where should my crude go….now? - baker & o'brien should my crud… · 1 •last year’s...

Baker & O’Brien, Inc. All rights reserved.

Argus North American Petroleum Transportation Summit

June 1-3, 2015

Where Should My Crude

Go….Now?

1

• Last year’s presentation: “Where Should My Crude Go?”

– How refiners plan crude purchases

– The stepwise displacement of Light/Medium Crude Imports

– Limitations of refineries to run Light Tight Oil (LTO)

– Breakeven values of LTO in different refineries

• This year’s presentation: “Where Should My Crude Go…Now?”

– Industry reaction to production increases and price drop

– Refining industry adaptations

– Light Ends quality issues and opportunities

Presentation Overview

Note: This presentation assumes that current restrictions on crude oil exports will

continue for at least the next several years, and does not address the pros/cons

or impacts of lifting or keeping those restrictions.

2

U.S. Crude Oil Production at Highest Level in 30 Years

Source: U.S. Energy Information Administration (EIA) and Baker & O’Brien Analysis.

U.S. Crude Oil Production

MB

/D

Current Landscape

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Ja

n-2

005

Ju

n-2

005

No

v-2

00

5

Apr-

200

6

Sep

-20

06

Fe

b-2

00

7

Ju

l-2

00

7

De

c-2

00

7

Ma

y-2

00

8

Oct-

200

8

Ma

r-20

09

Aug

-20

09

Ja

n-2

010

Ju

n-2

010

No

v-2

01

0

Apr-

201

1

Sep

-20

11

Fe

b-2

01

2

Ju

l-2

01

2

De

c-2

01

2

Ma

y-2

01

3

Oct-

201

3

Ma

r-20

14

Aug

-20

14

Ja

n-2

015

Other Onshore

CA

Alaska

CO/WY/UT

Louisiana

ND/SD/MT

TX/NM

GOM

3

What Changes at Lower Crude Prices? Current Landscape

Source: Platts.

4

Where Should My Crude Go…Now?

1 MM B/D

2 MM B/D

1.5 MM B/D

0.5 MM B/D

0.5 MM B/D

Current Landscape

“BALLPARK” PRODUCTION BY AREA ILLUSTRATES RELATIVE TAKEAWAY VOLUMES

5

WTI Price Below Most Reported Shale Breakeven Points

Marginal Production Economics of Major U.S. Shale Plays, WTI Basis

Current Landscape

Note: Some companies report estimates for subplays, such as “Uinta-Green River,” “Uinta-Vertical,” and “Uinta-Horizontal.” For this analysis, those estimates have been grouped together in the major play. *2015 – January through May 1, 2015. Sources: Banking analyst reports and EIA.

0 20 40 60 80 100 120

Robert W. Baird Morgan Stanley US Investment Goldman Sachs Credit Suisse Average

Bakken

Eagle Ford

Permian – Delaware

Permian – Wolfcamp

Marcellus/Utica

Uinta

Niobrara

Texas Panhandle

Mississippi Lime

$/Bbl.

Major Shale Plays May 1, 2015 -

$59.10

WTI Average Prices 2014 - $93.20 2013 - $97.90

2015* - $50.12

6

Notional Shale Breakeven Points

Comments from Industry:

• Jim Volker, CEO of Whiting Petroleum, said that Whiting would increase production around $70 per barrel (/Bbl.)1

• “In a $50-$60 price environment, it will be flat, but at $70, it will continue to grow...”2 Scott Sheffeld, CEO of Pioneer Natural Resources

• $70 a barrel for U.S. oil “turns it on for us” Harold Hamm, CEO of Continental Resources, Inc.3

(1) Wall Street Journal, “Shale Oil Drillers Ready to Ramp Up,” May 14, 2015.

(2) Oil and Gas Investor, “Permian Perseveres,” May 2015.

(3) Wall Street Journal, “Shale Oil Drillers Ready to Ramp Up,” May 14, 2015.

Current Landscape

7

Which Price to Use for Production Breakeven? Current Landscape

50

55

60

65

70

75

80

Do

llars

Pe

r B

arre

l

WTI Futures Prices

February 4, 2015

April 4, 2015

May 15, 2015

Source: Barchart.com.

8

U.S. Crude Oil Production Expectations

Source: EIA – Annual Energy Outlook 2015 with Projections to 2040, April 2015.

Current Landscape

9

U.S. Crude Oil Production Expectations

Source: EIA – Annual Energy Outlook 2015 with Projections to 2040, April 2015.

Current Landscape

Focus time frame

10

Crude Oil Production Expectations

Source: EIA. Incremental production is calculated using EIA‘s forecast for lower 48 onshore crude oil production minus Q4 2013 actual production.

Current Landscape

11

Displacement of U.S. Crude Oil Imports

Source: EIA.

Industry Reaction

Canadian Pipeline

Lower 48 Waterborne

12

Medium Crude Import Sources

Note: Q1 2015 contains only January and February data. Source: EIA and Baker & O’Brien analysis.

Industry Reaction

13

Industry Responses: Higher Runs, Displacement of Imports and Exports

Displacement of Imports

Crude Oil Exports Increased then

Stalled

Increased Crude Runs

Source: EIA.

Industry Reaction

13,000

14,000

15,000

16,000

17,000

1-Jan-2010 1-Jan-2011 1-Jan-2012 1-Jan-2013 1-Jan-2014 1-Jan-2015

U.S

. C

rud

e R

un

s

MB

/D

6,500

7,500

8,500

9,500

10,500

11,500


U.S

. C

rud

e

Imp

ort

s M

B/D

0

200

400

600

Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15

U.S

. C

rud

e

Exp

ort

s M

B/D

14

Additional Effects Include Rail/Pipe Logistics, Product Exports, and Capacity Expansions

Expansions in Domestic

Refining Capacity

New Investments in Logistics

Infrastructure

Expansion of Product Exports

Source: EIA

Source: Baker & O’Brien Analysis

Industry Reaction

1,000

2,000

3,000

4,000

5,000


U.S

. P

rod

uct

Exp

ort

s M

B/D

Source: EIA.

15

• The refining industry is implementing measures to increase LTO absorption:

1. Higher unit utilizations

2. Direct substitution of LTO for existing feedstocks

3. Blending of LTO with imported medium and heavy grades

4. Investments in light ends overhead and downstream processing

5. Capacity growth: grassroots crude and condensate units

• Can U.S. refiners technically process all the available domestic crude oil through a combination of the above mechanisms?

What is the Industry Doing? Industry Reaction

16

The Key LTO Processing Constraint: Light Ends Handling

• Refineries designed to process medium and/or heavy crude oils often cannot handle the naphtha and lighter material (<350°F) contained in LTO.

7% 8% 10% 20%

33% 37% 42% 16%

23% 24%

27%

31% 35%

37%

34%

34% 34%

30%

22% 18%

19%

44% 36% 33%

23% 14% 10%

3%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Eagle Ford Bakken WTI Avg. MediumImport

Avg. HeavyImport

Railbit Rawbit

Crude Oil Distillation Yields

<350 F

350-650 F

650-1000 F

1000 F+

Vo

lum

e %

Current Landscape

Source: PRISMTM

17

Typical Light Crude/Condensate Handling Constraints for Existing Refineries

STILL GAS TO SATURATED GAS PLANT

Crude vaporization capacity

Saturated gas plant capacity

Light product cooling and hydraulics

Crude column diameter

Overhead hydraulics and cooling

Naphtha treating and processing

Preheat train configuration

Source: Petroleum Fractionation Overview, University of Oklahoma, and Baker & O’Brien.

• Physical constraints to processing LTO vary by refinery, but are generally centered around crude oil distillation and light ends handling.

*Note: “PA” = pumparound circuit

Current Landscape

18

• Direct substitution of medium crude with LTO:

– Refiners would generally need to sacrifice some throughput in order to substitute light for medium crude oil without some additional investment.

Options for Replacing Medium Crude Oil with LTO

• LTO/heavy blends can substitute for some medium grade imports:

– Advantages: Enables refiners to maintain crude throughput and keep downstream units full.

– Challenges:

Blending exact substitute for medium grades

Asphaltene precipitation issues

Crude oil blending facilities

Availability of heavy crude oil

Possible high acid (TAN) constraints

Analysis Methodology

19

Options for Replacing Medium Crude Oil with LTO

33%

8%

23% 20%

31%

22%

27% 27%

22%

34%

27% 30%

14%

36%

23% 23%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Avg HeavyImport

LTO 41% LTO, 59%Heavy

Avg MediumImport

Distillation Yields, Vol.%

<350 F

350-650 F

650-1000 F

1000 F+

Blend


20

• Case Study: A 100,000 B/D refiner of imported medium crude oil, constrained by the volume of naphtha and lighter material that can be processed

• As the proportion of LTO in a substitute LTO/Heavy blend increases above 40%, crude throughput declines and feedstock available for downstream conversion units declines

• Unit turndown constraints become a factor when downstream feedstock (VGO and heavier) falls to <70% of downstream capacity, suggesting 65% maximum LTO in the blend

– Conversion units might be partially filled with atmospheric tower bottoms available from new condensate splitters

Case Study: Replacing Medium Crude with LTO/Heavy Blend

0

10

20

30

40

50

60

70

80

90

100

40% 50% 60% 70% 80% 90%

MB

/D

% LTO

Naphtha and Lighter

Distillates

VGO and Heavier

Constant Light Ends Constraint

Turndown Constraint


21

• To incentivize expansions, modest discounts of LTO vs. imported grades needed

• These discounts are on par with expected LLS-Brent differentials going forward

Required LTO Price Discounts

0

1

2

3

4

5

6

7

8

9

10

Mega Project:Low Estimate

20% Expansion 10% Debottleneck Mega Project:High Estimate

10% Exp, inclnaphtha HDS/Ref

Economics

3-yr. payback 5-yr. payback

LTO Crude Oil Discount Required for Various Project Types, $/Bbl.

Notes: (1) Includes effect of lost profit during unit outages. (2) Top of bars represent a 33% investment recovery per year or about a three-year payback. (3) Bottom of bars represent a 20% investment recovery per year or five-year payback.

22

New Issues Quality Issues

• Increased production of LTO and Condensate

– Price discounts have motivated the U.S. refining industry to modify equipment, although significant investments and time are needed

– Increased exports of processed condensate that incur global freight costs

– Increasing sales and exports of light products

• Quality Arbitrage

– Shipped crude is being “spiked” with light ends or condensate on common carrier pipelines

Meets pipeline specifications, but composition is different than typical WTI crudes

– If you have crude with light ends greater than average – you are benefitting

– If you have vapor pressure “giveaway,” you may be subsidizing others

23

Impact of Increased LTO Production on Delivered WTI Quality

Quality Issues

• Current NYMEX Contract Specifications

– Deliverable domestic crude streams include the following:

WTI, Low Sweet Mix (Scurry Snider), New Mexican Sweet, North Texas Sweet, Oklahoma Sweet, and South Texas Sweet

Blends of the above streams are deliverable, if they meet quality specifications

Condensates are excluded from the contract definition of crude petroleum

– Light Sweet Crude Oil futures states specifications as:

Sulfur: < 0.42% by weight

Gravity: > 37 to < 42 degrees API

Viscosity: 60 SUS Max

BS&W: < 1%

Pour Point: < 50F

RVP: < 9.5 psi

Source: NYMEX Rulebook – Chapter 200: Light Sweet Crude Oil Futures.

24


Quality Issues

• Current NYMEX Contract Specifications

– Deliverable domestic crude streams include the following:

WTI, Low Sweet Mix (Scurry Snider), New Mexican Sweet, North Texas Sweet, Oklahoma Sweet, and South Texas Sweet

Blends of the above streams are deliverable, if they meet quality specifications

Condensates are excluded from the contract definition of crude petroleum

– Light Sweet Crude Oil futures states specifications as:

Sulfur: < 0.42% by weight

Gravity: > 37 to < 42 degrees API

Viscosity: 60 SUS Max

BS&W: < 1%

Pour Point: < 50F

RVP: < 9.5 psi

Source: NYMEX Rulebook – Chapter 200: Light Sweet Crude Oil Futures. Note: *True Vapor Pressure.

Some shippers allow 11 psi TVP*

25


Quality Issues

• The Crude Oil Quality Association (COQA) has recommended additional specifications to WTI:

– Micro Carbon Residue: 2.40 Wt.% or less

– Total Acid Number: 0.28 mg KOH/g or less

– Metals

Nickel: 8 ppm or less

Vanadium: 15 ppm or less

– High Temperature Simulated Distillation

Light Ends (< 220F): 19 Wt.% maximum

50% point: between 470F and 570F

Vacuum Resid (>1,020F): 16 Wt.% maximum

• Adoption is still pending

• Not a market-based solution

Source: Crude Oil Quality Association – “What is the Quality of WTI/Domestic Sweet?”

26


Quality Issues

• Light Straight Run (LSR) and condensate can be blended with WTI and still meet the pipeline specifications

• However, the Resulting Composition can Differ Significantly from typical WTI

– The amount of Light Straight Run is substantially higher

• A “Dumbbell” Curve

Source: PRISM, COQA, and Baker & O’Brien Analysis.

27

The Opportunity of Light Ends Quality Issues

Refiners are discounting LTO due to higher contents of Light Ends and LSR, which are composed of:

1. Propane (C3)

Inventory levels are high, but can be exported or burned as fuel (low value)

2. Butane (C4)

Butanes are blended in gasoline

Butane can be converted to alkylate (limited demand)

Excess summer butane is stored in caverns in Utah, Conway, and Mont Belvieu

3. Light Straight Run - (C5-C6)

LSR is blended into gasoline

LSR can be shipped to Canada for diluent blending purposes

Highest value of LSR is usually olefins cracker feed – although limited demand

28


Relative Economic Value of Condensate Splitter Intermediate Products

(Jan – Apr 2015 Average)

Lower Relative Values

SOURCE: Baker & O’Brien Analysis and Platts.

29



30



31


Quality Issues

Both of these qualities meet pipeline specs

Source: PRISM, COQA, and Baker & O’Brien Analysis.

32

TAPS – A Crude Oil Quality Bank Model Quality Issues

• Trans-Alaska Pipeline System (TAPS) carries blended crudes from the Alaska North Slope (ANS) to the Port of Valdez

• NGLs are also injected into TAPS at the North Slope

• Simple refineries process ANS crude from TAPS and return light and heavy fractions to the pipeline creating a “Dumbbell” Crude

Valdez Port of Valdez

Alaska North Slope

33

• TAPS Quality Bank is a “zero sum game”

– Total receipts are equal to total payments

• Shipper of Crude A receives ANS crude oil and $ in Valdez equal to the amount of Crude A it puts into TAPS:

– Receives from Quality Bank: $(95.00 – 92.62)/Bbl. = $2.38/Bbl.

– Similar situation for producers of Crudes B, C, D, and E

TAPS – A Crude Oil Quality Bank Model Quality Issues

Crude A, $95/Bbl

Crude B, $97/Bbl

Crude C, $100/Bbl

Crude D, $102/Bbl

Crude E, $92/Bbl

ANS Loaded in Ships for Various West Coast

Markets

North Slope Pump Station 1

$92.62/Bbl TAPS

NGLS, $60/Bbl

Light Products for Alaska

Port of Valdez

Alaskan Refinery

34

• Stream qualities (distillation yields) are measured periodically through sampling and testing, and are averaged over a month

– Measurement of volume and composition

• Transparent and logical valuation methodology

• Published spot market prices

Mid-Continent Crudes Valuation Methodology Quality Issues

Blended WTI $97.20/Bbl Crude A, $95/Bbl

Crude B, $97/Bbl

Crude C, $100/Bbl

Crude D, $102/Bbl

Crude E, $92/Bbl

NGLS?

Pipeline to Gulf Refineries

Gathering Point Destination Terminal

35

• At sub-$70/Bbl. prices, U.S. crude oil production growth is stalling.

• Logistics infrastructure (pipelines/rail) will operate with spare capacity giving producers choices of where to send their crude.

• Refiners and others have been modifying equipment to handle increased volumes of shale crude given committed production with built-in price discounts or fees. Latecomers will be left as price-takers.

• Light ends content is constraining U.S. infrastructure. Quality arbitrage is profiting certain volume aggregators but few producers.

• Certain pipeline routes are candidates for quality bank pooling. This could create a market mechanism to dispose of light ends.

Summary

36

Baker & O’Brien – Independent Energy Consultants

www.bakerobrien.com

Dallas

12001 N. Central Expressway Suite 1200

Dallas, TX 75243 Phone: 1-214-368-7626

Fax: 1-214-368-0190

Houston

1333 West Loop South Suite 1350

Houston, TX 77027 Phone: 1-832-358-1453

Fax: 1-832-358-1498

London

146 Fleet Street Suite 2

London EC4A 2BU Phone: 44-20-7373-0925

where should my crude go….now? - baker & o'brien should my crud… · 1 •last year’s...

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