January Energy Marketing Guide

Transcription

1 ENERGY COMMODITY STRATEGY January Energy Marketing Guide M O R G A N S T A N L E Y R E S E A R C H Global Morgan Stanley & Co. LLC Adam Longson, CFA, CPA Adam.Longson@morganstanley.com Stefan Revielle Stefan.Revielle@morganstanley.com Elizabeth Volynsky Elizabeth.Volynsky@morganstanley.com Cover photo: West Azeri oil platform; photo credit: BP p.l.c. For other important disclosures, refer to the Disclosure Section, located at the end of this report.

2 With OPEC on the Sidelines, Plenty of Headwinds for 215 It likely gets worse before it gets better: Bearish 1H15, but recovery could come as early as 2H and 216 have always represented the most challenging years for this cycle from an S&D perspective. However, without any accommodation from OPEC, the risk to prices is significantly elevated. OPEC or some other intervention is eventually required, most of which would come through lower prices. Although estimates of the oversupply are overstated, we see a large imbalance developing by the spring without some intervention. While we see forces to balance the market without OPEC, perhaps as early as 2H15, these will not come into play without low prices remaining in place over the coming months. Other headwinds add to the price risk and overcorrections are possible: These include expected USD strength, some inventory overhang from this summer, and extremely bearish sentiment. Supply upside vs. our estimates could also come from Iraq/Kurdistan, Libya or Iran, if there was a change in circumstances. With little short term intrinsic value in crude oil markets, momentum will continue to be a driving force for prices. But not all hope is lost we see a path for recovery potentially as early as 2H15. A number of upside risks are underappreciated, and prices are path dependent. The lower prices fall in the interim, the more reaction we will see in the physical market and into later years. Lower prices will curtail investment, increase the risk of OPEC intervention or an outage, or even shut in wells. Based on our forecasts, activity should slow sharply, and if intervention is large and swift, price recovery in 2H15 could be swift as well. Supply Will Outpace Demand, But More So in 1H15 (global crude supply and demand, mmb/d) MS estimates By 22, Material Supply Is Needed Which Requires Higher Prices (mmb/d) Global Crude Supply Global Crude Demand Sources: IEA, JODI, Rystad Energy, Morgan Stanley Commodity Research e Global Crude Demand e Non-OPEC Crude Supply e Cumulative Gross Additions Sources: IEA, JODI, Rystad Energy, Morgan Stanley Commodity Research 2

3 Supply Is Likely To Continue To Come Online Despite Low Prices Global crude supply will continue to ramp in the near-term. The largest of these projects, ex-us shale, are located in Brazil, Iraq, West Africa, Canada, and the US Gulf of Mexico. Many of these large additions are complex offshore projects with long lead times and sunk capital. Even in the US, production momentum can continue for some time. Some wells have already been drilled and simply need to be tied in, while hedges can keep production going from a number of large producers. In fact, the full impact of greater pad drilling in 214 has not been felt by the market. Growing supply and exports have offset lower production from Libya. The market has been able to look through any lower output from Libya as too small to balance the market. At the same time, rising exports from Russia, Iraq (namely KRG), and even the WAF and the North Sea have offset any outages. One of the few positives is that US producers may be delaying completions. Some producers have looked to avoid these costs and maximize NPV on short life cycle wells. At the same time, these efforts may simply delay production and may be targeted at securing lower service costs. Major Capacity Additions Will Continue in 215 (largest capacity additions ex-us shale in 215, mmb/d) Field Name Country Depth Sources: Rystad Energy, Company reports, Morgan Stanley Commodity Research 215 Gross Additions West Qurna 2 Iraq Land 245 Roncador III and IV Brazil Ultra deepwater (15+ meter) 177 Kambesah Mexico Shelf (to 125 meter) 125 Parque das Baleia Brazil Deep water ( meter) 116 Block 17 CLOV Angola Deep water ( meter) 15 Ku-Maloob-Zaap Project Mexico Shelf (to 125 meter) 91 Tawke Iraq Land 88 Sapinhoa Brazil Ultra deepwater (15+ meter) 82 Western Hub (Block 15/6) Angola Deep water ( meter) 79 Lucius (KC875) USA Ultra deepwater (15+ meter) 7 Jack/St. Malo USA Ultra deepwater (15+ meter) 62 Kearl Canada bitumen Land 62 Many Regions Will Continue to See Growth in 215, Even the US (YoY growth, kb/d) Jan-15 Feb-15 Mar-15 Apr-15 May-15 Sources: IEA, Rystad Energy, Morgan Stanley Commodity Research Jun-15 Jul-15 GoM Canada Brazil Iraq Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 3

4 While Demand Should Weaken Seasonally Seasonal refinery maintenance is likely to ramp up. US turnarounds will pick up substantially in February. However, global refinery maintenance tends to peak in Apr/May, particularly Europe and Asia. Refinery margins may struggle to stay so healthy. Refiners have benefitted from a period of strong runs and margins, partly helped by lower crude prices and a realignment of crude diffs. However, with global competition rising, such an environment should prove unsustainable. In fact, refinery excesses were responsible for the initial sell off in crude in later summer 214. Inventories are set to build well above normal, with the peak dislocation occurring in 2Q15. With crude supply growing, OPEC unwilling to intervene, and demand falling seasonally, a dislocation is coming. Although the market may be overestimating the magnitude, stocks will build above seasonal norms. Implied Stock Draws Fall Well Below Norms in 2Q15, But Recover in 2H15 (implied global crude stock change, kb/d) 2,5 2, 1,5 1, 5 - (5) (1,) (1,5) (2,) (2,5) Jan-15 Feb-15 Mar-15 Peak distress likely Apr-Jun Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 But avg draws possible by year end Difference vs. 5Y Median Implied Global Crude Stock 5Y Median Implied Stock Sources: IEA, JODI, Rystad Energy, Morgan Stanley Commodity Research Oct-15 Nov-15 Dec-15 Seasonal Crude Demand Will Play An Important Role in Quarterly Balances (global crude demand, mmb/d) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Y Avg Sources: IEA, JODI, Morgan Stanley Commodity Research estimates 4

5 Curve Structure Reinforces Inventory Overhang Deep contango, floating storage reinforce downside risk for oil over the coming months. Brent and Dubai have moved into a steeper contango (both sit at $1+/bbl of contango) as fears grow about the 2Q15 S&D and limited storage options. Carry trades are now open for onshore and offshore storage, which should drive inventory builds.. Floating storage already starting. Increased barrels are moving to South Africa for storage, just as we saw during late summer 214. However, last week, Dynacom Tankers said that traders are looking for at least 1 VLCCs for floating storage (~2 mmb), with a handful of vessels already booked for offshore storage. If larger quantities of floating storage are required over the coming months, the Brent contango is likely to steepen to support rising VLCC utilization and freight rates. Inventory overhangs can limit price recovery. While more important for curve structure, a large inventory build would be problematic, as even when fundamentals turn, inventory overhangs typically need to be worked off before prices see a sustainable rally (e.g. 21). Deep Contango = Floating Storage Attractive Again (prompt month structure, $/bbl) Prices Were Slow to Respond To Global Stock Draw in 21 Given Inventory Overhang (left axis: IEA stock Δ & misc to balance, kb/d; right axis: Brent price inverted, $/bbl) Source: Bloomberg, Platts, Morgan Stanley Commodity Research Source: IEA crude/liquids balance, Bloomberg, Morgan Stanley Commodity Research 5

6 In An Extreme Example, Even Shut-In Economics Do Not Provide A Short Term Floor The oil price is somewhat meaningless in the short run except at extreme levels. A $1-$2/bbl move in oil price does not have much immediate impact in oil markets. There is little immediate response from physical markets that can push back. The only immediate critical levels are extreme highs where demand is destroyed or extreme lows where existing production struggles to stay online. But even here, there is a delayed response. However, crude prices can fall below shut-in economics in the short run. Producers are extremely reluctant to shut in, even when below cash costs. 1) Many costs are fixed and cannot easily be shed (e.g. labor, equipment, leases, etc). 2) Cash costs can fall: lower demand and sustaining capex can help. 3) Restart costs can be high for such a temporary measure. 4) Potential field damage if production is disrupted. At a minimum, producers will be slow to respond to price signals. Decisions to shut in production are not taken lightly and could require board approval. Moreover, many producers do not believe these extreme low prices will be sustained, which limits action. Rhetoric surrounding OPEC continues to suggest that it will not act as a backstop for prices. Saudi Arabia and other GCC countries continue to point out that lower oil prices are not harmful and that the market (via non-opec) needs to adjust. Repeated calls for emergency OPEC meetings (mainly by Venezuela) have been ignored. Cash Costs Can Slide Lower In Lower Oil Price Environment (y axis: Operating costs with and without royalty effects, $/bbl; x axis: Cumulative global liquids production, mmb/d) $6 $5 $4 $3 $2 $1 $ Mexico Canada ex Oilsands China UAE Saudi Iraq Arabia China US Iran Russia Cash costs without royalties (Dec 214) Cash Costs with Royalties (Dec 214) With royalties (Jan 215) UK Canada Oilsands Venezuela Sources: Rystad Energy, Morgan Stanley Commodity Research Low Prices Did Not Trigger Any Notable Shut Ins During 29 (YoY in non-opec crude supply, kb/d) Jan-8 Mar-8 May-8 Jul-8 Sep-8 Nov-8 Jan-9 Mar-9 May-9 Jul-9 Sep-9 Nov-9 Jan-1 Mar-1 May-1 Jul-1 US L48 ex. GoM Canada Russia Sources: IEA, Morgan Stanley Commodity Research Sep-1 Nov-1 6

7 Without OPEC, Low Prices Are Needed to Slow Production Supply Growth is Likely to Slow and Could Come In Below Our Estimates M O R G A N S T A N L E Y R E S E A R C H We expect to see a material slow down in capital investment in the coming months if current prices hold). US E&Ps have already announced cuts of 2-5%, with another 2-4% cut being proposed for spring, which should impact production in 2H15. North America has plenty of momentum into 1H15, and efficiency gains and more focused capital spending provide some offset (e.g., focus on the core). However, a rapid deceleration is possible in 2H15 that will significantly slow production in 216. While US production growth and capex could return rather quickly, it s unlikely to occur without much higher prices. Under our base case, we see US crude production (incl. GoM) slowing to ~6 kb/d in 215 and decline 1-2 kb/d in 216. Sustained lower prices would cause a greater pullback. International projects will lose funding as well, but the impact will be delayed. While we see a number of higher cost projects outside the US, many of the projects of this scope that are close to completion will continue to come online. The delayed impact of cutting from this project pool will likely be felt in later years. We Now See Much Lower Non-OPEC Crude Supply Growth in 215 (crude oil only production growth in 214 vs. 215e, kb/d) Total Non-OPEC United States Non-OPEC Latin America OECD Europe Canada China Asia ex China Other Non-OECD Europe OECD Asia Oceania Non-OPEC Middle East Mexico Non-OPEC Africa Former USSR excluding Estonia Sources: IEA, Rystad Energy, Morgan Stanley Commodity Research 214 growth 215e growth GoM Has Been A Growing Source of Additions Along with Tight Oil (US crude oil production growth YoY, kb/d) 1,6 1,4 1,2 1, Sources: IEA, HPDI, Morgan Stanley Commodity Research MS estimates Unconventional Alaska Conventional GoM Total US production 7

8 29 Offers A Warning: Capex Fell Dramatically, But Production Still Grew Prices fell by ~75% in late 28, leading to major capex cuts in 29. According to Rystad data, global capex was cut by $36 billion, over two-thirds of which took place in North America (US+Canada). Despite the cuts, US production grew YoY as several large Gulf of Mexico projects started up and/or continued to add capacity in 29. These included Thurnderhorse (25 kb/d), Tahiti (125 kb/d), and Shenzi (1 kb/d). Even in Canada where capex fell by a similar amount, the 11 kb/d Horizon oil sands and upgrading project still came online and additional phases of Foster Creek (12 kb/d) came on. And finally in Russia, where capex declined by ~$8 billion, production also increased YoY, because projects, like Vankor (45 kb/d) and Uvat (195 kb/d) came online. Given the complex and capital-intensive nature of the projects that are expected to add production in 215, we are skeptical of a quick supply response, especially ex-us shale. Capex In Major Non-OPEC Producing Regions Declined Along With Price in 29 (left axis: YoY Capex by region in 29, $ billions; right axis: YoY in Brent price, $/bbl F US Canada Russia Middle East South America Other YoY Price Sources: Rystad Energy, Bloomberg, Morgan Stanley Commodity Research $4 $3 $2 $1 $ -$1 -$2 -$3 -$4 However, Production Continued To Grow As Major Projects Came Online (YoY crude supply by region, mmb/d) 2,5 GoM outage in 28 2, 1,5 1, 5 - (5) (1,) Jan-9 Feb-9 Mar-9 Apr-9 May-9 Jun-9 Jul-9 Aug-9 Sep-9 Oct-9 Nov-9 Dec-9 Jan-1 Feb-1 Mar-1 Apr-1 May-1 Jun-1 Jul-1 Aug-1 Sep-1 Oct-1 Nov-1 Dec-1 OECD Americas Other OECD FSU Asia Non-OPEC Latin America Other Non-OPEC Total Non-OPEC Sources: IEA, Morgan Stanley Commodity Research estimates 8

9 US Production From Shale Is At Serious Risk Analyzing shale economics is not so simple. US shale is not homogenous, even within the same company or play. Acreage and costs vary wildly, as do infrastructure access and sunk costs. We see producers with viable acreage as low as $3/bbl WTI and as high as $1/bbl. Regardless, lower prices should limit cash flow and spending, while any freeze in the high yield market could quickly close access to capital for producers. Fringe shale production requires $8/bbl WTI. Analysis by our E&P team suggests that numerous companies non-core areas are uneconomic assuming a 2% hurdle rate. Production could be cut in these areas as producers move to most-productive acres and those that require lower transport costs (e.g., Texas). The Bakken is particularly at risk given many producers lack of transport infrastructure and high costs of rail. Slowing production will come on a lagged basis. Much of early 215 production is already underway and will be hard to curtail at this point. Momentum and improving capital efficiency should keep US growth elevated in early 215 despite lower prices. Hedges, incentives and other obligations can also support activity beyond what economics would suggest. But at our base case, we should see a rapid reduction in activity into 2H15. According to Drew Venker, at $65/bbl WTI, oil-focused E&Ps could shrink 7% in 216, which seems untenable. US unconventional production is most at risk now, but will be the first to return. US shale is not the high cost producer, but given its short lead time, it will be the first to slow in a lower price environment. However, when prices rebound, US shale producers will be able to respond in 3-6 months. US Shale Production On The Margin Is At Risk, Esp Small/Mid-Caps (WTI Breakeven assuming 2% pre-tax IRR, $/bbl) XEC - Cana Woodford XEC - Delaware Lower Wolfcamp WLL - Bakken Dunn Co. (KOG) WLL - Bakken (Sanish) CLR - Core Bakken HK - Bakken CXO - Bone Spring WLL - Niobrara (NE Extension) EPE - Eagle Ford WLL - Bakken (West) Average BCEI - Niobrara (Wattenberg) CXO - Midland Wolfcamp CLR - Avg. Bakken HK - E. Tx Eagle Ford BBG - Niobrara (Wattenberg) BBG - Uinta OAS - Bakken EPE - Southern Midland Wolfcamp Based on company historical realizations Sources: Morgan Stanley Equity Research $ $5 $1 $15 $31 $42 $51 $52 $61 $61 $62 $64 $65 $66 $68 $75 $75 $78 $81 $87 $87 $92 $98 US Unconventional Production Set To Slow Through 215 With Lower Prices (US YoY production growth for select plays, kb/d) 1,2 1, Source: HPDI, Morgan Stanley Commodity Research MS estimates Bakken Permian Eagle Ford Niobrara Total 9

10 US Rig Count Set to Fall Sharply on and Capex Cuts US rig counts tend to follow pricing, but on a lag. In previous oil price cycles, rig counts did not peak until 4-6 months after the peak in oil prices. Similarly, the peak to trough in US oil rig count was around 8 months, but larger cycles can be much longer. US rigs are already 1-2 months into their descent. Since peaking at just over 16 in Oct 24, the US oil rig count has fallen sharply, particularly since 2H Dec. However, the total rig count can be deceptive when it comes to the actual impact on production. Producers will remove rigs with the lowest productivity first (e.g., vertical and directional rigs) and move production to the core areas. Producers could also run their rigs more efficiently, all of which can mute the impact of a lower US rig count. Rig Count Decline Can Be A Quick And Prolonged Response (y-axis: number of US rigs relative to peak price; x-axis: number of months before/after peak price) Drops In Rig Counts Can Be Severe (US oil rig count cycles vs. pricing) Oct-9 Sep- Jul-8 Jun-14 IMF Brent Spot Price US Oil Rig Count vs. Prices Cycle Start Date Start Tough Date Trough % Months Peak Date Peak Count Trough Date Trough Count % Months Peak Delay Trough Delay 1986 Nov-85 $29.82 Jul-86 $ % Jul-87 $19.83 Oct-88 $ % 15 Dec Feb % Oct-9 $36.9 Jun-91 $18.8-5% 8 Dec Oct % Apr-93 $18.63 Feb-94 $ % 1 Nov Apr % Oct-97 $2.5 Sep-99 $9.8-51% 23 Aug Aug % 24 (2) (1) 21 Nov- $32.52 Dec-1 $ % 13 Mar Sep % Aug-6 $73.61 Jan-7 $ % 5 Aug Feb % Jul-8 $133.9 Dec-8 $ % 5 Nov May % Mar-12 $ Jun-12 $ % 3 Aug-12 1,423 Jan-13 1,318-7% Jul-14 $16.98 Jan-15 $ % 6 Oct-14 1,593 MEDIAN -46% 8-4% Sources: Baker Hughes, Morgan Stanley Commodity Research estimates

11 Mix Effects Can Help Mitigate The Decline In the Rig Count Not All Rigs Are Created Equal (US oil rig count by type) 12/12/214 Horizontal Vertical Directional Total Rigs by Play IP Count IP Count IP Count IP Count Bakken Permian Eagle Ford Niobrara Mississippian Lime Other Total MS Dec-15 Estimate Horizontal Vertical Directional Total Rigs by Play IP Count IP Count IP Count IP Count Bakken Permian Eagle Ford Niobrara Mississippian Lime Other Total Change Horizontal Vertical Directional Total Rigs by Play IP Count IP Count IP Count IP Count Bakken Permian Eagle Ford Niobrara Mississippian Lime Other Total % Change 3% -46% -6% -74% -21% -6% 14% -53% Sources: HPDI, Baker Hughes, Morgan Stanley Commodity Research Overall rig counts mask the large variance in performance. When looking at how rigs are deployed, we see significant differences in the impact of each rig. Lower performing plays such as the MS Lime and Niobrara will likely lose rigs first, as will the conventional Permian. However, these rigs add relatively little to US production growth. The US still has a large number of inefficient vertical and directional rigs. While these wells tend to be cheaper, the average IP rate is just a fraction of new horizontal wells. High-grading (i.e. moving to the core) and efficiencies gains can further reinforce production. Losing low quality rigs among plays offers a double-digit uplift in weighted average IP. However, producers can pick up efficiencies within plays as well that can further limit the impact of lost rigs. The production impact is smaller than the rig impact 11

12 High-grading The US Drilling Portfolio Offers More Offsets Producers are moving drilling activity to their core and best performing acreage. This is one effort producers are using to further cut capex and yet keep production growth fairly resilient. We see significant variability within and across plays. We see oil IPs from as low as 1-3 b/d along a number of high quality wells well over 1 b/d. As a result, a number of high performing wells and rigs contribute an outsized share to US production growth. Focusing on these best-in-class wells may allow producers to lift capital efficiency once again without sacrificing too much production growth. Efficiency gains can also be had. Oil IPs have been rising slowly over the past several years as producers test new techniques for drilling and completion. Pad drilling is still a rising phenomenon within some plays (e.g. the Permian). We see more room for gains on completion techniques, although spending on R&D is being cut with low prices. There Is A Wide Range of IP Rates In the Shale Plays (Range of oil IPs from horizontal wells producing in 214 in various plays) IPs Have Been Rising Over Time (IP rates in major US shale plays) Bakken Eagle Ford Permian - Midland Permian - Deleware Niobrara Middle 8% range Average Top 25% Sources: HPDI, Morgan Stanley Commodity Research Mississippi Lime Apr-11 Jun-11 Aug-11 Oct-11 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Bakken Permian - Midland Permian- DE Eagle Ford Sources: HPDI, Morgan Stanley Commodity Research Note: Wells below 3 kb/d filtered out as assumed to be mischaracterized wells Feb-13 Apr-13 Jun-13 Aug-13 Oct-13 Dec-13 Feb-14 Apr-14 Jun-14 Aug-14 12

13 Plenty of Low Quality Wells Were Drilled in 214 The Midland Drilled Plenty of Low Quality Vertical Wells (count of oil wells drilled in 214 YTD by oil IP) 4, 3,5 3, 2,5 2, 1,5 1, 5 1% 9% 8% 7% 6% 5% 4% 3% 2% 1% % Bakken Bakken Eagle Ford Eagle Ford Permian: Delaware Sub-3 Oil IP Wells Still Prevalent (% of oil wells drilled in 214 by oil IP by play) Permian: Delaware Permian: Midland Permian: Midland Niobrara Mississippian Lime < >=1 Sources: HPDI, Morgan Stanley Commodity Research Niobrara Mississippian Lime < >=1 Eagle Ford Dominated Oil Wells Drilled, But Still Contained Many Sub-Par Results (count of horizontal oil wells drilled in 214 YTD by oil IP) 2,5 2, 1,5 1, 5 Less Room For High-Grading in Horizontal (% of horizontal oil wells drilled in 214 by oil IP by play) 1% 9% 8% 7% 6% 5% 4% 3% 2% 1% % Bakken Bakken Eagle Ford Eagle Ford Permian: Delaware Permian: Delaware Permian: Midland Permian: Midland Niobrara Mississippian Lime < >=1 Niobrara Mississippian Lime < >=1 Over 85% of the oil wells drilled in the Midland in 214 had oil IPs < 3 b/d, as did 55% of the oil wells across six shale plays (the Bakken, Eagle Ford, Delaware, Midland, Niobrara and Mississippian Lime). Even if we simply focus on horizontal wells, the Midland, Niobrara and Mississippian Lime all had over 5% of the 214 oil wells drilled come in with oil IPs below 3 b/d. 13

14 A Repeat of the Natural Gas Story Is Unlikely The natural gas price decline of 212 and subsequent production response offers parallels to oil. Initially, production fell hard in 1Q12 as prices dropped to low s of $2/MMbtu. Total gas rigs fell 5% in 212 and horizontal rigs fell 47%. However, production continued to grow. Delayed producer responses and coring-up kept supply from declining dramatically despite uneconomic prices. The Barnett Shale is a good case-study. Production rates improved 28% in 212 vs 211 and drill days fell 26% from 11 days to just 81. Similarly, we have seen large gains in rig efficiency and sometimes IPs as we look across natural gas plays. Such an event is possible in oil, but we would argue that oil is a different molecule that is further along in its maturity than 211 natural gas. What was different about gas? Oil has few of the advantages that unfolded in natural gas. 1) A new low cost resource opened up (Marcellus). 2) IPs went up marginally, but this pulled up the avg in recent years. 3) Rig efficiency rose as we went away from HBP drilling, ramped up pad drilling, and changed some techniques. 4) Falling backlogs and new infrastructure have supported production more than we thought. 5) Associated gas and wet gas were marginally helpful too. Despite Rig Declines in 212, Dry Gas Production Grew YoY (LHS: Dry gas production, Bcf/d; RHS: Gas Rigs) Feb-11 Apr-11 Jun-11 Aug-11 Oct-11 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 Apr-13 Jun-13 Aug-13 Oct-13 Dec-13 Feb-14 Apr-14 Jun-14 Dir/Vert Horizontal Dry Gas Prod (LHS) Source: EIA, Baker Hughes, Morgan Stanley Commodities Research Aug-14 Oct Rig Efficiency And New Plays Drove Most of the Production and Rig Count Disconnect (LHS:Wtd avg horizontal IP for Marcellus, Haynesville, Barnet & Eagle Ford, Mcf/d; RHS: wtd avg wells/rig/month 4,6 4,4 4,2 4, 3,8 3,6 3,4 3,2 3, 1Q11 2Q11 3Q11 4Q11 1Q12 HZ IP (Mcf/d) 2Q12 3Q12 4Q12 1Q13 Source: HPDI, Morgan Stanley Commodities Research 2Q13 HZ wells/rig/mo 3Q13 4Q

15 However, This Is Not 28/9 or /9 was a demand shock, this is a self-inflicted crisis. In 28, demand evaporated after the Lehman bankruptcy, sending global crude demand spiraling down. The call on OPEC+stocks fell from nearly 32 mmb/d in Jan-8 (>31 mmb/d pre-lehman) to ~28 mmb/d for much of 29. This rapid shift left OPEC overproducing and created an inventory overhang that took until late 21 to work off. In contrast, the crude only Call on OPEC+stocks was expected to fall towards 3. to 3.2 mmb/d in 215 prior to the recent sell off, and now looks like it will approach 3.5 mmb/d in our base case. If OPEC wanted to intervene, prices could still be in the $9+/bbl range for Brent. The selloff this summer/fall was sparked by low refinery runs and then compounded by the return of Libya not all that different from the 212 correction. If OPEC were to accommodate markets in 215 as they have in past periods, prices would trade much higher (esp. on a constant currency basis). At $9/bbl, we were expecting a mere 8 kb/d imbalance in 215. Physical markets do not show the same level of stress. Currently, physical markets show some signs of improvement. While fundamentals could change, we see several key differences vs ) The deep contango is missing: The flood of oversupply sent Brent prompt structure near $3 contango in 28/9 to cover extreme floating storage costs. By comparison structure is ~$1.11/bbl today with no sign of floating storage 2) Spare capacity remains low: In 28/9, a major outage would have only helped to close the gap, given excess OPEC capacity. Today, there is very little spare capacity. A large outage would first clean up the market, but there is little ability to offset any squeeze beyond that point. In 28/9 the Call on OPEC Collapsed with Demand; Today s Call is High (Crude oil specific Call on OPEC & Stocks, mmb/d) Crude only Call on OPEC+Stocks collapsed in 8/9 The crude Call on OPEC hasn't changed much Jan-8 May-8 Sep-8 Jan-9 May-9 Sep-9 Jan-1 May-1 Sep-1 Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Sources: IEA, JODI, Rystad Energy, Morgan Stanley Commodity Research MS estimates Brent Structure Is Not As Distressed At It Was In 28/9 (Prompt Brent 1-2 structure, $/bbl) $3. $2. $1. $. -$1. -$2. -$3. Jan-8 May-8 Sep-8 Jan-9 May-9 Sep-9 Jan-1 May-1 Sep-1 Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Sources: Bloomberg, Morgan Stanley Commodity Research 15

16 An Oversupply Problem Is Emerging, But The Market Is Overestimating Its Magnitude We see a modest oversupply developing by mid-215 with no intervention. While any degree of oversupply is negative, talk of a mmb/d oversupply far overstates the issue. We believe much of this misperception comes from three areas: 1) A need to explain the large selloff. 2) Reliance on a fundamentally flawed IEA liquids balance that fails to properly capture true black oil dynamics. 3) A misunderstanding of the Call on OPEC and a lack of appreciation for normal seasonal inventory changes. The traditional IEA balance is fundamentally flawed. By treating all hydrocarbons as fungible, this balance ignores the nuances and drivers of the industry. Refiners are the real consumer of crude oil, and will consume crude and shift yields to maximize profits and supply the most constrained product. As a result, crude oil supply and demand can vary wildly from products and/or IEA balance figures. Most analysts forget the stocks in the Call on OPEC+Stocks. The only way we can see a large oversupply is by looking at current OPEC production vs. the Call on OPEC, which appears large in 2Q15. However, the call on OPEC is really the Call on OPEC + stock changes. Normal seasonality is for stocks to build during this period as refiners move into maintenance. That s why OPEC production is not as volatile as the call. We use a true crude oil balance, which shows healthier crude demand and a modest oversupply developing that can be corrected. An eventual oversupply will keep pressure on prices, but we don t see anything close to the 28-like situation emerging. Extreme bearishness also ignores a number of feedback loops or offsets that could occur at lower prices. IEA Liquids Balance Fails to Capture True Crude Oil Dynamics (Various Calls on OPEC and OPEC production, mmb/d) Q214 2Q214 3Q214 4Q214e 1Q215e 2Q215e 3Q215e 4Q215e Ignoring the Stocks in the Call on OPEC+Stocks Can Overstate the Issue (5Y Average Quarterly Stock, Globally Implied and OECD, mmb/d) (.5) (1.) (1.5) (2.) 1Q 2Q 3Q 4Q Implied Call on OPEC IEA Call on OPEC Crude + Stock 5Y Avg Crude Stock - Global implied 5Y Avg Total Oil Stock - Global implied OPEC Crude Production Call on OPEC Crude + Stocks Sources: IEA, JODI, Rystad Energy, Morgan Stanley Commodity Research 5Y Avg Crude Stock - OECD Industry 5Y Avg Total Oil Stock - OECD Industry Sources: IEA, JODI, Rystad Energy, Morgan Stanley Commodity Research 16

17 Demand Will Likely Prove Better Than Expected Models imply nearly 3 kb/d of incremental product demand with crude oil at $7/bbl vs. $9/bbl. Crude runs should also benefit, potentially in a disproportionate manner, as more of the stimulus is likely to come from more constrained transportation fuels. Historically, OECD demand is very price elastic. GDP is the major driver of crude demand in models, but prices matter too, especially in the OECD. Elasticity will be lower this cycle as some non-oecd nations have discussed using low prices as an opportunity to unwind subsidies. Subsidies also limit the passthrough to EM consumers. However, the OECD can be quite elastic and represents the majority of upside demand revision potential. Transport fuels, which drive crude demand, are surprisingly healthy and most likely to be stimulated. We find there is a much stronger association between demand for high value transport fuels and refinery crude demand than there is for headline products. Much of the product weakness this year came from OECD ancillary products such as fuel oil, other gasoil (heating and spec issues), and other products. Product Demand Will Be Higher At Lower Price Points (left: product demand vs. $9 Brent baseline; kb/d; right: YoY in product demand, kb/d) (1) (2) $5 $6 $7 $8 $9 $1 Global Product Demand Sensitivity vs. $9 Brent OECD Product Demand Sensitivity vs. $9 Brent Est. Global Product Demand Growth (RHS) Note: Assumes 93 average DXY for 215 and MS GDP est. Sources: Bloomberg, IEA, IMF, Morgan Stanley Commodity Research 1,4 1,2 1, OECD Demand for Key Transport Fuels Is Strong; Other Products Are Weak (YoY in demand, kb/d) , -1,2 1Q211 2Q211 3Q211 4Q211 1Q212 2Q212 OECD Total Products OECD All Other Products 3Q212 4Q212 1Q213 Source: IEA, Morgan Stanley Commodity Research 2Q213 3Q213 4Q213 1Q214 2Q214 OECD 3 Main Products 3Q214 17

18 Markets May Be Too Focused on Headline Product Demand Crude demand is more important than product demand. The end market for crude oil is a refinery, not a gasoline engine. As we ve outlined in the past (Crude Oil: Near Term Fundamentals Not As Bad As Suggested (3 Nov 214)), crude demand is not equivalent to product demand for a number of reasons. In fact, crude demand had been far weaker than product demand since the mid- 2s given rising distillate yields with new investment, falling refinery utilization (which allows refiners to run more efficiently on the margin), rising other liquids demand (e.g. biofuels), processing gains and growing demand for NGLs, etc. These headwinds have now eased. Crude demand is now improving faster than product demand. 214 will mark the first year since the early 2s that crude runs outpace product demand. Crude demand grew at 2X the rate of product demand in 214, and should trend closer to product demand in the future. The composition of product demand is as important as the headline. Refiners run to maximize profitability and produce the most constrained products, which tend to be the transportation fuels. Currently, product demand weakness is coming from less valuable or important products, a trend that is likely to continue. Transportation fuels remain healthy, with gasoline in particular, growing well in both the OECD and non-oecd. EM Gasoline Demand Growth Is Robust (YoY change in gasoline demand, %) 35% 3% 25% 2% 15% 1% 5% % -5% -1% -15% Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Crude Demand and Product Demand Rarely Align (YoY in total product demand and refinery throughput, kb/d) 3, 2,5 2, 1,5 1, -1, -1,5-2, Rising Distillate Yields Were A Headwind For Crude Demand in Recent Years (US diesel yield, %) e Product - Crude YoY Product Demand YoY Refinery Throughput Jan-2 Aug-2 Mar-21 Oct-21 May-22 Dec-22 Jul-23 Feb-24 Sep-24 Apr-25 Nov-25 Jun-26 Jan-27 Aug-27 Mar-28 Oct-28 May-29 Dec-29 Jul-21 Feb-211 Sep-211 Apr-212 Nov-212 Jun-213 Jan-214 Aug-214 U.S. Refinery Yield of Distillate Fuel Oil (Percent) Brazil India China (inv-adj) 12 per. Mov. Avg. (U.S. Refinery Yield of Distillate Fuel Oil (Percent)) Sources: IEA, BP, EIA, China Customs, ANP, Thomson Reuters, Bloomberg, Morgan Stanley Commodity Research 18

19 Modest Demand Growth, Capacity Additions A Structural Challenge For Refining Margins and Product Markets An overbuilding of refining capacity is resulting in structurally lower refining margins. Although product demand remains healthy, current levels of refining capacity are too high for the current level of demand. If all these refiners were to run at the same time, product markets would be severely oversupplied. Margins must price marginal refiners out of the market on a consistent basis. Refining utilization is now at its lowest level since the mid-198s, and yet product markets are generally oversupplied. Given the abundance of refining capacity globally (and which continues to grow), product markets must price at a level to limit product production on average. This can keep product cracks lower than they otherwise would be. The build out of refining capacity will continue. Many non-oecd countries are looking to add refining capacity, often times when economics would say otherwise. Excess capacity and responses to economic signals could add to seasonal volatility. Rationalizing refining capacity is difficult. Although some refineries have closed in the OECD, permanently closing refineries is difficult. Some key reasons: 1) Integrated ownership; 2) Sovereign concerns (i.e. should France not have a refinery?); 3) Infrastructure problems (some refineries are needed to supply domestic markets given lack of product import capacity); 4) opportunistic buyers (see PADD 1 and PetroPlus) In Our Base Case, Refining Utilization Should Rise As Capacity Additions Slow (Global refinery capacity utilization, %) 88% 86% 84% 82% 8% 78% 76% 74% 72% 7% Source: IEA, BP, Morgan Stanley Commodity Research e 217e 219e Capacity Additions Should Start To Slow in 218 (Refinery capacity additions by region, mmb/d) OECD Americas OECD Europe OECD Asia FSU Non-OECD Europe China Other Asia Latin America Middle East Africa 217 Source: IEA, Morgan Stanley Commodity Research

20 Volatility Should Be the New Normal Oil markets are without a cartel for the first time in over 5 years, which is inherently destabilizing. Prior to OPEC wrestling control of markets in the 197s, the US Texas Railroad Commission controlled production and pricing. The loss of monopolistic pricing power could leave oil in a lower incentive price environment, but also leaves oil susceptible to the large swings present in other commodities. Talk of a new equilibrium price may be premature. Long run incentive prices are challenged, but a number of structural changes are occurring (both bullish and bearish), but cyclical factors should prove more important for prices. Commodities rarely trade at marginal cost and tend to overshoot. Geopolitics add both a bullish and bearish slant. Black swan events on the bearish side could come from a lifting of Iran sanctions (which looks more likely) or a return of Libya. On the bullish side, Venezuela and Nigeria may struggle to maintain production if this new world persists. In Recent Years, Oil Has Been Less Volatile Than Other Commodities (6-month rolling volatility, annual %) (6-month 7% realized volatility, %) 6% 5% 4% 3% 2% 1% Gas Crude Nickel Palladium Sources: Bloomberg, Morgan Stanley Commodity Research New Bullish and Bearish Structural Problems for Oil Markets Bullish Factors US needs to grow longer term Little spare capacity Outage risk is higher at low prices Higher volatility reduces investment appetite. Loss of the OPEC put US exports/quality congestion Costs are cyclical rig rates will recover Bearish Cost deflation and forced innovation Inventory overhang USD/international costs Prisoner s dilemma and problem of perceptions and faith in longterm oil NOCs/OPEC growth and continuing to invest Growing risk of sanctions relief for Iran 2

21 Lower Prices Today Can Setup For Higher Prices Later The lower and longer prices fall in the interim, the greater the long run impact and risk of higher prices as a reaction. A lack of investment could result in much higher prices later in the decade. Oil faces long run challenges, but healthy supply growth is still required to balance the market. Based on modest demand growth assumptions, we estimated the market required ~3 mmb/d of gross additions from to both offset natural declines and support demand growth. Without adequate investment, oil demand could far outstrip supply in a few years. Outside the US, supply growth cannot return quickly once curtailed. Many of these additions are high cost and risky investments with long lead times, particularly later in the decade. These projects will struggle to respond quickly and return with any improving price signal, creating the risk that prices could overshoot to the upside. If anything, removing the OPEC put should raise the hurdle rate required on oil projects, which may require even high prices for higher cost and risky projects. While a supply crunch would be short term bullish, the resulting high prices would be long run destructive for oil demand. As prices fall, outage risks rise, particularly from financially stressed nations that cannot maintain subsidies. As subsidies are lifted, the risk of civil unrest tends to rise, putting production at risk. With little spare capacity today, the market has few options to deal with a large outage. Creating a world where OPEC needs to produce at such high levels leaves the market increasingly vulnerable to shocks and increased volatility. Long Run Balances Have Suggested More Supply Is Needed by 218+ (left: YoY in non-opec crude supply, kb/d; right: Crude-specific Call on OPEC+stocks and production, mmb/d) 1,6 1,4 1,2 1, (2) (4) (6) forecast 215 Est. Crude Oil Supply Growth before OPEC Crude Crude Only Call on OPEC+Stocks OPEC Crude Production Assumes MS base case price forecast and limited loss of non-us investment. Sources: IEA, JODI, Morgan Stanley Commodity Research estimates Necessary Additions Are At Risk, Risking Much Higher Prices Later (y-axis: Marginal breakeven price assuming 1% hurdle rate on a Brent-equivalent basis, $bbl, x-axis: incremental liquids production added , mmb/d)) $14 $12 $1 $8 $6 $4 $2 Canadian In-Situ Oilsands Projects Permian, US Eagle Ford, US Bakken, US Canadian Mining Oilsands Projects Kearl, CA W. Qurna 2, IQ $ Sources: Rystad, Wood Mackenzie, Morgan Stanley Commodity Research 21

22 1986: History Rhymes, But Doesn t Repeat Rather than a repeat of 1986, volatility is likely the new norm. We continue to hear comparisons between OPEC s recent actions and those of While there are similarities, we don t believe the oil market has entered a new decade-long cycle of drastically lower prices. Rather, we see a market where elevated volatility and boom-bust cycles will likely become the norm. Today s situation is different in many crucial ways: 1) Saudi Arabia didn t lift production this time, OPEC just failed to cut. 2) Spare capacity was >15 mmb/d in Today, practical spare capacity is ~1 mmb/d with elevated risk of outages and civil unrest. 3) Lower cost sources of untapped production were available in the 198s. 4) The market is more reliant on long lead time projects (e.g. offshore) in challenging regions, and the breakdown of service costs has changed. 5) While shale increases US supply elasticity, the globe has a larger production base to replace with arguably higher decline rates (offshore, shale) relative to conventional onshore that represented a large share of production in the 198s. Supply swings in a few key countries explain a surprising amount of the oil cycles of the past 3 years. We continue to hear incorrect narratives about 1986, as well as oil history overall. Iraq, Russia and Saudi Arabia supply were responsible for a large part of many oil cycles of the past 3 years. Non-OPEC production (ex. Russia) has been more consistent and followed normal cycles. Saudi and OPEC Production Dropped Significantly in the Mid 198s, Leaving Plenty of Spare Capacity (left axis: OPEC crude production, mmb/d; right axis: Saudi crude production, mmb/d) OPEC (LHS) Sources: BP, IEA, Morgan Stanley Commodity Research Saudi Arabia (RHS) Swings in Russia and Iraq Production Were Large Contributors to the Last 3 Years of Price Swings (Liquids supplies by region, mmb/d) Source: IEA, Morgan Stanley Commodity Research Total OPEC Non-OPEC Non-OPEC ex. FSU

23 By Comparison, Supply Outage Risk Is Rising, Reinforcing Volatility Will be the New Norm We worry most about countries that cannot support gasoline subsidies as those directly impact consumers. We ve never been a big advocate of OPEC balanced budget math as driving oil markets or behavior. However, Venezuela and Nigeria are exceptions to the rule. In these countries, populations have become used to low gasoline prices (esp in Venezuela), but the country is dependent on international supplies. If oil prices decline to levels such that subsidies cannot be supported and will need to be lifted, civil unrest and crude production disruptions could result. Both Venezuela and Nigeria have a history of protests over gasoline pricing changes. Lower prices increase the risk of a major outage. This is possible longer term if governments cannot provide basic services, leading to civil unrest and disruptions, especially as ~12% of oil production is in economically unstable regions. If supply does go offline, there is little spare capacity to meet it. Saudi Arabia holds the vast majority of spare capacity, but it is unlikely to use it due to the need to manage reservoirs. They are currently producing near historical maximums and never went near reported spare capacity in prior crises. Furthermore, much of this spare capacity is not effective, especially in Libya as it could take months-years to bring that capacity into production given the flight of oil ex-pat workers and damage to fields. Significant Share Of Global Oil Supply Resides in Challenging Areas (Dec 214 global crude supply from at-risk countries, mmb/d) Iraq 2.42 Venezuela 1.87 Nigeria Libya Argentina Yemen Sources: IEA, Morgan Stanley Commodity Research Sudan South Sudan.2 Syria Almost No OPEC Spare Capacity to Offset a Major Outage (OPEC spare capacity as of Dec 214, kb/d) 5, 4,5 4, 3,5 3, 2,5 2, 1,5 1, 5 51 To Max KSA Production 435 Others Spare 945 Realistic Capacity 435 2,78 3,215 Saudi Arabia Spare Capacity Other Effective Spare Effective Spare Capacity Source: IEA, Morgan Stanley Commodity Research *In Libya, we assume 1.4 mmb/d of capacity Iraq Nigeria Iran Libya* Venezuela 4,545 Reported Spare Capacity 23

24 Global Overview Despite Rising Project Costs, Upstream Capex Growth Expected to Decelerate M O R G A N S T A N L E Y R E S E A R C H Capital investment set to slow in response to low prices. Oil capex grew rapidly in the 2s in response to higher prices. With the recent decline, that trend could reverse in the medium term. However, we would still expect capex to grow longer term in order to meet a conservative level of demand and support supply growth. Mix of investment shifting: Exploration accounting for a smaller share of capex. With rising US onshore production growth largely from proven reservoirs, many firms are trading in exploration risk for commodity price risk. As a result, there are now likely fewer high risk exploratory wells, allowing exploration to decline as a share of total capex. Moreover, with a more manufacturing-like process in US shale, development and well capex are rising as a percentage of total capex. The number of wells needed to maintain US production momentum only grows as production grows. Finally, capex categories such as modification capex (EOR) are losing share globally as well as EOR drives less production growth in our forecast period. Cyclical or secular deceleration? Falling service costs and lower oil prices should reduce investment and the overall cost of projects. However, one could argue that such savings are only cyclical. As prices recover, demand for oil services will rise as well. Global Oil Capex Is Likely To Slow In the Medium Term, But Should Pick Up Later (Oil field capex, millions $) : 15% CAGR e: -2% CAGR e 216e 217e 218e 219e 22e Source: Rystad Energy, Morgan Stanley Commodity Research 216e-22e: 6% CAGR Exploration Capex Is Most At Risk In Low Price Environment (% share of total oil capex, %) 1% 9% 8% 7% 6% 5% 4% 3% 2% 1% % 11% 2% 37% 29% 2 11% 18% 37% 31% 21 11% 18% 4% 28% 22 1% 17% 41% 29% 23 8% 17% 45% 27% 24 Development Capex Modification Capex Exploration Capex 7% 16% 44% 31% 25 8% 17% 44% 28% 26 8% 17% 44% 28% 27 9% 18% 45% 27% 28 9% 19% 45% 25% 29 11% 18% 47% 22% 21 13% 16% 47% 22% % 15% 48% 23% % 14% 48% 24% 213 Well Capex Subsea Brownfield Capex Source: Rystad Energy, Morgan Stanley Commodity Research 13% 13% 49% 23%

25 8% 7% 6% 5% 4% 3% 2% 1% % Development Capex Well Capex Ultra deepwater (15+ meter) Shelf (to 125 meter) Modification Capex Subsea Brownfield Capex Deep water ( meter) Land M O R G A N S T A N L E Y R E S E A R C H Breakdown of Capex Spending: Saving on Rigs Should Not Be A Large Savings for Many Projects For US shale, 6-7% of the cost is now in completion. Well capex is the majority of US well cost. However, drilling efficiencies have materially lowered the burden from running rigs. Hence, fracking and completion services should be vulnerable and a target of US E&Ps. Deepwater Projects Have Higher Proportion Of Development Capex (proportion of capex costs by type, %) Sources: Rystad Energy, Morgan Stanley Commodity Research Unconventional Production Has A Much Higher Share Of Well Capex (proportion of capex costs by type, %) 1% 9% 8% 7% 6% 5% 4% 3% 2% 1% % Development Capex Well Capex Modification Capex Subsea Brownfield Capex Conventional Arctic Oil sands (mining) Oil sands (in-situ) Extra heavy oil Tight liquids plays Shale oil plays Sources: Rystad Energy, Morgan Stanley Commodity Research Deep water projects tend to be more exposed to facility development. Drilling costs can be material, but these savings won t dramatically improve the economics of an offshore project. Exploration capex: Costs incurred to find and prove hydrocarbons: seismic, wildcat and appraisal wells, general engineering costs, based on reports and budgets or modelled. Development capex: Greenfield investments for the facility. This cost type drives the investments for the hull/leg, topsides and subsea structures. Well capex: capitalized costs related to well construction, including drilling costs, rig lease, well completion, well stimulation and commodities. Modification capex: Larger brownfield investments for the facility that is not expensed as an opex. This can be EOR, new wellhead platform or topside module. Brownfield investments related to drilling and completion of wells are included under Well Capex. Subsea brownfield capex: Late life investments for subsea structures. Brownfield drilling programs for fields with need for subsea units will drive the Subsea Brownfield Capex. 25