell to lows of <3% by gas demand is to be met 2014, before stabilizing in recent years at c6%. We identify the key drivers of lower decline rates as 1) a migration towards larger fields, 2) increasingly focused drilling, 3) a relative imbalance of new vs. old fields (c35% pre-peak rather than on We focus our analysis on the 15 decline) – a function of the significant growth in investments in the 2010-2014 largest publicly traded oil and gas producers by non-OPEC period, and 4) currency depreciation/tax benefits. production given consistent interpretation of OPEC decline However, while the above factors significantly impact the decline rate trajectories in rates is a challenge due to the individual fields, we show that understanding the portfolio mix (in terms of basin scale of exclusions from the type) is key to estimating decline rates by region. For example, Russia and China dataset that need to be made – (which contribute >60%% of the total production in our analysis) have an average e.g. OPEC production cuts; sanctions on Iran/Venezuela, 2016-2018 decline rate of 5.4%, significantly lower than their EU, US and LatAm and disruptions in Libya/Nigeria. peers (2016-18 avg 10%), which we view as a function of their outsized exposure to conventional onshore fields. We estimate decline rates of c6% at conventional onshore fields, 8-13% at offshore fields, and c17% at unconventional onshore fields In aggregate, the shifting post- (excl. oil sands). peak field mix to 2030 implies non-OPEC non-US decline rates As a result, we observe that the industry’s continued prioritization of ‘value over will increase by c1% to c8% by volume’ has led to outsized growth in both unconventional oil (i.e. US Shale) and 3030, equivalent to an additional annual supply loss of c300kb/d. (ultra-)deep-water developments – both of which are higher-decline geologies. This suggests that in the future the industry should experience higher declines than today; without adjusting for increasing field age and technological advancement.
In aggregate, the shifting post-peak field mix to 2030 implies non-OPEC non-US decline rates will increase by c1% to c8% by 3030, equivalent to an additional annual supply loss of c300kb/d. Moreover, we see potential further upside to this estimate as average field ages increase through a reduced rate of project startups. Figure 33: We believe an increase in decline rates post 2014 is Figure 34: Excluding the US we expect non-OPEC decline rates to primarily a function of reduced capex increase to c8% by 2030, driven by a shift in production mix
Source: J.P. Morgan estimates, Company data, Wood Mackenzie. Source: J.P. Morgan estimates. .
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Decline Rates: A critical factor influencing the current rebalancing of the oil market and potential price recovery. Understanding observed global decline rates is key to predicting the y/y change in supply from post-peak fields, and defines the required rate of future discovery and production if global oil and gas demand is to be met. As an example, applying a 1% increase in non-OPEC decline rates across c40mb/d (incl. Shale) expected to be in decline from 2020 could result in a c2mb/d “supply gap” by 2025. A theoretical production profile of an oil well is shown below. After production has built up to a plateau rate, over time subsurface conditions will no longer be able to support this rate of extraction, and the decline phase begins. However, while the decline rate of an individual oil well is in theory a relatively simple calculation, two practical difficulties emerge: 1) attaching sensors to production manifolds (as opposed to individual wells) obscures the underlying well decline profile; 2) while traditional decline rate calculations assume no additional capital expenditure, this differs from how fields are managed in industry. As a result, our analysis focuses on the observed decline rate per field, as opposed to the underlying decline rate per well. Figure 35: Theoretical production profile of an oil well. Our analysis focuses on the observed post-peak decline rate from non-OPEC fields since 2006.
Source: The Royal Society.
The reservoir quality, field management, level of infill drilling, workovers, and secondary recovery can significantly influence observed decline rates. Significant deviations can also be caused by development history, changes in technology or oil price, accidents, political decisions, sabotage and similar factors. Some fields have short plateau periods, more resembling a single peak, while others (especially large fields) may keep production relatively constant for many decades.
Figure 36: Example production at Petrobras’ deepwater Jubarte oilfield; Deviations in decline rates are common, caused by field development, changes in oil price or technology-led efficiency gains
Source: J.P. Morgan estimates, Wood Mackenzie.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Establishing regional and geological decline rates via the corporates – fundamental JPM analysis leverages reported production data across our global equities coverage universe; 42% of non-OPEC production in 2018 Our analysis is based on the As individual analysis on over 40,000 producing oilfields globally is a challenge for reported liquids production any outsider, we instead leverage reported production data from companies across data since 2006 from the 15 our global equities coverage. We focus on the 15 largest publicly traded oil and gas largest non-OPEC producers by non-OPEC production, encompassing 23mb/d of liquids production producers, and covers excl. OPEC and oil sands (given a typical zero-decline profile as oil recovery 23mb/d of liquids production requires mining bitumen instead of pumping crude). Our analysis includes: (42% of total non-OPEC production). EU Oils: Shell, BP, Total, Equinor, and Eni US Oils: Exxon, Chevron, ConocoPhillips, and Canadian Natural Resources Asian Oils: PetroChina and Sinopec The total number of Russian Oils: Rosneft, Lukoil and Gazprom Neft producing assets included in our dataset is over 1,100. LatAm Oils: Petrobras However, we caveat any comparison against the 40k Non-OPEC production from the 15 selected producers in our dataset has grown fields above as our analysis at c350kb/d on average since 2005. Within this, while production from the EU and consolidates numerous US oils has fallen an average 13% since 2005, the Russian and LatAm oils have smaller fields into single reported a production increase (inclusive of M&A) of over 4mb/d during the same asset lines. period. On a corporate basis, the largest contributors to growth have been the Russian NOCs Rosneft (+3mb/d since 2005) and Gazprom Neft (+0.9mb/d), as well as PetroChina (+1mb/d) and Petrobras (+0.4mb/d), offsetting reduced production at BP (-0.6mb/d) and Exxon (-0.4mb/d), amongst others.
Figure 37: Our analysis of the 15 largest non-OPEC producers covers Figure 38: The Russian oils have seen the largest share of growth, over 40% of 2018 total non-OPEC production offsetting consolidation in the EU/US.
Source: J.P. Morgan estimates, Company data, Wood Mackenzie. Source: J.P. Morgan estimates, Company data, Wood Mackenzie.
Several calculation steps are required to convert reported liquids production data into observed corporate decline rates: 1. We first reconcile reported production data on a country-level basis with Wood Mackenzie estimated field production profiles (including consolidation effects, affiliate entities, etc.); 2. We exclude production from OPEC fields, given the potential impact of sanctions, outages and production quotas; 3. We then screen for asset acquisitions, divestments and maintenance, which would obscure underlying production deltas;
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James Thompson (44-20) 7134-5942 [email protected]
4. On this ‘JPM cleaned’ production profile we then aggregate underlying production deltas from post-peak fields to calculate an observed annual decline rate.
In Figure 39 below, we display the estimated decline rates for the companies in our dataset between 2006 and 2018, and show declines have averaged c8% during the period. While basin type goes someway to explaining the decline rate profile below (for example, both Petrobras and Equinor’s upper-half decline rate is a function of their leading exposures to deepwater basins), we see further differentiation via field age and operator quality – for example, ENI has a 2006-2018 JPMe average decline rate of c9%, which we attribute to the company’s exposure to older fields as well as reduced efficiency gains vs peers.
Figure 39: JPMe corporate decline rate profile (2006-2018); declines have averaged c8% during the period; however, relative basin exposure, field age and operator quality drive further differentiation on a corporate level.
Source: J.P. Morgan estimates, Company data. Key drivers of corporate decline trajectories: field size, field consolidation/diversification In aggregate, decline rates have fallen from highs of >8% at the start of the period to below 3% by 2014, before normalizing at c6% in 2017/18. The most significant reduction came between 2011 and 2014, where high oil prices and a wave of upstream capital investment drove a reduction from 7% to <3%. However, primarily as a result of spending cuts driven by a collapse in oil prices, decline rates promptly increased, and averaged c5% in 2017/18.
Figure 40: Corporate decline rates have fallen from a weighted avg. Figure 41: Change in Change in observed decline rate (2016-18 vs c8% in 2006, to c5% in 2018 2008-12).
Source: J.P. Morgan estimates, Company data, Wood Mackenzie. Source: J.P. Morgan estimates, Company data, Wood Mackenzie.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
(Lower) Capital spending the leading driver of (higher) corporate decline rates; though impact has been reduced in recent years through focused drilling Comparing the weighted average corporate decline rates in Figure 40 above with crude prices, a trend of higher oil = lower decline rates emerges; however, we see this as a correlation, with capex (instead of oil price) the underlying decline rate driver. As shown in Figure 43, a strong relationship exists between increased IOC capex, and lower decline rates. However, since the collapse in prices and spending seen in 2014/15, decline rates have stabilized at c5% despite reduced capex, and we highlight two factors which we believe have helped stabilize decline rates: Improved operating efficiency: Corporates have fine-tuned processes to increase uptime from producing wells and processing facilities; in addition, maintenance programs have been rethought and better coordinated. Focused capex: Shrunken budgets have been directed to short-cycle projects offering the highest returns, such as infill drilling, near-field step-out drilling and satellite tie-backs. Moreover, reworked development plans and reductions in service sector costs have enhanced the efficacy of this spend.
Figure 42: As oil prices fell over 50% between 2014 and 2016, decline Figure 43: We believe this is primarily a function of reduced capex rates increased from <3% up to c7%. (RHS shows total IOC capex in $bn)
Source: J.P. Morgan estimates, Company data, Wood Mackenzie Source: J.P. Morgan estimates, Company data, Wood Mackenzie
Significant currency depreciation & tax benefits have helped the Russian oils maintain investment despite falling oil prices; helping drive decline rates lower Significant local currency depreciation has helped sustain investment levels in Russia, mitigating increases in decline rates. Another important factor helping dramatically improve brownfield decline rates in Russia is tax benefits, as producers are willing and able to boost output at mature fields when given mineral extraction tax breaks from the government. For instance, Rosneft managed to achieve an almost zero decline rate at its Samotlor field in 2018 as the tax break came into force, vs a 5% decline rate in 2016 and 3% in 2017.
Portfolio consolidation/diversification; larger fields = lower declines Aggregated across our dataset, we see a trend of reduced decline rates for companies which have consolidated production towards larger fields. This is primarily explained by geology – larger fields typically suffer reduced pressure reduction per barrel produced. Breaking down the asset split by company in Figure 44 and Figure 45 below, we show that while Shell, BP, Conoco Phillips and CNR have consolidated the number of producing fields by c20% on average since 2010, production on a per field basis has increased by an average 35%.
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James Thompson (44-20) 7134-5942 [email protected]
Figure 44: Change in number of fields 2018 vs 2010 – The state- Figure 45: Change in production per field 2018 vs 2010 – While the backed Russian oils are prominent examples of diversification, due EU majors have consolidated their asset base, increased production to the (relative) ease in obtaining licenses from the state per field has helped maintain aggregate production levels.
Source: J.P. Morgan estimates, Company data, Wood Mackenzie Source: J.P. Morgan estimates, Company data, Wood Mackenzie
Geology / portfolio mix the key determinant of regional decline rates While capex has historically been the main driver of decline rate trajectories per field, we show that understanding the portfolio mix (in terms of basin type) is key to estimating decline rates by region. We show that the biggest producing regions, Russia and China (which contribute >60%% of the total production in our analysis), have an average 2016-2018 decline rate of 5.4%, significantly lower than their EU, US and LatAm peers (2016-18 avg 10%).
Figure 46: Average decline rate by region: Russian and Chinese decline rates have historically remained below their western counterparts, primarily as a function of outsized onshore exposure
Source: J.P. Morgan estimates, Company data.
However, while currency depreciation effects have helped mitigate increases in Russia, we believe the significantly lower baseline in Russia and China is primarily a function of asset mix: the companies’ portfolios in both regions are significantly skewed towards conventional onshore fields, which have historically held lower declines than unconventionals and offshore, given better geology vs. unconventionals and lower cost drilling vs. offshore. By comparison, Petrobras’ (i.e. LatAm) observed decline rates have averaged c10% during the last 10 years. Similarly, we believe this
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James Thompson (44-20) 7134-5942 [email protected]
is a function of the portfolio exposure to deepwater and ultra-deepwater assets such as the Campos basin. The higher declines for deepwater fields reflect high drilling and well intervention costs, which often make up the bulk of development expenditure in deepwater, discouraging infill drilling.
Figure 47: 2018 Decline Rate by basin type: (ultra-)deepwater + shale = higher decline rates
Source: J.P. Morgan estimates, Company data.
We leverage our analysis of historical decline rates to estimate a 2018 decline rate by basin type, viewed through a regional basis to minimize company-specific drivers such as operator quality. In aggregate, we estimate decline rates of c6% at conventional onshore fields, 8-13% at offshore fields, and c17% at unconventional onshore fields (excl. oil sands). Through weighting these declines on a proportionate split of post-peak production by region, we arrive at a close approximation to reported actuals as shown in Figure 49 below.
Figure 48: JPMe 2018 post-peak observed decline rate by basin type: Figure 49: Weighting these decline rates by regional production split, Onshore fields typically exhibit the lowest declines we generate a close approximation to observed decline rates
Source: J.P. Morgan estimates, Wood Mackenzie. Source: J.P. Morgan estimates, Wood Mackenzie.
JPM forecast: Production shift toward deepwater and shale to drive increased decline rates from 2020+ Corporate decline rates to increase as producers embrace a ‘value over volume’ mentality Applying our basin decline estimates to the post-peak production profiles for the 15 companies included in our analysis allows us to identify potential changes in decline rates, a key driver of companies’ medium-term capex outlooks. For example, companies which we expect to see the largest increase in decline rates would be at risk of raising MT capex to maintain volumes (i.e. ‘run-harder to stand still’). To
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James Thompson (44-20) 7134-5942 [email protected]
reflect the company-specific factors involved and as discussed above, we estimate a change in decline rate by company, which we then apply to 2018 calculated figures.
In aggregate, we see the largest increases in decline rates at Petrobras, Chevron, BP and Shell. We attribute this to the companies’ outsized growth in (ultra-)deepwater offshore, driven by a focus on higher-margin production (see our deepwater deep- dive analysis here).
Figure 50: Decline Rates by Company – Impact of production shift on decline rates
Source: J.P. Morgan estimates, Company data.
Applying our decline rates to total non-OPEC non-US production, we expect decline rates to increase to c8% by 2030 as the production mix shifts Looking post 2020, we apply the above calculated decline rates (i.e. assuming no further impact from reduced capital spending or further efficiency gains) to the global post-peak production profile to 2030, generated via a JPM overlay of Wood Mackenzie data. While our analysis applies to c17mb/d in 2019 (~40% of total non- OPEC non-US production), we expect production from post-peak fields to reach over 25mb/d by 2025 (~65% total) as assets including the onshore Yuganskneftegaz fields (Russia) and PDO Block 6 (Oman), and ultra-deepwater Lula-Iracema (Brazil) peak.
Figure 51: A ‘value-over-volume’ mentality has meant non-OPEC Figure 52: Excluding the US (where observed decline rates are production growth has shifted towards (ultra)deepwater and obscured by continued ramp-ups in Shale) we expect non-OPEC unconventional projects, which exhibit the highest declines decline rates to increase to c8% by 2030, driven by a shift in production mix from post-peak fields
Source: J.P. Morgan US E&P Research. Source: J.P. Morgan estimates. The corollary of this data is that as the proportion of production from higher decline ultra-deepwater and unconventional fields grows (relative to conventional onshore and shallow water), global observed decline rates are also set to increase. We estimate that compared to a 2019E non-OPEC non-US decline rate of c7%, decline rates would reach c8% by 2030 (i.e. an additional 300kb/d annual loss to supply by 2030). Moreover, as our estimate excludes the effect of increasing field age, further increases could occur.
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James Thompson (44-20) 7134-5942 [email protected]
Super cycle II: “Missing Trillion” – underinvestment in black oil sees supply peak in 2022
The base of this analysis comes Is the oil supply crunch thesis ‘dead’? The ‘crying wolf’ in oil markets was a from our Global E&P capex (capex-led) supply shock that never was. Over the past five years the industry has model. Surveying over 100 of the materially cut investments and yet oil production has continued to grow. This can be top oil producers, it has attributed to: (i) lower than expected decline rates as oil companies invested more in historically served as a good indicator of capex trends optimizing producing asset performance, (ii) large inventory of funded greenfield projects sanctioned during the previous upcycle coming to fruition; (iii) capital We estimate that 2020 capex continued to flow into US shale despite oil prices falling as the industry pivoted to (cost incurred) in real terms short-cycle projects; (iv) deflationary oil field service pricing and a supply chain remains 40% below the 2014 peak. conducive to producing an increased proportion of brownfield volumes for fewer dollars invested. Recent developments in the oil market suggest that there is Our analysis of finding and development costs and current investment trends downside risk to our most recent suggests that the industry is underspending against what will be needed to balance forecast which called for low (1- 3%) growth YoY. the market beyond 2022. We forecast a shortfall of $210bn by 2025 and ~$1 trillion by 2030, even after we factor in material improvements in F&D costs. In the short Here we adapt to add in an term with oil prices under pressure we see little scope for E&P equities to increase estimate for OPEC investments spend, but suggest that this is only going to exacerbate a longer-term issue. and a further estimate to separate oil from gas. “Low growth” the capex mantra of 2014-2020, as the industry continues to distance from oil. However we see approaching supply challenges that even major technological advances (or high demand destruction) may not be able to solve. The question we have interrogated in the analysis is whether this apparent security of supply, despite low spending, can continue. Particularly given several industry trends which are currently in play, namely: Big Oil shifting away from oil; increasingly firm strategic decisions by oil majors to reduce investment in upstream and particularly in black oil, with companies such as BP clearly stating a plan to reduce production longer term. Figure 53: Medium-term capex plans outlined by the group maintain Figure 54: …it follows that IOCs have to spend dollars more wisely. A a flat outlook… number of commitments have been made on New Energies
n spending. Potentially crowding out upstream investment
b 300 60% $ 250 40% 200 20% 150 0% 100 -20% 50 -40% - -60% 2013 2014 2015 2016 2017 2018 2019E 2020E 2021E BP Chevron ENI Exxon Galp OMV Petrobras RD Shell Repsol Equinor Total Growth Change from peak Source: J.P. Morgan estimates, Company data. Source: J.P. Morgan estimates, Company data.
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James Thompson (44-20) 7134-5942 [email protected]
US LTO full cycle well economics suffer in a low price environment; Concern over full cycle shale economics, seen by the lack of cash generation in unconventionals focused E&Ps, has increasingly meant a withdrawal of capital from the space. Given shale has provided nearly all of recent marginal supply growth, a lack of access to capital combined with high decline rate geology poses a downside risk to supply.
Figure 55: Full-Cycle Oil Break-Evens - The bulk of US shale gravitates around $50-55/bbl breakeven (assuming 25% BTAX IRRs) vs spot WTI at c$50/bbl
Source: J.P. Morgan estimates, Company data. Project breakevens have fallen quickly over the past 5 years, yet still >50% of long-cycle projects are out of the money below $60/bbl Brent. It is not just shale projects that face challenges from low oil prices. We observe that despite the significant gains made by oil companies in recent years, it is still the case that well over 50% of potential FIDs over the next 5 years are out of the money at spot crude price ($52/bbl Brent). This equates to nearly 50 bn barrels which face risk of delay. Figure 56: Global Projects cost curve (15% IRR): ~50% projects breakeven on the current strip
Source: J.P. Morgan estimates, Company data. Enduring sanctions on large producers can tighten the market; while there is little sign that Venezuela can grow production materially in the near term, we also observe that some 4 mb/d of supply in OPEC is under varying degree of economic sanctions, which if maintained could keep 2-3 mb/d off the market over the medium term. Wood Mackenzie.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Figure 57: OPEC production facing sanctions from the US.
Source: J.P. Morgan estimates, Company data.
Service sector can’t reduce price further; oil service pricing overall is no longer deflating as evidenced by the IHS CERA Upstream Capital Cost Index (UCCI), with little scope for the oil services space to do more for less. At this stage in the cycle a number of OFS companies continue to face balance sheet challenges. If we adjust our forecasts for service pricing (using the IHS CERA UCCI) we estimate that capex is down 25% from 2014 peak. The right hand chart below illustrates quite neatly the increase in 2011-2014 investment being above trend and likely a factor behind how the industry has not seen the anticipated negative supply effect of capex cuts in recent years.
Figure 58: Actual Capex (JPM E&P Upstream Capex forecast) Figure 59: Cost Adjusted Upstream JPMe upstream capex (ex-MENA) 600,000 500,000 -25%
-40%, 400,000 ~$230bn
300,000
300,000 m $
200,000
100,000
0 0
NOCs IOCs Independents 2020E
Source: J.P. Morgan estimates, Company data. Source: J.P. Morgan estimates, Company data. Historical costs adjusted using the IHS CERA UCCI normalized to 1Q19.
Productivity / Efficiency gains are past point of greatest impact; US LTO has seen greatest tangible increase in productivity but other basins such as the North Sea have also seen material benefit from best practice and technology uptake. However, the high levels of production efficiency, and slowdown in shale productivity gains, suggest the best rate of change is behind us. Production mix suggests accelerating decline; as noted above the production mix shift suggests that decline rates are increasing, putting greater pressure on renewal of liquids production.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Figure 60: We expect non-OPEC non-US decline rates to increase as production shifts towards (higher decline) deepwater and shale basins
Source: J.P. Morgan estimates, Company data.
Our analysis shows current levels of investment are sufficient to meet demand growth to 2021, but will see supply peak in 2022. To offset a shortfall in 2025 needs ~$210bn cumulative spend hike (~$35bn p.a.) vs the prevailing trend, rising to ~$1.0 Trillion (>$80bn p.a.) by 2030. Putting this together and we find the best way to analyze and potentially forecast the current trend is through spending. We suggest that since the downturn the industry has been only very modestly increasing investment in upstream oil and gas. We calculate spending growth of ~5% CAGR between 2017-20, but this falls closer to 3% when considering only oil given the higher weighting to the US which is biased to liquids and is expected to decline another 10-15% this year.
Spending growth is more of a crawl, but efficiency gains are benefitting the industry. While in absolute terms we see the industry stuck in “low growth” mode, we also consider the effects of efficiency gains given a now relentless focus on capital efficacy in the industry. We see faster adoption of technology, greater transparency (data sharing) and increased standardization as the norm. We aim to represent this through a development efficiency factor. That is to forecast oil capex required we calculate the barrels needed to meet demand forecast and multiply this by an industry Finding & Development (F&D) cost. To this F&D we apply an efficiency factor, which as a base case we take at 3% per annum (i.e. if it costs $15/bbl to develop a barrel in 2020, it will then cost $14.55/bbl in 2021).
Taking these conditions (3% annualized oil capex growth and 3% annualized efficiency improvements) and running through the model, delivers a supply model which keeps pace with demand growth through 2022, but doesn’t grow beyond 102mb/d, suggesting this level may represent an inflection point for the industry. On our estimates this occurs in 2022, beyond which the relatively slow rate of spending growth means an ever- increasing supply gap, implying potential for a much tighter oil market.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Figure 61: JPM Global Oil capex analysis – trend (dark grey) capex at 3% CAGR + 3% efficiency gain, vs. capex required to meet JPMe demand forecast (yellow: +6.5% CAGR)
Source: J.P. Morgan estimates. Historical Oil Capex calculated from JPM E&P capex survey, with an additional historical estimate for MENA OPEC capex and then adjusted for relative industry share of upstream capex directed towards gas, as such the chart does not equal our Global E&P survey.
It follows that to meet our base-case demand forecast requires higher capex. Using the below inputs we show that cumulative spending will need to increase by ~$210bn by 2025 (~$35bn p.a.) and ~$1tn by 2030 (>$80bn p.a.). Given we don’t expect this level of increase by the industry in 2020 at the very least, this suggests that the industry is steadily falling behind the curve.
Our analysis calculates that investment in liquids production growth will need to rise to ~$650bn, from current level of ~$350bn (with oil capex calculated based off our Global E&P capex survey (total O&G spend ~$340bn across 104 companies), including MENA OPEC (est at ~$110bn), excluding an estimate for investment in Gas (~25%)) in order to reach this level, an ~85% increase. On average to deliver the production in line with our demand forecast requires $510bn p.a. vs. $425bn p.a. 2020-2030 on current trend (average 20% higher than the current projection) This includes us factoring a 3% efficiency gain in annualized F&D costs YoY, such that F&D costs industry wide are ~25% lower in 2030 than in 2020.
Figure 62: JPM Supply/Demand – At current levels of investment (grey line) supply shortfalls appear from 2022 –oil capex rises to $650bn in 2030. To meet the JPM base demand case (black line) can be met by increasing capex ~$1tn cumulatively to 2030 (gold line)
Source: J.P. Morgan estimates.
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James Thompson (44-20) 7134-5942 [email protected]
Table 2: JPM Scenario Summary - Missing Capex ~$210bn to 2025; ~$1.0tn to 2030 JPM Scenario Current (JPM Base) Required Field Decline - Increase vs 2018 baseline 0.0% 0.0% OPEC Growth - Initial Year 2022 2022 OPEC Production Growth - 2022-25 Avg (kb/d) 566 566 OPEC Production Growth - 2026-30 Avg (kb/d) 149 149 US Shale Scenario JPM Base JPM Base US Shale Growth - 2022-25 Avg (kb/d) 550 550 US Shale Growth - 2026-30 Avg (kb/d) 400 400 Annual capex productivity gain (%) 3.0% 3.0% 2021+ Annual Capex Growth (%) 3.0% 6.5% 2020-25 Cumulative Spend ($bn) 2,269 2,477 2020-30 Cumulative Spend ($bn) 4,492 5,391 Source: J.P. Morgan estimates, Company data.
Regionally, though the model doesn't model on a well-by-well basis, we see a greater need for IOCs and US E&Ps to raise spending more than OPEC which can maintain production and even raise it without material incremental growth capex, given current spare capacity and sanctions restrictions.
Which countries show the clearest signs of lower than expected production growth is difficult to predict, though Russia, Brazil, Saudi are unlikely to be the source, with US onshore, West Africa, North Sea more likely the source of shortfalls given historical underspend. That said, given planned production growth from shale / current long-cycle developments, then we see little near-term risk of supply shortfall from the current level of investment in the industry.
Figure 63: JPM Annual Supply Surplus (Deficit)
Source: J.P. Morgan estimates.
Near-term spending outlook – downside risk given near-term oil price. Making it harder to catch up. Over the 16 years of our Global E&P capex survey we note a close correlation between YoY change in the average oil price and the directional move in capex. Given the most recent downward move in the commodity it suggests that operators will shift spending to the lower end of budgets, meaning 2020 could be a year of capex declines, further aggravating the long-term supply picture.
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James Thompson (44-20) 7134-5942 [email protected]
Figure 64: E&P capex (ex. MENA) and Brent oil price (% change YoY) 60.0 45.0 30.0 15.0 0.0 -15.0 -30.0 -45.0 -60.0 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 E E 0 0 0 0 0 0 1 1 1 1 1 1 1 1 1 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 0 0 2 2 Oil price change (%) Bull case 2020 (%) Bear case 2020 (%) Base case 2020 (%)
Source: J.P. Morgan estimates, Bloomberg. Note 2019 oil price is an average of the Brent forward curve and YTD.
Rise in early-cycle activity suggests oil companies with longer-cycle business models starting to address long-term upstream portfolio concerns. Our Global E&P capex survey illustrated that in 2019 there was a defined tick up in early-cycle activities. While these may slow again in early 2020 (exploration is often the first $ of capex to be cut), the evidence of last year suggests that operators have (i) completed construction of the majority of prior-cycle developments, and (ii) are refocusing on longer-term portfolio renewal. We continue to see this as a leading indicator of potential spend increases.
Figure 65: Global exploration spending as a % of E&P spending (ex-MENA) – upward trend has the potential to continue 700 24 s t 600 e g d
20 u B
500 P & E
16 l a t o t
400 f n o
b $ 12 %
a 300 s a
d
8 n e
200 p S
n o i 4 t 100 a r o l p x 0 0 E 2003 2005 2007 2009 2011 2013 2015 2017 2019E
Total E&P spending ($bn) Exploration Spend as a % of total E&P Budgets
Source: J.P. Morgan estimates, Company data.
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James Thompson
(44-20) 7134-5942 s [email protected] e t
Tackling the Supply / Demand Bear a
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James Thompson (44-20) 7134-5942 [email protected] 1. US Shale: Key driver of global crude growth but the ‘magic dust’ is running out, while lower oil = lower volumes We incorporate our Shale team’s retooled production model (here) into our global supply forecasts, which builds off the production models within their individual company forecasts (aggregate supply growth c770kb/d in 2020, 270kb/d in 2021, and a 2022-30 avg. c400kb/d – driven by the Permian). COVID-19 update: At prevailing oil prices our US shale team have published (click here) a scenario which implies 100-170kb/d of downside to 2020-21 production estimates, and c1mb/d of downside by 2025 - This supports our view shale growth is under pressure given capital restrictions. While the Permian offers a healthy runway to 2030, a confluence of Figure 66: JPM US Crude Production Model – Unencumbered by capital constraints, the shareholder pressure on TSR and productivity slowdown = lower quantum of Permian remains the key driver of Shale growth to 2025, offsetting net declines on other fields new barrels vs previous decade Over the past 4 years, the oil market has been characterized by excess supply primarily driven by U.S. shale production growth as illustrated in Figure 66. Our US team’s analysis of shale inventory suggests that the US has c19 years of inventory at the current drilling space and that Permian Basin alone will likely emerge as the primary driver of future volume growth in US shales. Moreover, the confluence of 1) an increasing mix of children wells, 2) constrained capex led by greater shareholder pressures on FCF and TSR and 3) a slow-down in productivity gains (albeit with still plenty of running room for efficiency gains) means that the net quantum of new barrels coming online over the next five years (JPMe 2020-24 aggregate growth 2.6mb/d) is likely to be less than the during the previous period (JPMe 2015-19 aggregate growth 3.1mb/d).
Source: J.P. Morgan estimates. Table 3: JPM US Lower 48 supply estimates: The Permian basin is expected to grow at 2020-25 CAGR of 9%, driving total onshore US crude production to c15mb/d by 2030. 2018E 2019E 2020E 2021E 2022E 2023E 2024E 2025E 2026E 2027E 2028E 2029E 2030E Permian - TX 2,820 3,508 3,911 4,293 4,753 5,102 5,444 5,816 6,106 6,396 6,687 6,977 7,268 Permian - NM 659 884 1,231 1,429 1,655 1,830 2,007 2,195 2,305 2,414 2,524 2,634 2,743 Permian Total 3,479 4,392 5,141 5,721 6,408 6,932 7,451 8,011 8,411 8,811 9,211 9,611 10,011 Annual Growth (%) 26% 17% 11% 12% 8% 7% 8% 5% 5% 5% 4% 4% Eagle Ford 1,417 1,457 1,462 1,439 1,452 1,460 1,445 1,433 1,433 1,433 1,433 1,433 1,433 Williston Basin 1,334 1,487 1,540 1,465 1,411 1,392 1,397 1,406 1,406 1,406 1,406 1,406 1,406 DJ Basin 492 559 571 519 487 486 497 512 512 512 512 512 512 MidCon 605 641 611 546 492 475 474 481 481 481 481 481 481 Other Onshore 1,383 1,431 1,417 1,323 1,293 1,315 1,336 1,370 1,370 1,370 1,370 1,370 1,370 Others Total 5,229 5,574 5,599 5,292 5,135 5,127 5,148 5,201 5,201 5,201 5,201 5,201 5,201 Annual Growth (%) 7% 0% -5% -3% 0% 0% 1% 0% 0% 0% 0% 0% US L48 Crude Production 8,708 9,967 10,741 11,014 11,543 12,059 12,599 13,212 13,612 14,012 14,412 14,812 15,212 Source: J.P. Morgan estimates.
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James Thompson (44-20) 7134-5942 [email protected]
US Shale (cont.) – Growth runway remains healthy but shareholder pressure on capital framework + productivity slowdown means 2020-25 growth quantum less than in previous decade Looking into 2020+ we believe that US shale growth will largely be shaped by the industry’s ability to reduce cycle times and mitigate declining productivity as basins (the Delaware in particular) become more developed. Moreover, with capital markets more constricted to the E&Ps and energy investors prioritizing free cash flow generation, some operators are now sacrificing full section NPVs to generate higher near-term economics (wider well spacing, lower proppant loading).
Productivity gains seem to be peaking, but there is still running room for Figure 67: Overall our US Shale team expect a slowdown in capex to result in the US rig count efficiency gains remaining at current low-levels through 2020. They see the US at an average of 805 onshore rigs next year vs the current onshore rig levels of 777, but a 15% decrease y/y. Our US E&P team demonstrate that shale productivity seems to be plateauing in most major oil basins on a per foot basis. While the US rig count has been steadily declining over the past year, we expect the impact on oil production to be partially mitigated by cycle time improvements. Moving forward we see the biggest efficiency gains in growing basins such as the Permian where operators are shifting to larger pads and longer laterals as well as younger basins such as the PRB where operators like EOG will begin to shift to full-scale development in 2020+. More mature basins such as the Williston and the Eagle Ford, in our view, have less running room for efficiency gains but should still see moderate improvement moving forward. In aggregate, the team assume 0.25-1% m/m cycle time improvements moving forward for most basins.
Source: J.P. Morgan estimates. Figure 68: In 2019, U.S. shale productivity was largely unchanged y/y, though the Williston, Figure 69: As a result, we expect a 2021+ slowdown in US shale growth to well below 2018-19 Midland Basin, DJ Basin, and STACK did see slight improvements. levels (JPMe crude supply growth equivalent to c45% of 2021-25 liquids demand growth).
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected] US Shale (cont.) – A tighter capital frame on shale economics means greater asymmetry to oil prices; downside risk to volume growth at spot WTI as a larger proportion of Permian growth diminishes With productivity and technology-led efficiency gains slowing, breakeven economics will be key in assessing the second order of volume growth linked to higher oil prices. While breakevens have continued to drift lower as US shale remains competitive at $50/bbl, we believe they have normalized (ranging between $45/bbl in the Midland Basin to $55/bbl in the Delaware). This suggests that spot WTI <$50/bbl should have a negative impact on future volume growth as returns diminish. Under higher oil prices we expect marginal FCF to be prioritized to the shareholder over incremental capex/volumes.
Despite sufficient reserves/inventory levels to sustain production into the next Figure 70: JPM Inventory Deep Dive – plenty of oil left but predominantly in one basin: the decade, we see downside risk to growth at spot WTI given full-cycle breakevens Permian Our Shale team have taken a deep dive into the estimated remaining inventory for each major oil basin and for each underlying county, and conclude that the US has about ~19 years of inventory remaining at the current drilling pace.
Ultimately, their analysis concludes that the Permian Basin, which has the most surface acreage and can handle the highest number of wells/DSU has the largest outstanding inventory.
However, while inventory levels appear sufficient to fuel a growth runway to 2030, when comparing full-cycle breakevens against spot WTI (at <$50/bbl), the majority of basins screen as uncommercial.
Source: Enverus Figure 71: Full-Cycle Oil Break-Evens - The bulk of US shale gravitates around $50-55/bbl Figure 72: Innovations in horizontal drilling and hydraulic fracturing have driven a 116% breakeven (assuming 25% BTAX IRRs) vs spot WTI at c$50/bbl increase in reserves since 2008 to an 11-year proven reserves life in 2018.
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates, BP statistical review of world energy 2019.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
2: OPEC capacity ‘overhang’: Saudi on ‘mute’ as inventory reduction > market share
As a structural supply deficit emerges and with that a sustained inventory drawdown, we would expect the backend of the curve to move higher (as outlined in our executive summary). This in turn should instigate a production response by OPEC which we model from 2021, calibrated against a continued drawdown in global inventories. We model OPEC crude production growth of 500kb/d in 2021, c1mb/d in 2022/23, and averaging 300kb/d pa to 2030. As a result, we expect OPEC spare capacity, excluding members under sanctions, to fall to 2.1mb/d by 2030, broadly in line with the group’s historical level of circa 2mb/d.
While OPEC budget fiscal breakevens remain elevated in 2020 ($45-90/bbl) Figure 73: While OPEC breakevens above the forward curve will be a key constraint to we expect the group to maintain its policy of prioritizing revenue over market production growth, we look to 2021/22 as a ‘tipping point' for relaxed production quotas - with share, seeking to put a ‘floor’ on Brent of c$60/bbl. growth led by Saudi, Iraq, the UAE and Kuwait. Saudi’s oil policy agenda has a natural bias towards ‘value’ over ‘volume’ as we triangulate the Kingdom’s fiscal budget breakeven with Saudi Aramco’s cash breakeven (post dividend and capex) of $60/bbl, on average across 2019-21. With this in mind, we believe that in our base case scenario of an oil market deficit in 2021, the response by OPEC+ will be muted as their collective agenda is to drive both US and OECD inventories back towards historical averages over and above mitigating a short-term move higher on the front-end of the curve. As a result, we think the back-end of the curve would have to move materially above $70/bbl to warrant a renewed production framework of higher quotas.
Source: J.P. Morgan estimates. Figure 74: Updated 2020 fiscal breakevens for selected OPEC(+) members – 2020E weighted Figure 75: Change in 2020 fiscal breakevens by region – Saudi a key driver of the increase as average $64/bbl vs spot Brent at c$55/bbl. the KSA accelerates economic growth in the absence of significant FDI, and increasing debt.
Source: J.P. Morgan estimates. IMF Data. Source: J.P. Morgan estimates, IMF Data.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
OPEC (cont.) – As fiscal breakevens are expected to remain elevated in 2020, we expect OPEC to maintain its policy of prioritizing revenue over market share, seeking to put a ‘floor’ on Brent of c$60/bbl. OPEC production growth is conditional on global inventory drawdown and while fiscal breakevens remain elevated. This view is reinforced by our recent Global Oil & Gas CEO conference in November (here), where experts on Saudi oil policy pointed to c$65/bbl as the kingdom’s fiscal ‘comfort’ level in the absence of significant FDI.
Read-across from the Aramco IPO: Minority shareholder prioritization Figure 76: While Aramco is able to boast a leading pre-dividend breakeven of <$10/bbl, combined with the KSA’s diversification push means Saudi likely to defend c$60/bbl is needed to fund full payout to the majority government shareholder… $60/bbl through its OPEC+ oil policy We highlight an under-appreciated read across from the Aramco IPO (see note here): while the company is able to boast a best-in-class pre-dividend breakeven of <$10/bbl, the commitment to a $75bn base dividend in 2020 and hence a 2020-22 average post capex and dividend breakeven of $58/bbl has important implications for the government majority shareholder (below a gross payment of $75bn, distributions to minority shareholders are prioritized until 2024).
I.e. the kingdom needs c$60/bbl Brent in order to receive a payout proportionate to its ownership stake.
Source: J.P. Morgan estimates. Company Data.
Figure 77: While Saudi is on a path to reducing its fiscal budget breakeven, oil revenues remain a key source of funds for this diversification effort Understanding the deviation of OPEC+ fiscal breakevens also goes some way to explaining the apparent friction between Russian and Saudi oil policies in 2019: Russia’s fiscal breakeven is c$30/bbl lower than Saudi’s, implying a greater appetite to grow production. However, as we look to the medium term, a positive corollary of the KSA’s plan to increase non-oil revenues (and hence reduce fiscal breakevens) is that we may see increased cohesion between OPEC(+) members’ oil policies.
Source: MOF, NCB, Our JPM 2019-2023 fiscal estimates are scenarios based off government public figures. JPM Production estimates: 2019E: 9.8mb/d, 2020E: 9.5mb/d, 2021E 9.7mb/d, 2022E 10.2mb/d, 2023E 10.9mb/d
40 This document is being provided for the exclusive use of [email protected].
{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
OPEC (cont.) – 2021/22 the ‘Tipping Point’: Saudi fiscal breakeven ~$70/bbl and emerging oil market deficit = OPEC growth to resume In the event of a sharp move higher in oil prices, we don’t believe OPEC+ will respond through increased production quotas unless there was an equally proportionate inventory drawdown that preceded it. While Saudi breakevens above the forward curve will be a key constraint to OPEC production growth, we look to 2021/22 as a ‘tipping point' for relaxed production quotas. While we acknowledge that if sanctions on Iran and Venezuela were removed we could see a surge in production, we believe that OPEC+ (led by Saudi) will seek to absorb the additional barrels though respective quota cuts given their renewed focus to reduce global inventories. Equally, and in the same vain, in a global economic recessionary environment where demand is weaker (expanded on page 16) we would expect OPEC to respond through deeper cuts to help mitigate an inventory surplus.
We model OPEC crude production growth of 500kb/d in 2021, c1mb/d in Figure 78: We model OPEC production growth from 2021, with Saudi, Iraq, the UAE and Kuwait 2022/23, and averaging 300kb/d pa to 2030. key sources of growth
From 2021, we expect production growth from Saudi, Iraq, the UAE and Kuwait to be partially offset by capacity declines (JPMe 3% capacity decline p.a.) in other OPEC countries. As a result, we expect OPEC spare capacity, excluding members under sanctions) to fall to 2.1mb/d by 2030, compared to a (JPMe) long-term strategic minimum of c2mb/d as identified in our CGG Capacity Series analysis.
Source: J.P. Morgan estimates. Figure 79: Excluding countries under sanctions, we model OPEC spare capacity falling to 2.1mb/d by 2030 from c4mb/d in 2020
Source: J.P. Morgan estimates.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
3: ‘Stranded’ assets: Global oil reserves a ‘mirage’ of oil as carbon intensity and economic commerciality = 50% haircut to global liquids reserves of 1.7tn barrels
BP’s most recent Statistical Review of World Energy estimated 2018 global proven oil reserves at c1.7 trillion barrels, enough to meet over 50 years of demand at 2018 levels. This level is little changed since 2010 and includes for example the inclusion of Venezuela’s heavy crude deposits. We think a deepened understanding of the global oil reserves base is key to understanding the potential scale of globally ‘stranded’ assets, or whether, in fact, a need for further discoveries remains.
Figure 80: Total proved liquids reserves (including condensate and NGLs) totaled 1,730 billion Figure 81: Of the 1.1tn bbls of reserves added since 1980, 78% of total additions have come barrels in 2018, according to BP’s Statistical Review of World Energy, up 0.1% y/y from OPEC, which has added an avg 21bn bbls pa.
Source: BP statistical review of world energy 2019. Source: BP statistical review of world energy 2019.
Figure 82: Aggregate global reserves are sufficient to sustain c50years of production at 2018 Figure 83: The global proven liquids reserve replacement ratio has been above 100% for 35 of levels (95mb/d), however the global R/P ratio has fallen by 5 years since 2011 38 years since 1990.
Source: J.P. Morgan estimates, BP statistical review of world energy 2019. Source: BP statistical review of world energy 2019.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Reserves (cont.) – OPEC members have added over 800bn bbls of reserves since 1980 (i.e. a 190% increase), with Venezuela and Saudi Arabia accounting for c50% of total OPEC reserves As of 2018, 71.8% of the world's proven oil reserves were located in OPEC Member Countries (inclusive of Ecuador and Qatar), equivalent to 1.2 trillion boe, or 87 years of supply at a 2018 OPEC production level of c39mb/d. Since OPEC started to set production quotas (partly) on the basis of reserves levels in the 1980s, many of its members have reported significant increases in their official reserves – for example, between 1983 and 1984 Kuwait’s reserves increased by c40%. Net reserves have increased by over 800bn boe since 1980, and Venezuela and Saudi Arabia hold approximately half of total OPEC reserves.
Figure 84: Current liquids reserves are 1.2tn boe, and OPEC has more than replaced its proven Figure 85: ...though the picture changes dramatically if Venezuela is removed, as the country reserves every year 1980-2018… accounts for c72% of reserves since 2006
Source: BP statistical review of world energy 2019. Source: J.P. Morgan estimates, BP statistical review of world energy 2019.
Figure 86: Proven OPEC reserves split by country. Venezuela and Saudi Arabia hold c50% of Figure 87: OPEC R/P ratio - Bookings increased materially in the 1980s, around the same time total OPEC reserves… as OPEC began setting production quotas linked to reserves levels.
Source: BP statistical review of world energy 2019. Source: J.P. Morgan estimates, BP statistical review of world energy 2019.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Reserves (cont.) – Non-OPEC has added c230bn bbls of reserves since 1980 (i.e. an 89% increase), with Canada, Russia, the US and Kazakhstan the primary source of additions While OPEC has by far outpaced the rest of the world in terms of reserves additions since 1980, there have also been notable additions in the rest of the world. As of 2018, proven non-OPEC liquids reserves were 488bn boe, primarily located in Canada, Russia, the United States and Kazakhstan.
Figure 88: Non-OPEC reserves totaled 488bn boe in 2018, having risen by 86% since 1990; Figure 89: Non-OPEC reserves replacement has averaged c140% 1980-2018, c96% of additions primarily via additions in Canada/Russia occurred in 1991, 1999, and 2007
Source: J.P. Morgan estimates, BP statistical review of world energy 2019. Source: J.P. Morgan estimates, BP statistical review of world energy 2019.
Figure 90: Proven liquids reserves split by country – Canada accounts for over 1/3rd of non- Figure 91: Non-OPEC reserves are sufficient to sustain 24 years of production at 2018 levels OPEC reserves (c55mb/d).
Source: J.P. Morgan estimates, BP statistical review of world energy 2019. Source: J.P. Morgan estimates, BP statistical review of world energy 2019.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Reserves (cont.) – Commerciality in a low(er) oil price world = c50% fall in 1P reserves from the 10 largest global sources Although global proven reserves reached new highs in 2018, we overlay Wood Mackenzie estimates of commercial reserves (that is the reserves from fields on production, under development or likely to be developed) to show that c730bn boe from the 10 largest countries by liquids reserves (which contribute c1.5tn to total global reserves of 1.7tn) are classified as ‘un-commercial’. Simply put, the 1.7tn headline masks large disparities in production costs for the economic recovery of the oil, and a divergence in reserve accounting standards.
Venezuela and Canada suffer the largest reductions, having both booked Figure 92: Estimated proven liquids reserves from the 10 largest global sources fall by c730bn significant quantities of bitumen. bbls when applying a Wood-Mackenzie commercial screen (minimum 15% IRR at c$60/bbl Brent) According to Rystad, running SPE proved reserves rules over Venezuela’s mostly hard-to-extract bituminous oil shrinks the country’s top-ranking reserves to just 6 billion barrels, only c2% of the claimed total 303-billion-barrel total. Canada’s massive but costly oil sands deposits suffer a similar fate under the tougher rules, shrinking to 24 billion barrels. Moreover, as well as being high cost these barrels are also high carbon intensity, requiring significant energy to extract (e.g. oil sands bitumen is produced from Alberta using either mining or thermal techniques),
Source: J.P. Morgan estimates, BP statistical review of world energy 2019, Wood Mackenzie
Figure 93: Venezuela and Canada suffer the largest reductions, having both booked significant quantities of bitumen A reduction in global reserves of c730 billion barrels is equivalent to approximately 21 years of global production at 2018 levels, and would reduce the global 2018 R/P ratio to 29 years (implying a 1P liquids reserves base of c1tn barrels). Comparing this revised number to even estimates in BP’s most aggressive transition scenario (which models global oil demand falling to c80mb/d by 2040), 66% of reserves would be consumed by 2040, rising to c75% under their base-case scenario.
Source: J.P. Morgan estimates, BP statistical review of world energy 2019, Wood Mackenzie
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Reserves (cont.) – Commerciality in a low(er) carbon world -> CO2 intensity an increasingly important consideration in project sanctioning Rightly or wrongly, with consensus for ‘peak’ oil demand somewhere within 2030-2040, and a ‘lower for longer’ outlook for oil now widely accepted, the Majors are re- engineering their portfolios towards barrels that sit at the low end of the cost curve. However, for an ever increasing proportion of investors, holding the lowest-cost barrels is simply not enough, and the Majors are facing calls to outline practical steps to show progress in reducing emissions and CO2 intensity.
Figure 94: 2016-2025 Emissions and intensity by resource theme – We expect companies to Figure 95: Layering a “High Carbon” cut off to global reserves could exclude a further 15% of reposition their portfolios towards low carbon, low breakeven projects reserves. Chart shows an analysis of medium term oil-biased field developments
Source: Wood Mackenzie Source: J.P. Morgan estimates, Wood Mackenzie. Note we screen for low breakeven as <$60/bbl (at 15% discount rate), and low
carbon as a CO2 intensity <$30kg/boe Figure 96: Combined with the corporate screen as discussed above, this results in a global Figure 97: A reduction in global reserves of c900 billion barrels is equivalent to approximately proven, low-breakeven and low-carbon reserves level c150bn boe below the level required in 25 years of global production at 2018 levels, and would reduce the global 2018 R/P ratio to 25 the IEA’s SDS, and over 1tn bbls below their “current policies" scenario years, below that seen in 1980
Source: J.P. Morgan estimates, BP statistical review of world energy 2019, Wood Mackenzie Source: J.P. Morgan estimates, BP statistical review of world energy 2019, Wood Mackenzie
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Reserves (cont.) – Corporate overlay: IOCs running to stand still as, despite global reserves growth, corporate levels remain broadly unchanged at c300bn boe; reserve life continues to fall to multi-year lows on reduced exploration finds While global reserves have increased c30% since 2000, we leverage the analysis across our global research franchise to show that corporate reserves remain broadly unchanged vs 20 years ago at c300bn boe – equivalent to an 18 year reserves life at 2018 production levels.
Figure 98: Extensions/discoveries largest source of growth Figure 99: Global balance of revisions vs discoveries –Discoveries represent the majority of reserves additions since 2000, with negative revisions during the 2014 oil price downturn
Source: J.P. Morgan estimates, Company Data Source: J.P. Morgan estimates, Company Data
Figure 100: Global reserves life continues to trend lower as exploration capex is reduced and Figure 101: Change in reserves life by region – the Russian oils continue to dominate the discoveries fall corporate reserves landscape, led by Rosneft and Gazprom Neft.
Source: J.P. Morgan estimates, Company Data Source: J.P. Morgan estimates, Company Data
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
4. ‘Peak’ oil demand / climate change: Reality check needed; delivering cheap energy to developing economies means black oil is not ‘dead’ in Energy Transition While peak demand in the late 2020s / early 2030s appears to have become the new ‘consensus’; we point to growth in the industrial and transport sectors (including aviation, shipping and road), predominantly in Asia, as a key driver of increasing oil demand through to 2040. Despite the current backdrop of (nCoV-led) uncertainty for 2020 global economic growth and oil demand as discussed on page 6, from 2021 onwards we assume a global recovery and expect 2021 liquids demand growth of c1.3mbd.
Figure 102: While we expect a 2020 nCoV demand shock, from 2021+ our base case assumes Figure 103: Our JPM base case sits mid-range between potential scenarios, and assumes a liquids demand growth averaging c1mb/d to 2030, with peak demand growth in 2021. 2.6% GDP CAGR to 2030, as well as an annual improvement in energy intensities of 1.9%.
Source: J.P. Morgan Commodities Research. Source: J.P. Morgan Commodities Research. Figure 104: 2020-25 liquids demand growth by sector - Industrial and transport growth Figure 105: 2020-25 liquids demand growth by sector – As a result, we expect products (including aviation, shipping and road) set to an increased call on crude over the next decade demand growth to be entered around LPG, Gasoline, Diesel and Kerosene
Source: J.P. Morgan Commodities Research. Source: J.P. Morgan Commodities Research.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Demand (cont.) – Emerging Markets: developing economies’ growth ‘engine' still highly dependent on oil Modelling large oil consumers such as the US, China and India by evaluating structural changes in their economies and their energy intensities, we expect US oil demand growth to average just 10kbd y/y over the next 5 years, with growth actually flat lining between 2022 and 2025 before contracting from 2026 onwards. However, while oil demand is expected to shrink in developed countries, we expect Emerging Markets to drive global demand growth through to 2030.
EM countries’ crude growth should not be underestimated… Figure 106: We expect developing economies including India and China to be the key drivers of oil demand growth to 2025 China: 2021-25 average demand growth 285kbd. We expect the transition to a service-based economy to continue over the next decade, reducing consumption growth from energy-intensive infrastructure projects. Coupled with efficiency gains, electric vehicle (EV) penetration and displacement from renewables we think China's oil intensity will decline by 2.2% p.a. As a result, oil demand growth is expected to average 285kbd y/y through to 2025, and to slow by the end of the decade. India: 2021-25 average demand growth 260kb/d. We think oil demand growth will be driven largely by transport fuel demand, namely gasoline and jet as infrastructure projects enhance connectivity within the country. LPG demand is likely to continue to displace kerosene in household use, supported by the government’s social welfare programme, but this transition is expected Source: J.P. Morgan Commodities Research. to have completed before 2025. Figure 107: Global oil demand growth regional breakdown (kb/d). India is expected to become RoW: JPMe annual demand growth 420kb/d to 2025. Consumption growth the largest point source of demand growth from 2020, averaging 260kb/d 2021-25. can be characterized by stronger EM Asia, Africa and Middle East growth tempered by a notable decline in oil demand within OECD Europe. Environmental regulations coupled with incentives for EVs and renewables is expected to curtail oil consumption particular for transport fuels.
Source: J.P. Morgan Commodities Research.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Demand (cont.) – Risk Scenarios: Demand growth to fall to as low as c700kb/d pa to 2030 in a ‘global slowdown’ scenario; meeting SDS implies demand to fall to c95mb/d by 2025. Given the uncertainty over the path of the global economy for the next decade and the changes in regulations related to fossil fuels, we acknowledge there are risks around our central forecast for oil demand for the period in question. To address such concerns we have projected several scenarios for oil demand growth.
JPM demand growth scenarios: Figure 108: JPM global liquids demand scenarios range from 2021-30 avg growth of 600kb/d in a ‘Trade War’ scenario up to 1.4mb/d pa in a “low efficiency” scenario We have constructed several scenarios to assess global liquids demand growth under varying macro inputs. These include:
High Efficiency: Global energy intensities improving at 2.3% pa (vs JPM base 1.9%). Low Efficiency: Global energy intensities improving at a weaker trajectory (1.4%) similar to the previous 20 years. Global Slowdown: We model the world economy decelerating to an annual growth rate of 1.9% in 2021 versus a projected 2.5% rate for 2020. The global economy is expected to rebound back to 2.6% on annual basis in 2022 under this scenario. Source: J.P. Morgan Commodities Research. Trade War: An escalation in the trade war sees a sharp contraction in the global economic growth rate to 1.7% in 2021 with a more a gradual and modest recovery through to 2025. Annual average growth rates do not exceed 2.25% within this particular scenario. Climate change. We show that under the IEA’s Sustainable Development Scenario (SDS), which assumes a 3.6% annual improvement in energy intensity, liquids demand is forecast to fall to c95mb/d by 2025. In the low efficiency scenario, we project oil demand to grow by as much as 1.4 mbd annually by 2025, reaching 106.6 mbd. In our low case event (trade war escalation), we think oil demand could slow to average just 600 kbd annually for the next 5 years, to 102.7 mbd. This would be less than 3 mbd of demand growth compared to 2020 forecasts.
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
JPM Scenario Summary y r a m m u S
o i r a n e c S
M P J
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
Scenario 1: Sanctions Removal on Iran and Venezuela from 2022 In a scenario where sanctions are removed on Iran and Venezuela (JPMe an additional 350kb/d of production growth 2022+), we see the aggregate 2020-2030 “Call on Capex” falling to $2.4tn by 2025, c$150bn higher vs prevailing spend.
Table 4: JPM Scenario Summary: We assume additional crude production growth of 350kb/d Figure 109: As a result, the aggregate oil capex growth rate required to balance supply/demand pa from 2022 onwards in a scenario where sanctions are removed on Iran and Venezuela. would fall to c5.5% pa (vs the current trend at c3%).
JPM Scenario Current (JPM Base) Scenario Field Decline - Increase vs 2018 baseline 0.0% 0.0% OPEC Growth - Initial Year 2022 2022 OPEC Production Growth - 2022-25 Avg (kb/d) 566 916 OPEC Production Growth - 2026-30 Avg (kb/d) 149 499 US Shale Scenario JPM Base JPM Base US Shale Growth - 2022-25 Avg (kb/d) 550 550 US Shale Growth - 2026-30 Avg (kb/d) 400 400 Annual capex productivity gain (%) 3.0% 3.0% 2021+ Annual Capex Growth (%) 3.0% 5.5% 2020-25 Cumulative Spend ($bn) 2,269 2,416 2020-30 Cumulative Spend ($bn) 4,492 5,115 Source: J.P. Morgan estimates. Source: J.P. Morgan estimates.
Figure 110: Under this scenario, we expect the market to enter a supply/demand deficit by Figure 111: This results in a “Call on capex” c$150bn higher vs current estimates by 2025 (and 2024, with the cumulative 2019-23 inventory gain removed by 2030 c$600bn by 2030)
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates.
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James Thompson (44-20) 7134-5942 [email protected]
Scenario 2: Oil demand falls in-line with the IEA’s Stated Policies Scenario (STEPS) According to the IEA, the world is not on track to meet a “Sustainable Development Scenario (SDS)” fully aligned with the Paris Agreement by holding the rise in global temperatures to well below 2°C. Instead, the IEA provide a Stated Policies Scenario which reflects the impact of existing policy frameworks and today’s announced policy intentions. The projections in the STEPS suggest that, in the absence of more concerted policy action, demand for oil and (especially) gas would continue to grow to 2040. Under this scenario, we model annual capex growth of c5% to 2030 in order to balance supply/demand, implying a 2020-25 “Call on Capex” c$120bn higher vs current trends. Table 5: JPM Scenario Summary: Under the IEA’s STEPS scenario, we model annual liquids Figure 112: As a result, the aggregate oil capex growth rate required to balance supply/demand demand growth averaging 584kb/d 2021-2030 (vs JPM Base Case 1,082kb/d) would fall to c5% pa (vs the current trend at c3%).
JPM Scenario Current (JPM Base) Scenario Field Decline - Increase vs 2018 baseline 0.0% 0.0% OPEC Growth - Initial Year 2022 2022 OPEC Production Growth - 2022-25 Avg (kb/d) 566 566 OPEC Production Growth - 2026-30 Avg (kb/d) 149 149 US Shale Scenario JPM Base JPM Base US Shale Growth - 2022-25 Avg (kb/d) 550 550 US Shale Growth - 2026-30 Avg (kb/d) 400 400 Annual capex productivity gain (%) 3.0% 3.0% 2021+ Annual Capex Growth (%) 3.0% 5.0% 2020-25 Cumulative Spend ($bn) 2,269 2,386 2020-30 Cumulative Spend ($bn) 4,492 4,983 Source: J.P. Morgan estimates. Source: J.P. Morgan estimates. Figure 113: Under this scenario, the market enters a supply/demand deficit by 2024, before Figure 114: This results in a “Call on capex” c$120bn higher vs current estimates by 2025 (and remaining broadly balanced through to 2030. $500bn by 2030)
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates.
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James Thompson (44-20) 7134-5942 [email protected]
Scenario 3: “Value over Volume” – OPEC production growth of c2mb/d pa needed if IOC & Shale capex remains flat Post the oil price collapse of mid-2014, the operational and strategic focus of most global IOCs has shifted to capital efficiency and maximizing the value of existing production and new barrels brought onstream – i.e. value over volume. However, with a declining outlook for non-OPEC non-US startups as we move into 2021 and beyond as highlighted in our 2020 Macro Outlook, we show that under a scenario where global capex remains flat annual OPEC growth of c2mb/d is needed (modelled at 1.5mb/d growth to 2025, then 2.3mb/d growth 2026-2030) to balance global supply/demand, even if capex productivity gains increase to 5% pa. Table 6: JPM Scenario Summary: Under a scenario where global oil capex remains flat at Figure 115: Under a flat capex scenario, global oil production is expected to fall post 2021 by c$350bn pa, we show the “Call on OPEC” would rise by an average 2mb/d pa to 2030 an average 1mb/d vs demand growth of c1mb/d (i.e. a call on OPEC of 2mb/d)…
JPM Scenario Current (JPM Base) Scenario Field Decline - Increase vs 2018 baseline 0.0% 0.0% OPEC Growth - Initial Year 2022 2022 OPEC Production Growth - 2022-25 Avg (kb/d) 566 1,500 OPEC Production Growth - 2026-30 Avg (kb/d) 149 2,300 US Shale Scenario JPM Base JPM Base US Shale Growth - 2022-25 Avg (kb/d) 550 550 US Shale Growth - 2026-30 Avg (kb/d) 400 400 Annual capex productivity gain (%) 3.0% 5.0% 2021+ Annual Capex Growth (%) 3.0% 0.0% 2020-25 Cumulative Spend ($bn) 2,269 2,104 2020-30 Cumulative Spend ($bn) 4,492 3,858
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates. Figure 116: …Excluding OPEC growth, this would drive a global S/D deficit up to c20mb/d by Figure 117: Annual capex of c$350bn pa is equivalent to a 2020-2030 cumulative spend of 2030, despite an assumed 5% annual capex productivity gain c$4tn,c$600m below prevailing spend of c$4.5tn (assuming a 3% 2020-30 CAGR)
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates.
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James Thompson (44-20) 7134-5942 [email protected]
Scenario 4: Decade-long underspend leads to higher declines – A 1% increase in non-OPEC non-US declines = c$300bn additional capex needed by 2030 As demonstrated on page 24, we see a strong relationship between (lower) corporate spending and (higher) decline rates. In this scenario, we show that should prevailing underspend of c$1tn to 2030 lead to decline rates increasing by c1% vs a 2018 baseline, a further capex increase of c$300bn would be required (i.e net capex growth of c$1.2tn vs prevailing spend). Table 7: JPM Scenario Summary: A 1% increase in decline rates vs our 2018 baseline lead to Figure 118: As a result, the aggregate oil capex growth rate required to balance supply/demand an additional 4mb/d production deficit by 2030 would increase to c7.5% pa (vs required growth of c6.5% at flat decline rates). Required Capex - JPM Required Capex - 1% JPM Scenario Base Decline Field Decline - Increase vs 2018 baseline 1.0% 1.0% OPEC Growth - Initial Year 2022 2022 OPEC Production Growth - 2022-25 Avg (kb/d) 566 566 OPEC Production Growth - 2026-30 Avg (kb/d) 149 149 US Shale Scenario Tapered Growth 2022+ Tapered Growth 2022+ US Shale Growth - 2022-25 Avg (kb/d) 450 450 US Shale Growth - 2026-30 Avg (kb/d) 63 63 Annual capex productivity gain (%) 3.0% 3.0% 2021+ Annual Capex Growth (%) 6.5% 7.5% 2020-25 Cumulative Spend ($bn) 2,477 2,541 2020-30 Cumulative Spend ($bn) 5,391 5,685 Source: J.P. Morgan estimates. Source: J.P. Morgan estimates. Figure 119: Compared to the required capex at flat decline rates, this drives an average Figure 120: As a result, the “call on capex” to meet demand would rise a further c$300bn to additional production deficit of c500kb/d pa to 2030 2030 – i.e. c$1.2tn higher vs prevailing spend
Source: J.P. Morgan estimates. Source: J.P. Morgan estimates.
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James Thompson (44-20) 7134-5942 [email protected]
Appendices
Appendix A – JPM Supply estimates Table 8: Crude production/capacity outlook for the largest OPEC producers. JPMe OPEC production growth from 2021+ OPEC Crude Production and Spare Capacity (mb/d) 2018E 2019E 2020E 2021E 2022E 2023E 2024E 2025E Saudi Arabia Crude Production 10.3 9.8 9.5 9.7 10.2 10.7 10.9 11.0 Crude Capacity 12.0 11.8 12.0 12.0 12.0 12.5 12.5 12.5 Iraq Crude Production 2.7 2.7 2.6 2.6 2.7 2.9 2.9 2.9 Crude Capacity 4.7 4.8 5.0 5.5 5.5 5.5 5.5 5.5 United Arab Emirates Crude Production 3.0 3.1 3.0 3.0 3.2 3.3 3.4 3.4 Crude Capacity 3.2 3.4 3.4 3.7 3.8 3.9 3.9 4.0 Kuwait Crude Production 1.0 1.1 0.9 1.1 1.1 1.1 1.1 1.0 Crude Capacity 3.0 3.0 3.0 3.2 3.4 3.5 3.5 3.5 Iran Crude Production 4.6 4.7 4.5 4.6 4.8 5.1 5.1 5.2 Crude Capacity 3.9 3.9 3.8 3.7 3.6 3.5 3.4 3.3 Nigeria Crude Production 1.7 1.8 1.8 1.8 1.9 1.8 1.8 1.7 Crude Capacity 1.8 2.0 2.0 1.9 1.9 1.8 1.8 1.7 Others Crude Production 8.1 6.2 5.6 5.5 5.6 5.5 5.4 5.3 Crude Capacity 6.1 5.7 5.5 5.4 5.2 5.1 4.9 4.8 Total Crude Production 31.4 29.4 27.9 28.4 29.6 30.4 30.6 30.7 Crude Capacity (incl. Sanctioned Countries) 34.7 34.5 34.8 35.4 35.4 35.8 35.5 35.3 Source: J.P. Morgan estimates, Company data.
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James Thompson (44-20) 7134-5942 [email protected]
Appendix B – Global Reserves Background
Angola – Proved liquids reserves 8.4bn boe Angola has reported a rapid increase in reserves since 1991. Most of the proved reserves are located in the offshore parts of the Lower Congo and Kwanza Basins, and the bulk of drilling has targeted deepwater and presalt formations. Angola’s R/P ratio saw a marked fall between 2001 and 2008 as a result of production startups at several deepwater fields discovered in the 1990s. Since then, IOCs led by Total, Chevron, ExxonMobil, and BP have started production at other deepwater fields.
Figure 121: Angola discovered several deepwater fields in the 1990s Figure 122: Production has risen as a result of startups in the 2000s
Source: BP statistical review of world energy 2019. Source: Wood Mackenzie
Brazil – Proved liquids reserves 13.4bn boe Brazil has consistently grown its reserves base since 1980 (1980-2018 average RRR >200%), having seen only one major decline in 2015 after state-run Petrobras cut its own reserves following the oil price decline collapse (here). According to the EIA over 94% of Brazil’s oil reserves are located offshore, and 80% of all reserves are near the state of Rio de Janeiro. The next largest accumulation of reserves is located off the coast of Espírito Santo state, which contains about 10% of the country’s oil reserves. The main additions have been in the pre–salt resources. In 2005, Petrobras drilled exploratory wells near the Tupi field and discovered oil below the salt layer, while in 2007, a consortium of Petrobras, BG Group, and Petrogal drilled in the Tupi field and discovered an estimated 5-8bn boe resources. 2018 R/P was 14 years.
Canada – Proved liquids reserves 168bn boe Canada's oil sands are estimated to be one of the world's largest single petroleum deposits – holding between 1.5 and 2.5 trillion barrels of in-place bitumen. Proven liquids reserves totaled 168bn boe as of 2018, having increased by over 130bn boe in 1999 after the oil sands of Alberta were seen to be economically viable. As highlighted by Alberta Energy Resources, this addition was controversial at the time as oil sands contain an extremely heavy form of crude oil known as bitumen which will not flow toward a well under reservoir conditions. Instead, it must be mined, heated, or diluted with solvents to allow it to be produced, and must be upgraded to lighter oil to be usable by refineries. As a result, Wood Mackenzie estimates the remaining commercial reserves in Canada's oil sands to be around only 38 billion barrels as of 1 January 2019.
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James Thompson (44-20) 7134-5942 [email protected]
Figure 123: Liquids reserves in Canada were estimated at 168bn bbls Figure 124: Total liquids reserves are equivalent to c90 years of in 2018, having increased by over 130bn boe between 1998 and 1999. production at 2018 levels (c5mb/d).
Source: J.P. Morgan estimates, BP statistical review of world energy 2019. Source: J.P. Morgan estimates, BP statistical review of world energy 2019.
Kuwait – Proved liquids reserves reported at c102bn boe Kuwait’s liquids reserves (reported at 102bn boe) are equivalent to X% of OPEC total, and the country’s current R/P ratio is around 90 years, having fallen from ~130 years in the mid 1990s. Reported reserves increased c40% between 1983 and 1984; however, the country has seen relatively few reserves revisions since 1990, despite producing an average 2.3mb/d of liquids over the same period (the reserves estimate has remained unchanged between 2004 and 2018).
This has raised questions about the actual level of proven oil reserves in Kuwait. For example, in an article from 2006 (here), Petroleum Intelligence Weekly claimed to have obtained documents from the Kuwaiti Oil Company referring to a 2001 proven reserves level over 75% below the reported level at the time (c100bn boe, broadly the same level as today). As of March 2001, BP cite Kuwait’s remaining proven crude oil reserves as just 24bn boe. As a result, there have been calls for greater clarification on the state of the country’s oil resources.
Figure 125: Excluding a c40% increase 1993-/94, Kuwait has seen Figure 126: Kuwait’s R/P ratio is around 90 years, having fallen from relatively few revisions despite producing over 2mb/d of liquids ~130years in the mid 1990’s, primarily on increased production.
Source: BP statistical review of world energy 2019. Source: BP statistical review of world energy 2019.
Norway – Proved liquids reserves 8.6bn boe Norway is the largest holder of crude oil and natural gas reserves in Europe. All of the country’s oil reserves are located offshore on the Norwegian continental shelf (NCS), which is divided into three sections: the North Sea (which Wood Mackenzie
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James Thompson (44-20) 7134-5942 [email protected]
estimates holds >55% of the country’s total liquids reserves), the Norwegian Sea, and the Barents Sea. The largest oil discovery in recent years has been Johan Sverdrup (discovered in 2011). The country’s 2018 R/P ratio was 13 years; however, we note this is likely to fall in 2019 as reflecting the startup of Sverdrup. Figure 127: Brazil – Proven reserves replacement vs 100% Figure 128: Norway – Proven reserves replacement vs 100%
Source: J.P. Morgan estimates, BP statistical review of world energy 2019. Source: J.P. Morgan estimates, BP statistical review of world energy 2019.
Russia – Proved liquids reserves 106bn boe Russia holds 106bn bbls of proven liquids reserves as of 2018, ranking 5th in the world and accounting for 22% of total non-OPEC reserves. According to Wood Mackenzie, over half of Russia's remaining oil and condensate reserves are in West Siberia, and with a number of large and giant undeveloped fields in the Northern parts of the basin expected to come onstream over the next 10 years, the basin will dominate the Russian reserves base for the foreseeable future – despite declining production at many of its largest fields. On an aggregate basis, proven liquids reserves are enough to sustain 25 years of production at a 2018 production level of c11mb/d. Russia also has massive resources that have been classified as contingent (i.e. with no current development plans in place and/or significant uncertainty over development plans and timing). Figure 129: Russia holds 106bn bbls of proven liquids reserves as of Figure 130: Proven liquids reserves are enough to sustain 25 years 2018, accounting for 22% of total non-OPEC reserves. of production at a 2018 production level of c11mb/d
Source: J.P. Morgan estimates, BP statistical review of world energy 2019. Source: J.P. Morgan estimates, BP statistical review of world energy 2019.
While there was scepticism Saudi Arabia– Proved liquids reserves 298bn boe around Saudi's reserves level in The proven liquids reserves in Saudi Arabia are the second largest in the world, the 2000s, in a press conference th totaling 298 billion barrels as of 2018, and are concentrated within a relatively small on the 9 of January 2019 the number of supergiant onshore and shallow water discoveries. The main reserves incumbent Energy Minister, Khalid Al-Falih, officially revision occurred in 1988 after the KSA raised its estimate of proved liquids reserves announced that DeGolyer and by c90 billion barrels. The kingdom’s 2018 R/1P ratio was 66 years. MacNaughton had completed the first ever independent evaluation According to Wood Mackenzie, Ghawar accounts for about one quarter of Saudi of proved reserves for the Arabia's oil reserves, while the offshore giants Safaniyah, Zuluf, Marjan, Manifa and Kingdom, which indicated that proved reserves are likely proximal to, and even somewhat 59 larger than, previous estimates. This document is being provided for the exclusive use of [email protected].
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James Thompson (44-20) 7134-5942 [email protected]
Berri collectively hold around 35% of the total. Using data provided during Saudi Aramco’s 2019 bond listing as a proxy (and assuming the company’s reserves are a suitable proxy for total in-kingdom reserves), Saudi’s liquids distribution is relatively balanced at ~50% light, 15% medium, 35% heavy crude.
Figure 131: Saudi’s main reserves revision occurred in 1988 after the Figure 132: Saudi Aramco’s reserves split – Independently assessed KSA raised their estimate by c90 billion barrels. reserves distribution relatively balanced
Arabian Super Arabian Light (API >40) Extra Light 1% Arabian Heavy (API 36-40) (API <29) 12% 35%
Arabian Medium Arabian Light (API 29-32) (API 32-36) 18% 34% Source: J.P. Morgan estimates, BP statistical review of world energy 2019. Source: J.P. Morgan estimates, Saudi Aramco 2018 Bond Prospectus
US – Proved liquids reserves 61bn boe Proven oil reserves in the United States were 61 billion barrels of liquids as of the end of 2018, excluding the Strategic Petroleum Reserve. According to the EIA, the 2018 reserves represent the largest US proven reserves since 1972. From the late 1970s to 2008, crude oil reserves experienced a steady decline. In 2008, the downward trend for crude oil reversed when innovations in horizontal drilling and hydraulic fracturing were applied to tight oil-bearing formations, such as the Bakken Shale of the Williston Basin, and reserves have increased by over 115% in the last decade. Figure 133: Innovations in horizontal drilling and hydraulic fracturing Figure 134: The R/P ratio equaled 11yrs in 2018. It hit a trough of have driven a 116% increase in reserves since 2008. 9.4yrs in 1986 as production from the Alaska pipeline began to peak.
Source: J.P. Morgan estimates, BP statistical review of world energy 2019. Source: J.P. Morgan estimates, BP statistical review of world energy 2019.
Venezuela – Proved liquids reserves 303bn boe The Eastern Venezuela basin surpassed the Maracaibo basin The proven liquids reserves in Venezuela are commonly reported as the largest in the as Venezuela's highest oil- world, totaling 303 billion barrels as of 2018. Venezuela's proven reserves jumped in producing basin in 2000. It also the late 2000s when the heavy oil of the Orinoco Belt was judged economic: while in has the largest remaining October 2007 the Venezuelan government said its proven oil reserves were 100 reserves of any basin, with the billion barrels, this had increased to 172 billion barrels by February 2008, before heavy oil in the Orinoco Belt reaching 211bn bbls in 2009, the largest of any country in South America. As of accounting for the overwhelming majority. 2018, Venezuela’s proven liquids reserves are estimated at c300bn barrels.
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James Thompson (44-20) 7134-5942 [email protected]
Figure 135: Venezuela's proven reserves jumped in the late 2000s Figure 136: … Liquids reserves are estimated at c300bn boe, with the when the heavy oil of the Orinoco Belt was judged economic… heavy oil in the Orinoco Belt the overwhelming majority.
Source: BP statistical review of world energy 2019. Source: Wood Mackenzie
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Disclosures
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{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
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64 This document is being provided for the exclusive use of [email protected].
{[{cHXdtoTfeLnrSuorvFFUtF-JGNRK7kbvAPgNkkrptxjnCy_Beenhg74pQ3urfKNgb2Qgf3W8xdA}]} Christyan F Malek Europe Equity Research (44-20) 7134-9188 03 March 2020 [email protected]
James Thompson (44-20) 7134-5942 [email protected]
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