CATCH ME IF YOU CAN · 5 Catch Me If You Can © 2018 Drillinginfo, Inc. All rights reserved. All...

© 2018 Drillinginfo, Inc. All rights reserved. All brand names and trademarks are the properties of their respective companies.

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CATCH ME IF YOU CAN

FundamentalEdge Report | March 2018


Contents

INTRODUCTION AND KEY TAKEAWAYS 03

CRUDE OIL 04

U.S. Becomes Largest Global Producer 05

The Need to Export 16

Global Demand: Don’t Count On It 19

NATURAL GAS 21

Dry Gas Production: Strong Growth Despite Weak Prices 24

Winter 2017-18 Review 26

U.S. Demand: Domestic and Exports 28

NGLs 35

Oversupply Persists 37

Ethane Update 39

Oil & Gas Price Forecast 43

4Q2017 Earnings Calls Summaries 46


Introduction and Key Takeaways

▪ Abundance has brought a new game. The U.S. is now the leading producer of natural gas AND oil/petroleum products. The country continues to produce higher volumes despite weak prices.

▪ The U.S. out-produces domestic demand for oil and natural gas at about $55-$60 crude oil and $2.65-$2.75 natural gas. Therefore, exports of both commodities will be crucial to balance the markets.

▪ Exploration and production costs will rise over the next few years, but technological and management innovation will help to offset the increases. The U.S. will not abandon its position as the low cost marginal supplier.

▪ For NGLs, expected production growth continues to come from the Permian due to the superior economics along with proximity to market. The recent weakness in prices has been due to the lack of infrastructure, but moving forward slight gains are expected as crackers come online to support additional ethane recovery.

▪ The industry keeps finding new apparently prolific gas fields – Mancos Alpine High and the Austin Chalk, for example. As they develop, they hold the prospect of disrupting gas flows across the country and placing significant stress on existing infrastructure.

▪ Drillinginfo continues to expect the long term price equilibrium to be $60/Bbl for crude and $2.65/MMBtu for natural gas.

CRUDE OIL

Catch Me If You Can | FundamentalEdge Report | March 2018

Catch Me If You Can © 2018 Drillinginfo, Inc. All rights reserved. All brand names and trademarks are the properties of their respective companies. 5

US On Track To Become Largest Producer of Crude Oil

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

Cru

de

Oil

Pro

du

ctio

n (

MB

bl/

d)

Saudi Arabia Russia US

Global Crude Oil Production

CHART 1US production has surpassed Saudi Arabia to become the second largest producer of crude oil in the world. The rapid growth in production over the last several years comes on the back of great shale production economics.

The US continues to grow production and will likely surpass Russia to become the #1 producer of crude oil in the world by the end of 2018.

As US production grows, every incremental barrel will be exported, pushing out a previously foreign supplied barrel. US market share will continue to grow.

The combination of current price levels and low breakeven economics of US shale production will ensure that, by the end of the year, the US will be looking back at Saudi Arabia, Russia, and all other crude oil producing countries saying “Catch Me If You Can.”


$60/Bbl? What Happened? Is It Sustainable?

$60/Bbl? What Happened? Is It Sustainable?

CHART 2Crude oil prices have been on the up-and-up since July 2017. The upward trend started with the anticipation leading up to the OPEC 173rd

meeting at the end of November 2017. Analysts started building into their forecasts an extension of OPEC quotas through 2018, awakening the bulls.

The 173rd OPEC meeting concluded with even better news than expected. In addition to the extension of the quotas, Nigeria & Libya (previously exempt from quotas) also agreed to limit output to maximum 2017 levels. This further fueled the bullish flames, driving WTI prices up above the $60/Bbl level in December 2017.

All the warnings from agencies like the EIA and IEA regarding prevailing fundamentals around supply, demand, & inventories were counteracted by bullish news pieces regarding unrest in the Middle East, Saudi strategy, various short lived supply outages, and an unrelenting speculative hunger.

The chart shows the increasing WTI price over time and the corresponding increase in managed money (speculative) long positions over the same time period. The speculative long positions are at levels last seen before prices retreated to the high $40/Bbl level in early March 2017 following the bursting of the speculative bubble of early 2017.

Is another eventual end to the speculatively induced price run on the cards this time around or are these price levels sustainable?

12%

13%

14%

15%

16%

17%

18%

19%

20%

21%

22%

40

45

50

55

60

65

70

1/1

7

2/1

7

3/1

7

4/1

7

5/1

7

6/1

7

7/1

7

8/1

7

9/1

7

10

/17

11

/17

12

/17

1/1

8

2/1

8

3/1

8

Managed M

oney L

ong P

ositio

ns (%

Open In

tere

st)

WT

I ($

/Bb

l)

WTI Price Managed Money Long Positions [RHS]

Source: EIA Weekly Cushing, OK Crude Oil Future Contract 1, CFTC


Global Supply/Demand: Balanced, But No Deficit

Global Supply/Demand: Balanced, But No Deficit

CHART 3Although the oversupply situation has been reversed since 2Q2017, the current implied deficit is only 30 MBbl/d. The deficit has been getting smaller every quarter as US growth continues to eat into the ambitions of OPEC to correct the global inventories to levels from prior to the price crash.

The oversupply situation that lasted from 2Q2014 to 1Q2017 led global crude oil and petroleum product inventories to very high levels. The expectation was that the OPEC and non-OPEC quotas that would take ~1.6 MMBbl/d off the market would reverse the deficit and quickly correct the high inventory levels.

The higher prices that materialized due to the expectation of the deficit and efficiency gains from optimized completions and lower service costs led to ~1 MMBbl/d of growth in production from the US in 2017, cutting into the deficit.

Growth from Nigeria and Libya (who were exempt from quotas) also undermined OPEC’s efforts to keep production low. The ~1.2 MMBbl/d of cuts promised by the OPEC-12 were approximately halved due to their growth.

Source: IEA

0.5

20.5

41.2

81.5

21.7

90.9

7 1.6

41.2

50.3

50.1

71.3

60.0

6-1

.08 -0

.46

-0.3

6-0

.03

-4

-3

-2

-1

0

1

2

3

4

5

6

78

80

82

84

86

88

90

92

94

96

98

100

102

1Q

2010

1Q

2011

1Q

2012

1Q

2013

1Q

2014

1Q

2015

1Q

2016

1Q

2017

1Q

2018

Supply/D

em

and Im

bala

nce (M

MB

bl/d

)

Cru

de O

il &

Petr

ole

um

Pro

ducts

(M

MB

bl/d

)

Supply/Demand Imbalance (RHS) Demand Supply IEA Demand Forecast

Start of persistent oversupply. Deficit resurfaces.

Peak oversupply.

Supply outages.

Q1

Current Implied Deficit


OPEC Quotas: Compliance & Motive

OPEC Quotas: Compliance & Motive

CHART 4

OPEC has had a great track record with compliance during this period of quotas. Initially, high compliance rates were driven by Saudi Arabia’s willingness to subsidize early overproduction by other quota carrying countries. Saudi Arabia has since continued to lead the way for compliance as they prepare for the IPO of Saudi Aramco. The high compliance is translating to higher prices, which they want to persist for several months prior to the IPO.

Recent boom in compliance rates to ~150% has been driven by the rapid decline of Venezuelan production. The situation on the ground in Venezuela means that this decline is likely to persist, and this has really awakened the bulls who are buoyed by the more than 420 MBbl/d that Venezuela is producing below quota.

Sources: IEA, OPEC (Secondary Sources)Compliance (%) = (1,176 + Cuts) / 1,176 MBbl/d

MemberQuota

(MBbl/d)Feb 2017 (IEA)

(MBbl/d)Feb 2017 (OPEC)

(MBbl/d)Feb Cuts (IEA)

(MBbl/d)Feb Cuts (OPEC)

(MBbl/d)

Saudi Arabia 10,058 9,980 9,982 +78 +76

Iraq 4,351 4,480 4,425 -129 -74

UAE 2,874 2,800 2,827 +74 +47

Kuwait 2,707 2,700 2,702 +7 +5

Venezuela 1,972 1,550 1,548 +422 +424

Angola 1,673 1,570 1,613 +103 +60

Algeria 1,039 1,040 1,031 -1 +8

Qatar 618 600 602 +18 +16

Ecuador 522 510 520 +12 +2

Gabon 193 200 191 -7 +2

Iran 3,797 3,820 3,813 -23 -16

Eq. Guinea 128 130 130 -2 -2

OPEC-12 29,932 29,380 29,384 +552 +548

97%

84%

95%86%

92%

77% 75%

87% 91%

105%

115%

134% 138%147%

99% 97%

108%101%

107%

82% 86%

96% 93%

103%

129%135% 137%

147%

60%

70%

80%

90%

100%

110%

120%

130%

140%

150%

Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18

Com

plia

nce (

%)

IEA OPEC (Secondary Sources)


OPEC Key Players: Nigeria, Libya, & Venezuela

OPEC Key Players: Nigeria, Libya, & Venezuela

CHART 5Nigeria and Libya increased production in 2017, undermining the OPEC cuts. Nigeria and Libya grew production ~650 MBbl/d in 2017, cutting into the promised 1.2 MMBbl/d of quotas set by the quota carrying OPEC-12. This led to a somewhat muted supply deficit than was expected.

With the most recent OPEC 173rd meeting, there was an agreement that Nigeria and Libya would not produce higher than their peak rates in 2017 (1.8 MMBbl/d and 1.0 MMBbl/d respectively). This was the most bullish piece of news to come out of the meeting, as it was somewhat unexpected. The extension of the quotas through 2018 was largely factored in by the market in mid-2017.

Venezuela’s production decline has been rapid given the conditions on the ground. Venezuela was producing just above 2.0 MMBbl/d in January 2017, but has declined more than 450 MBbl/d to a low of 1.55 MMBbl/d in February 2018. The decline shows no signs of stopping and the bulls point to this decline as one of the key reasons behind the recently higher price levels that have materialized.

Source: OPEC (Secondary Sources)

27.8

6

27.7

9

27.8

4

2.0

1

1.5

5

1.4

6 1.8

0

0.551.01

1.02

25

26

27

28

29

30

31

32

33

34

Jan-1

7

Feb

-17

Ma

r-1

7

Apr-

17

Ma

y-1

7

Jun-1

7

Jul-1

7

Aug-1

7

Sep-1

7

Oct-

17

No

v-1

7

De

c-1

7

Jan-1

8

Feb

-18

OP

EC

-12 &

OP

EC

Cru

de O

il P

roduction (

MM

Bbl/d

)

Rest of OPEC Venezuela Nigeria Libya


Non-OPEC Quotas: Inconsequential to OPEC (So Far)

Non-OPEC Quotas: Inconsequential to OPEC (So Far)

CHART 6Non-OPEC compliance has been dismal. Kazakhstan in particular has been outproducing quota. Most recently, Kazakhstan was more than 220 MBbl/d above quota.

In the initial Algiers Accord, the non-OPEC participation was seen as an absolute necessity for the success of the OPEC quotas. Although the non-OPEC quota compliance has been poor, OPEC has largely ignored this non-compliance.

Saudi Arabia in particular has downplayed the low non-OPEC compliance levels as their main focus remains the Saudi Aramco IPO. Compliance by OPEC is still closely tracked by the market, but the non-OPEC quotas are largely ignored now with the exception of Russian production levels.

Russia is the largest contributor to the non-OPEC cuts and many had anticipated that they would cheat on the quotas when prices increase. The relationship between Saudi Arabia and Russia and their joint efforts to stabilize the oil market will be closely watched moving forward. Will the Russians start to take advantage of the higher prices and pump more crude oil (bearish) or will they continue to comply and risk market share (bullish)?

MemberQuota

(MBbl/d)Feb 2018(MBbl/d)

Feb Cuts(MBbl/d)

Russia 10,929 10,953 -24

Mexico 2,003 1,891 +112

Kazakhstan 1,668 1,890 -222

Oman 967 964 +3

Azerbaijan 779 806 -27

Malaysia 618 643 -25

Bahrain 187 209 -22

S. Sudan 96 131 -35

Brunei 121 92 +29

Sudan 72 67 +5

TOTAL 17,440 17,646 -206

Sources: IEACompliance (%) = (546 + Cuts) / 546 MBbl/d

37%

14%

46%

61% 62% 58% 58%

112%122%

96%

79%67%

59% 62%

0%

20%

40%

60%

80%

100%

120%

140%

Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18

Com

plia

nce (

%)


U.S. Economics: Low Cost Shale, Price Ceiling

US Economics: Low Cost Shale, Price Ceiling

CHART 7Whereas the OPEC quotas have been successful in keeping some supply off the market, US production has rebounded and reached all time highs. These production levels and continued growth are warranted by the great production economics seen across the US shale plays.

Although the Permian has gotten most of the media attention, at $65/Bbl, the sweetspots(and in some cases even tier 2 areas) of all major plays in the country are in the money. These great economics have been fueling the increased activity and growing production from the US.

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$0

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n (

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Source: DI ProdCast

Gulf Coast Permian Williston Anadarko Rockies


US Rig Count: Flattened Out

US Rig Count: Flattened Out

CHART 8The rig count has rebounded from the low of 433 active rigs back in May 2016 to the recent peak of more than 1,100 active rigs. The increase in the rig count has been driven by the great economics shown in the previous slide.

Of the rigs that have been added since the low, ~50% of those rigs have been added back into the Permian basin.

Source: DI Analytics

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

1/2

01

5

4/2

01

5

7/2

01

5

10

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15

1/2

01

6

4/2

01

6

7/2

01

6

10

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16

1/2

01

7

4/2

01

7

7/2

01

7

10

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17

1/2

01

8

Active R

igs

Other Permian Anadarko Gulf Coast Williston DJ

May 4th, 2016Low: 433 Rigs

March 25th, 2018Recent: 1,099 Rigs

March 17th, 2018Peak: 1,104 Rigs

Trough to Peak+671 Rigs


US DUC Count: Builds Leading to Service Cost Increases

US DUC Count: Builds Leading to Service Cost Increase

CHART 9

Source: DI AnalyticsHorizontal Wells Only

2

2

4

7

13

16

34

41

45

113

132

243

268

308

818

0 100 200 300 400 500 600 700 800 900

North Park

Arkoma

San Juan

Ft. Worth

Other

Piceance

Powder River

E. TX

Midcon

Anadarko

D-J

Gulf Coast

Williston

Appalachia

Permian

DUC Count

Total = 2,046Only includes horizontal wells spud but not completed > 6 months

With the increased rig count in the Permian, completions crews have had a hard time keeping up with the pace of drilling.

DUC wells that have been drilled but not completed for more than six months usually suffer from one of the following:

- Lack of infrastructure for gathering, processing, or takeaway.

- Poor well-level economics waiting for higher prices.

- Lack of completions crews to keep up with the pace of drilling.

Currently in the Permian, there are 818 DUC wells that have been drilled but not completed for more than six months. These wells have great economics and the infrastructure is still able to support the additional volumes that would be brought online from these wells. However, the completions crews are currently not able to keep up with the pace of drilling.

More completions crews are necessary and this is the reason why most operators are expecting 10%-20% increase in D&C costs moving forward.


US Production Economics: Impact of Service Costs

US Production Economics: Impact of Service Costs

CHART 10

Source: DI ProdCast

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$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

WT

I B

reakeve

n (

$/B

bl) @

$2.7

5/M

MB

tu H

H &

12.5

% M

AR

R

+20% D&C Cost +10% D&C Cost Current D&C Costs

A higher D&C cost will definitely have an impact on the economics of US production areas. However, these higher costs will not be the difference between a $60/Bbl price level and $100/Bbl prices.

An increase of 10%-20% in D&C costs equates to an average of $4-$8/Bbl higher breakevensacross the country. Particularly in areas with great economics like the Permian, these higher breakevens will bring down the NPV per well, but it will not move any of these areas out of the money.

The higher D&C costs will be important for the areas that are on the fringe of being economic. The higher D&C costs, although fueled by the tightness of completion crew availability in the Permian, will permeate through all other plays as well.


US Production: Growth to Continue

Source: DI ProdCast

0

2

4

6

8

10

12

14

16

20

14

20

15

20

16

20

17

20

18

20

19

20

20

20

21

20

22

20

23

Cru

de O

il P

roduction (

MM

Bbl/d

) @

12.5

% M

AR

R

Other Permian Anadarko Eagle Ford Williston DJ

Δ Dec to Dec (MMBbl/d) →Δ YoY (MMBbl/d) →

+1.18+1.35

+1.09+1.07

+0.71+0.91

+0.53+0.60

+0.42+0.47

+0.31+0.37

Year WTI ($/Bbl) HH ($/MMBtu)

2018 $60 $2.75

2019 $60 $2.75

2020 $60 $2.75

2021+ $60 $2.65

US Production: Growth to Continue

CHART 11US production is set to grow 1.18 MMBbl/d exit-to-exit in 2018. The production growth will be fueled by the growth in the Permian.

All major shale basins will post growth this year under the Drillinginfo price forecast. Moving forward, the production will continue to grow, albeit at a slower pace.

The risk to this forecast is mainly to the high side.

- Efficiency gains are likely to offset any cost increases and drive faster production growth into the future.

- Should higher prices continue to prevail, operators are likely to hedge additional volumes and bring more rigs online.

The downside risk is due to infrastructure:

- If the Permian production outpaces takeaway capacity, there may be a slower growth profile from the area.


US Production: Expect Exports

Source: DI Market Intelligence

1.35

3.33

5.19

1.42

3.11

4.59

0

1

2

3

4

5

6

2018 2020 2025

Pro

duction G

row

th/E

xport

s (

MM

Bbl/d

)

Production Growth (vs. Avg. 2017) Avg. Exports

US Production: Expect Exports

CHART 12As US production continues to grow, the additional volumes will be headed abroad. Almost all incremental volume growth will be exported.

This is due to the fact that the lighter crude oil that the US produces is a better fit in global refineries. The US will send the light crudes out while continuing to import heavier crudes that are an ideal fit for the US’s extremely complex refining infrastructure.

All of these exports will continue to take more market share from other crude oil exporting countries including Saudi Arabia and Russia.

In order to facilitate these exports, there needs to be additional infrastructure buildout on the Gulf Coast over the next several years.


US Production: Efficiency Gains Marked

One of the main reasons behind the great economics in the US is the efficiency gains that have been realized through longer laterals, optimized completions, and the move to industrial style exploitation of shale plays.

The Permian and Anadarko have led the way in terms of production gains per well. These efficiency gains will continue offset some of the impact from increasing service costs and drive production forward at an even faster pace.

US Production: Efficiency Gains Marked

CHART 13

Source: DIHorizontal wells only.

0

100

200

300

400

500

600

700

0 12 24 36 48 60 72

Cru

de O

il P

roductio

n (

Bbl/d)

Months on Production

Permian

2011

2012

2013

2014

2015

2016

2017

0

50

100

150

200

250

300

350

0 12 24 36 48 60 72

Cru

de O

il P

roductio

n (

Bbl/d)

Months on Production

Anadarko

2011

2012

2013

2014

2015

2016

2017


US Production: Efficiency Gains Offset Cost Increases

Source: DI ProdCast

8

9

10

11

12

13

14

15

20

14

20

15

20

16

20

17

20

18

20

19

20

20

20

21

20

22

20

23

Cru

de O

il P

roduction (

MM

Bbl/d)

+10% Service Costs

+20% Service Costs

+20% Service Costs & +10% IP Rate

Current DI Forecast

US Production: Efficiency Gains Offset Cost Increases, Fuel Growth

CHART 14Even should cost increases occur, efficiency gains are likely to more than offset the impact on production.

Even with a 20% increase in service costs, a modest 10% increase in IP rates would lead to a faster production growth rate than that projected in the Drillinginfo base case.

These efficiency gains are likely to materialize in the form of transferred learnings between operators and basins.


Global Demand: Don’t Count On It

Source: IEA

-0.4

2

0.9

8

0.7

6

0.6

8

96.82

98.43

100.42

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

88

90

92

94

96

98

100

102

1Q

2014

2Q

2014

3Q

2014

4Q

2014

1Q

2015

2Q

2015

3Q

2015

4Q

2015

1Q

2016

2Q

2016

3Q

2016

4Q

2016

1Q

2017

2Q

2017

3Q

2017

4Q

2017

1Q

2018

2Q

2018

3Q

2018

4Q

2018

ΔQ

0Q

(MM

Bbl/d

)

Cru

de O

il &

Petr

ole

um

Pro

duct

Dem

and (

MM

Bbl/d

)

Δ QoQ Demand

4Q2017-4Q2018+1.99 MMBbl/d

4Q2016-4Q2017+1.60 MMBbl/d

Global Demand: Don’t Count On ItCHART 15The other side of the fundamental equation is

demand. Last year, demand growth was 1.60 MMBbl/d according to the IEA. The expectation for 2018 is a growth of 1.99 MMBbl/d.

Forecasting of demand growth is particularly difficult and the expectation for demand has historically started high and continued to be revised down throughout the year.

Given the fact that global economies are suffering from geopolitical tensions and face possible sanctions and trade wars, the expectation of 1.99 MMBbl/d of demand growth is ambitious.

Additionally, the demand that materialized from the implementation of strategic reserves in China and India for the last couple of years has ceased. These strategic reserves were the main culprit behind a artificially inflated demand realization in recent years.


OECD Stocks: What Normalization?

Source: IEA, DI

2,500

2,600

2,700

2,800

2,900

3,000

3,100

3,200

JA

N

FE

B

MA

R

AP

R

MA

Y

JU

N

JU

L

AU

G

SE

P

OC

T

NO

V

DE

C

OE

CD

Sto

cks (

MM

Bbl)

Max/Min 2010-2014 2015 2016 2017 2018E 2018E Low Demand

ASSUMPTIONSUS Growth IEA Estimate

Non-OPEC, Non-US Production FlatOPEC Current Production Levels

IEA Quarterly Demand Estimates & Low Demand 400 MBbl/d Lower Than IEA Estimate

OECD Stocks: What Normalization?

CHART 16The OECD stocks must be normalized before there can be a sustained $60/Bbl price level. Given US growth expectations, flat non-OPEC & non-US production, and OPEC staying flat at current production levels the inventories will return to the five year average from prior to the price crash by late summer 2018. Even should demand come in 400 MBbl/d lower than IEA’s expectations, the inventory levels are expected to normalized late in the 2018.

There are a few things that could change the trajectory of the global inventory declines:

- Higher prices too fast could fuel further growth in US production, undermining the OPEC quota extension.

- Poor demand realization could lead to smaller deficits than anticipated, slowing down the pace of inventory normalizations.

- Production growth in any shape or form would hurt fundamentals (Venezuelan recovery, OPEC quota deterioration, Russian market share ambitions, etc.).

Even should inventory levels normalize this year, when quotas are no longer in place, OPEC will be able to bring a sizeable piece of ~1.2 MMBbl/d back online in 2019, The US will also continue to grow more than 1.0 MMBbl/d at current price levels. This is more than the expected demand growth in 2019, meaning that prices can’t get much higher than current price levels.

Additionally, should prices persist at these levels, there will be additional non-US and non-OPEC projects that become viable.

NATURAL GAS


© 2018 Drillinginfo, Inc. All rights reserved. All brand names and trademarks are the properties of their respective companies. 22 Catch Me If You Can

Key Takeaways – Short Term Dynamics

Short Term Dynamics:

• In 2017 dry gas production returned to growth mode after 2016 posted the first annual decline in 10 years. Dec17 production was 6.7 Bcf/d higher than Dec16, and has already added an incremental 1.4 Bcf/d in 1Q2018.

• Marcellus and Utica led the way in 2017 at +4 Bcf/d, aided by pipeline capacity additions in this region.

• Permian (+1.4 Bcf/d) and Haynesville (+1.5 Bcf/d) also contributed significantly to the total U.S. gain.

• By year end 2018, DI expects production to be 5.9 Bcf/d higher than year end 2017. The same basins contribute to this growth.

• On the demand side, we witnessed closer to normal levels in Winter 17-18 in aggregate. This was stronger than Winter 16-17 but not nearly as high as the polar vortex levels seen in 2014.

• 1Q2018 also saw the first export cargo from Dominion’s Cove Point terminal making it the second operating U.S. export facility.

• Storage inventories will exit withdrawal season (end of Mar18) at a lower-than-average 1.35 Tcf.

• This compares to a 5-year average of 1.7 Tcf and 2017 level of 2.1 Tcf.

• Prices averaged $3.11 per MMBtu in 2017 and $2.97 during the Winter 2017-18.

• Drillinginfo expects gas prices to average $2.75 per MMBtu in 2018.

• This compares to $2.87 per MMBtu indicated by daily settlements for Jan-Mar combined with current forward prices for April-Dec.

• Rapid production growth this summer will be partially offset by increased exports (via LNG and Mexico) as well as increased power burn (due to lower prices and coal retirements, particularly in Texas).

• Thus despite starting at a lower-than-average 1.4 Tcf, DI expects storage inventories to reach a manageable level of 3.65 Tcf by end of Oct18.


Key Takeaways – Long Term Forecast

Long Term Forecast:

• Significant natural gas production growth is expected to continue over the next five years.

• Dry gas production will come primarily from the Marcellus/Utica and Haynesville basins, while associated gas will drive production growth in the Permian and Anadarko basins.

• The primary driver to support this production growth will be increased LNG exports.

• By 2022, the U.S. is expected to have 5 operational terminals and export and average of 8 Bcf/d of LNG.

• The long-term price equilibrium for natural gas is $2.65 per MMBtu under a $60 WTI.


Dry Gas Production: Strong Growth Despite Weak Prices

0

10

20

30

40

50

60

70

80

90

100

Bcf/d

Rest of US Anadarko Haynesville Permian Marcellus/Utica

US Dry Gas Production by BasinCHART 17Natural gas dry production in the U.S. is

expected to increase by 5.9 Bcfd in Dec18 compared to Dec17.

This growth is lead by the Marcellus and Utica regions, which is expected to contribute with 3 Bcf/d, followed by 1.0 Bcf/d from the Permian, 0.8 Bcf/d from the Anadarko and 0.6 Bcf//d from the Haynesville.

Longer term, Drillinginfo expects production to continue growing, but at a lower pace due to gas prices ranging between $2.75/MMBtu and $2.65 MMcf/d in the next five years.

Dry gas production is expected to reach almost 91.4 Bcf/d by the end of 2022.

Dec22 vs Dec17

+6.3

+3.6

+1.2

+2.9

+0.6

Source: DI ProdCast

Dec18 vs Dec17

+3.1

+1.0

+0.6

+0.8

+0.3


Northeast Bottleneck Relieved in Late 2018

Northeast Dry Gas Production and Takeaway CapacityCHART 18

-

5

10

15

20

25

30

35

Bcf/

d

Legacy (Other) PA-North WV Utica PA-West Capacity

Source: DI ProdCast, DI Analytics

Debottleneck Expected During 3Q2018

Project Name Pipeline Capacity (Bcf/d)

Status In-Service Source Destination

Leach Xpress Texas Eastern (TETCO) 1.50 In-Service 1/1/2018 OH, PA-West Leach, OH

Rover Phase II Energy Transfer (ET) 1.15 Under Construction 6/1/2018 MW Canada

Atlantic Sunrise Phase 1B Transco 0.45 Under Construction 7/1/2018 PA-North NJ/MD

Atlantic Sunrise Phase 2 Transco 0.50 FERC Certified 7/1/2018 PA-North AL

Atlantic Sunrise Phase 3 Transco 0.35 FERC Certified 9/1/2018 PA-North AL

Nexus Gas Transmission Nexus 1.50 Under Construction 11/1/2018 OH Canada

Gulf Xpress Columbia Gulf (CGT) 0.88 FERC Certified 11/1/2018 WV LA

TOTAL 6.33

Natural gas production growth in the Marcellus and Utica basins has been historically constrained by takeaway pipeline capacity. However, several key projects have come online in recent months, increasing capacity out of the Northeast, and allowing for a significant increase in production.

Northeast capacity constraints relaxed in the last two months of 2017 as 3.5 Bcf/d of takeaway capacity came online. Despite this, much produced gas stayed in the Northeast to meet local demand during the cold spell of winter 2017-18.

With the further addition of over 5.0 Bcf/d through 2018, DI expects the bottleneck out of the Northeast to be alleviated during the 3rd

quarter of the year as Rover Phase II and Atlantic Sunrise Phases 2 and 3 are placed in service.

With this additional takeaway capacity will come a significant increase of 3.7 Bcf/d (YoY) in Northeast natural gas production in 2018.

As more takeaway pipeline projects continue to come online and debottleneck the Northeast, producers will be able to sell more gas to higher priced markets causing the Northeast price basis to shrink toward the variable cost of transportation.


Winter Weather

CHART 19

Total Daily Heating Degree Days Year-on-Year Change (Nov17 – Feb18)

Sources: NOAA, DI Analysis

Although heating degree days this winter are similar to the 10-year average, they are significantly above last winter for most of the country, as illustrated in chart 19. The Midwest, Northeast, Southeast, and Midcontinent regions all saw colder weather this winter compared to last. This additional heating demand allowed the market to work through higher production volumes.


Storage Inventories- End of Summer Season Forecast

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500S

tora

ge

In

ven

tory

(B

cf)

5-yr Max/Min 2015-16

2016-17 Injections @ 5-yr Average Rate

Injections @ 2017 Rate 2017-18

Storage Inventories End-of-Summer Projections

CHART 20The withdrawal season (Nov-Mar) pushed inventories down to 1.35 Tcf.

Looking ahead, two projections are presented in the chart for working inventories on Nov. 1 (end of the summer).

1) If injections this summer are at the 5-year average, inventories will end at 3.5 Tcf.

2) If a summer similar to last year materializes, inventories will reach 3.1 Tcf.

DI expects gas storage inventories by November 1, 2018 to reach 3.65 Tcf, assuming normal weather. This level is higher than the two projections discussed above as production supports higher-than-average injections.

3.1 Tcf

3.5 Tcf

DrillingInfo ForecastNov 1, 2018 3.65 Tcf

April 1, 20181.35 Tcf


Natural Gas Demand: 5-Year Outlook

US Natural Gas Demand by SectorCHART 21US natural gas demand

continues to grow with 2022 demand expected to be 15.5 Bcf/d higher than 2017.

A lot of the 2018 growth over last year is expected to come from the power sector as significant amounts of coal retirements take place and low gas prices boost gas power generation.

Longer term, LNG export growth is expected to lead gains as 3 more terminals come online.

0

10

20

30

40

50

60

70

80

90

100

2015 2016 2017 2018 2019 2020 2021 2022

Bcf/

d

Rescom Ind Other (Fuel) Power LNG Exports MX Exports

2017-2215.5 Bcf/d

Sources: EIA, DI Analysis


ResCom Demand

The long-term trend over the past several years has been increasing ResCom gas demand per HDD. This likely has to do with population growth, economic activity, and an increasing amount of utility gas being used as heating fuel on the East Coast.

In 2017, this represented a 13% higher ResCom gas demand per HDD in Nov-Dec, compared to the same period in 2010.

US ResCom Demand per Heating Degree Day: Nov-Dec (MMcf/HDD)

CHART 22

2,600

2,700

2,800

2,900

3,000

3,100

3,200

3,300

2010 2011 2012 2013 2014 2015 2016 2017

Sources: EIA, NOAA, DI Analysis


Natural Gas Demand: Short Term Forecast

Domestic US Natural Gas Demand by SectorCHART 23Domestic natural gas demand

(Industrial, ResCom, and Power) is expected to average 71.4 Bcf/d this year. This forecast assumes $2.75 average Henry Hub settlement price this year, and 10-year average weather.

0

10

20

30

40

50

60

70

80

90

100

Industrial ResCom Power


Coal Plant Retirements and Fuel Switching

Texas: Electricity Generation by Retiring Coal PlantsCHART 25

Company announcements indicate that coal retirements will reach 12.8 GW this year while another 1.3 GW will permanently switch fuels. Over the 2019-’22 time frame, coal retirements and fuel switches are likely to surpass 15.7 GW, the sum of current announcements.

The historical net generation of retiring and fuel switching plants is illustrated in chart 24 by state. With average heat rates, it would take 1.1 Bcf/d to replace the 2017 net generation of these facilities with combined cycle natural gas. However with steam turbine gas plants, it would take 1.5 Bcf/d.

In Texas, approximately 5.4 GW of coal retirements are expected this year with 4.4 GW already taken offline. This magnitude of retirements is unprecedented in the state as less than 0.6 GW of coal-fired generation has retired there in the past decade due to low-cost local supply. This will leave Texas with 19 GW of operating coal-fired capacity and another 0.5 GW that is currently mothballed. The historical generation of the retiring plants is illustrated in chart 25. Using average heat rates, it would take 0.6 Bcf/d to replace the 2017 net generation of these facilities with combined cycle natural gas. However with steam turbine natural gas, it would take 0.8 Bcf/d.

Other states with significant amounts of coal-fired capacity going offline or switching fuels this year include Ohio (2.5 GW), Florida (2.3 GW), Oklahoma (1.1 GW), and Tennessee (1 GW).

0.0

0.2

0.4

0.6

0.8

1.0

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

CC

Gas E

quiv

ale

nt

(Bcf/

d)

Genera

tion (

GW

h)

Big Brown JT Deely Monticello Sandow

Electricity Generation From Retiring Coal Plants by StateCHART 24

0.0

0.5

1.0

1.5

2.0

01,0002,0003,0004,0005,0006,0007,0008,0009,000

CC

Gas E

quiv

ale

nt

(Bcf/

d)

Genera

tion (

GW

h)

Texas Ohio Florida Oklahoma Tennessee Indiana Minnesota New York Maryland Virginia

Sources: EIA, SNL, DI Analysis


Renewable Power Builds

Company announcements show strong growth of renewable power capacity during the next several years. If all announced plants are built on schedule, US wind capacity is expected to increase by 25% in 2018 and 82% by the end of 2022 compared to today’s operating capacity. Similarly, solar is expected to grow 19% this year and 83% by 2022.

For wind power, current announcements add up to 17.1 GW of new wind capacity in 2018, another 24.3 GW in 2019, and 26.1 GW in 2020 before dropping to 3.5 GW in 2021 and 3.7 GW in 2022. In comparison, 7.3 GW of wind was added in 2017 and 13.6 GW was added in 2012, the highest growth year on record.

For solar power, current announcements sum up to 8.0 GW in 2018 (0.8 GW already operating), 6.9 in 2019, and 6.5 in 2020 before dropping to 2.6 in 2021 and just 0.4 in 2022. In comparison, 5.2 GW was added in 2017 and 8.2 was added in 2016, the highest growth year on record.

Although not all announced plants may come online on time or at all, the growth in renewable generation is expected to be significant. With very low variable operating costs, wind and solar contribute power to the grid whenever the resource is available and without having to compete with dispatchable generation. These resources are likely to push out other baseload generation, including gas and coal. Chart 26 illustrates the expected renewable generation according to plant operating status. Charts 27 and 28 show where the plants are being built.

2018-’22 Wind Power BuildsCHART 27

2018-’22 Solar Power BuildsCHART 28

Source: SNL infrastructure, DI analysis

Wind and Solar Generation ForecastCHART 26

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

0

10,000

20,000

30,000

40,000

50,000

60,000

Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Jul-20 Jan-21 Jul-21 Jan-22 Jul-22

CC

Gas E

qu

ivale

nt

(Bcf/

d)

Gen

era

tio

n (

MW

h)

Wind: Operating/Construction Solar: Operating/Construction

Wind: Advanced Development Solar: Advanced Development

Wind: Early Development Solar: Early Development

Wind: Announced Solar: Announced


Mexican Exports

Mexican Gas Exports Forecast

2.9 3.7 4.2 4.3 4.7 4.8 4.9 5.0

5.35.7 6.1 5.8 6.0

0.0

2.0

4.0

6.0

8.0

2015 2016 2017 2018 2019 2020 2021 2022

Bcf/

d

Historical DI Forecast MX Fcst (Pipeline + LNG)*

CHART 29

Source: EIA, SENER, DI Analysis

Project Name Operator StatusIn-Service Date

Capacity (Bcf/d)

Basin Notes

Nueva Era Pipeline Howard MexicoUnder Construction

8/1/2018 0.50 Eagle FordInitially expected to come online in June2017

South Texas Expansion Project (STEP)

Enbridge Applied 10/1/2018 0.40Eagle Ford

(US project)Initially expected to come online in May2017

Valley Crossing (Nueces-Brownsville)

EnbridgeUnder Construction

10/1/2018 2.60 Eagle FordInitially expected to come online in June2018. Construction started in April 2017

Sur de Texas-Tuxpan Pipeline

CFE Announced 06/1/2019 2.60MX from Eagle Ford

Initially expected to come online in June2018.

Key Projects Adding US Export Capacity to MXTABLE 1

Natural gas exports from the US to Mexico are expected to reach 5.0 Bcf/d in 2022, an increase of 0.8 Bcf/d from 2017 levels.

This growth is 1 Bcf/d lower compared to Mexican authority (SENER-The Secretariat of Energy). The main reason for the difference in the forecasts is that SENER volumes might include LNG imports. In the previous (2016) Mexico’s outlook report for 2015-2030, all imports were expected to come via pipeline from the U.S. starting in 2017. Due to delays in pipeline infrastructure advances, this was not possible in 2017, therefore the 6 Bcf/d expected in 2022 could include imports via LNG.

Per EIA, U.S. exports to Mexico via LNG increased by 0.3 Bcf/d in 2017, from 0.05 Bcf/d in 2016 to 0.35 in 2017.

Projects on the Mexico side continue to face push backs due to delays in getting permits issued by the regulatory agencies. Most projects, as shown in Table 1, are facing about a one-year delay.


LNG Exports - Two Operating Export Terminals

LNG Exports – Sabine Pass and Cove Point Activity

CHART 30

LNG Exports Forecast

CHART 31

0.511.94

3.0

5.57.0 7.3

8.0

0

2

4

6

8

10

2016 2017 2018 2019 2020 2021 2022

Bcf/

d

Historicals DI Forecast

0.0

1.0

2.0

3.0

4.0

Bcf/

d

Sabine Pass

Creole Trail KM LA NGPL Transco

0.0

0.5

1.0

1.5

Bcf/

d

Cove Point

Cameron (2.1), Freeport (2.14)

Corpus Christi (2.14), Sabine Train 5 (0.6)

Source: EIA, Genscape Pipeline Data, DI Analysis

During the first quarter of 2018, Cove Point became the 2nd

LNG export terminal in the U.S. after Sabine Pass in Louisiana.

Based on LNG terminals currently under construction, Drillinginfo forecasts an average of 3 Bcf/d of LNG exports in 2018 and increasing to 8 Bcf/d in 2022.

Daily flows from pipeline postings show multiple days with sendouts from Sabine Pass and Cove Point higher than 3 Bcf/d back to Nov’17. However, volumes are volatile and have also gone as as low as 0.7 Bcf/d.

NGLs



Key Takeaways

▪ The overall frac spread (NGL barrel ratio to Henry Hub) has dropped in recent months due to higher oil and gas prices coupledwith lower NGL prices. The bump in ethane recovery observed in the last report was short lived as prices no longer support it. There should be a slight uplift in prices mid-year when Mariner East 2 comes online.

▪ Expected production growth continues to come from the Permian due to the superior economics along with proximity to market. The majority of that growth comes from ethane (210 MBbl/d of ethane of the 488 MBbl/d of total NGL growth from December 2017 to December 2021) with increased ethane recovery out of the area in the coming years.

▪ Ethane rejection is expected to decline in the Eagle Ford, Permian, and Northeast over the next couple of years as steam cracker demand in the Gulf Coast and export demand in the Northeast grow.

▪ The delay of Marnier East 2 has caused a bottleneck for LPG exports, putting downward pressure on LPG prices. The new pipeline is due to come online mid-2018, expecting to bring 275 MBbl/d of ethane, propane, and butane takeaway capacity for export out of the East Coast.

▪ Natural gasoline demand slightly rose over Q4 2017, driving prices up and dropping stocks from close to historical highs to around the 5 year average. However, with limited demand growth and US and Canadian demand expected to be flat-to-declining, more waterborne exports are going to be needed in order to balance the market.

First Quarter Announcements:

▪ Utopia East pipeline was placed into service in January 2018. The 270-mile pipeline transports 50 MBbl/d of ethane from Harrison County, Ohio to Windsor, Ontario to produce plastic feedstock for the petrochemical industry.


Oversupply Persists in NGL’s

0

1,000

2,000

3,000

4,000

5,000

6,000

Mb

/d

SE/Gulf West Midcontinent Gulf of Mexico Northeast Other Permian

Dec22 vs Dec17

US NGL Production

CHART 32

Source: DI ProdCast

+213

+159

+93

+124

+499

US NGL Production

The development of the major shale gas and tight oil plays has been the key player in the rapid growth in US NGL production. It is expected to increase by 305 MBbl/d from end of 2017 to end of 2018. About 46% of that growth comes from the Permian basin.


The Value of NGLs

CHART 33

0

5

10

15

20

25

30

$/M

MB

tu

NGL Composite WTI Henry Hub

0

5

10

15Frac Spread

0

2

4

6

8

10

12

14

16

18

(10)

10

30

50

70

90

110

130

150

$/M

MB

tu

Cen

ts/G

allo

n

Ethane Propane Normal Butane Isobutane Natural Gasoline Henry Hub

CHART 34

NGL Prices vs. Gas Prices

Source: ProdCast, Platts Prices, EIA

Frac Spread

The first three months of 2018, have stressed the frac spread, with higher oil and gas prices and lower NGL prices. A major contributor to lower NGL prices is the lack of infrastructure. Moving forward, Drillinginfo expects slight gains in outright ethane prices as steam crackers come online to support additional ethane recovery. In addition, Sunoco’s Mariner East is expected to carry 275 MBbl/d of ethane, propane, and butanes to Marcus Hook for export which will incentivize prices to rebound from the price drop observed over the last few months.

Despite our expectation of overall price strength for the NGL barrel, there are several price risks to keep an eye on:

• The long term gasoline demand trend in the US is declining; declining demand for gasoline means declining demand for butane in gasoline blending.

• Demand for pentanes+ as diluent for Canadian oil sand production has flattened as SAGD and mining projects have been cancelled or delayed in the face of low crude prices. As a result, growing pentanes+ volume will need to find a new home.

20

18


Ethane

Source: ProdCast, Hodson, EIA

Ethane Rejection

Ethane rejection has come down from the peak seen in 2015 of almost 800 MBbl/d, but is still very much a reality at about 640 MBbl/d. Close to 450 MBbl/d of incremental capacity is due to come online this year, mitigating some of the projected ethane rejection.

Forward Looking

Eagle Ford, Permian, and Rockies have already seen more ethane recovery as new crackers have come online on the Gulf Coast. This trend will continue as the Gulf Coast cracking capacity is expected to grow further and these regions have low transportation costs as they are close to the market.

The Williston, on the other hand, will likely continue to reject ethane, as the cost of shipping is close to the price of ethane (~25 cents/gal) allowing for little to no margins for Petrochemical companies.

The Northeast is the main contributor to ethane rejection in the US, however, it has started to decline with projects like Marcus Hook and Mariner West bringing new demand to the area. In January, Utopia East pipeline commenced operations, brining on 50 MBbl/d (expandable to 75 MBbl/d) of ethane export capacity from Ohio to Canada. By mid-2018, Mariner East 2 is expected to bring an extra 275 MBbl/d of NGL demand, however, ethane will be competing with propane and butane on that pipeline.

5-7 cpg

-

100

200

300Northeast

0

20

40

60Williston

0

50

100

Eagle Ford

0

50

100

Permian

0

50

100

Rockies

0

100

200

300 Gulf Coast

Rejected Ethane

Incremental Cracker Demand


LPGs

LPG Supply/DemandLPG ExportsCHART 35

Mont Belvieu PricesCHART 37

0

500

1,000

1,500

2,000

Mb

/d

Normal Butane/Butylene Isobutane/Isobutylene

Propane/Propylene LPG Export Capacity

(10)

10

30

50

70

90

110

130

150

Cents

/gal

Propane Normal Butane Isobutane

CHART 36

25,000

45,000

65,000

85,000

105,000

125,000

145,000

165,000

185,000

MB

2014 2015 2017

2016 5-Year Average

-

500

1,000

1,500

2,000

2010 2011 2012 2013 2014 2015 2016 2017LPG Exports

Petchem Demand

Heating/Fuel/Gasoline Blending/ StorageBalancingTotal Demand

Source: DI ProdCast, EIA, Platts Prices

CHART 38

LPG Stocks

Propane/Butane

LPG exports continue to draw from stocks, rounding out 2017 to levels below what was observed in late 2014 (the time of the price crash). Exports have peaked at about 1,200 MBbl/d due to lack of infrastructure. Sunoco’s Mariner East 2 (ME2) was initially expected to come online in 2017, but has been postponed to mid-2018. The postponement of the 275 MBbl/d pipeline to Marcus Hook for export has put downward pressure on prices, as propane demand has been bottlenecked. Once this bottleneck is lifted exports are expected to rise and prices are expected to recover.

Bottleneck

Bottleneck


-100

0

100

200

300

400

500

2010 2011 2012 2013 2014 2015 2016 2017

Natural Gasoline Exports Petchem DemandDiluent/Other/ Storage Balancing Total DemandTotal Supply

Natural Gasoline

Natural Gasoline Demand

US ExportsCHART 40 CHART 41

Natural Gasoline Stocks

CHART 39

0

5,000

10,000

15,000

20,000

25,000

30,000

MB

2014 2015

2017 2016

5-Year Average

98%

2%

Canada

Other

Source: EIA, Platts Prices

Natural Gasoline Demand

Although natural gasoline stocks have decreased over the last few months, natural gasoline demand remains fairly flat with limited potential for growth. With new export pipelines like ME2 only carrying light feeds (ethane, propane, and butane), along with the fact that crackers have recently only been using about 5% natural gasoline as their feedslate, there isn’t much hope for significant natural gasoline demand growth in the near future. Waterborne exports are going to need to increase in order to balance the market.

Limited demand growth and growing supply for pentanes+ is expected to keep a strong ceiling on the overall NGL barrel price, and limit a return to historical peak linkages to Brent.


2018 – 2019 Expected Infrastructure

Cracker AdditionsTABLE 2

Source: Hodson

Company Plant Region Capacity (MMlb/year) Capacity (MBbl/d) 2

01

8

Chevron Phillips Cedar Bayou #2 Gulf Coast 3,300 94

ExxonMobil Baytown #3 Gulf Coast 3,300 94

Indorama Lake Charles, LA Gulf Coast 970 28

Sasol Lake Charles #2 Gulf Coast 3,300 94

Shintech Plaquemine, LA Gulf Coast 1,100 31

TOTAL 11,970 341

20

19 Formosa Point Comfort #3 Gulf Coast 3,500 100

Total Port Arthur, TX Gulf Coast 2,200 63

TOTAL 5,700 162

Pipeline AdditionsTABLE 3

Company Pipeline Region Capacity (MBbl/d)

20

18

Sunoco Mariner East 2 Northeast 275

Kinder Morgan* Utopia East Northeast 50

Epic Epic NGL Pipeline Texas 350

Kinder Morgan UMTP Northeast/Texas 430

ONEOK Delaware Basin Ext. Texas 110

TOTAL 1,215

20

19 Enterprise Shin Oak Texas 250

Targa/Blackstone Grand Prix Texas 300

ONEOK Elk Creek Other 240

TOTAL 790

* Came online in January 2018

OIL & PRICE FORECAST



Crude Oil Price Forecast

$60 $60 $60 $60 $60$61$59

$56$53 $52

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

2018 2019 2020 2021 2022

WTI ($/Bbl)

DI Fcst NYMEX as of 3-26-18

Drillinginfo WTI ForecastCHART 42


Natural Gas Price Forecast

$2.85 $2.85 $2.85

$2.65 $2.65

$2.87

$2.77 $2.75

$2.79

$2.85

$2.50

$2.55

$2.60

$2.65

$2.70

$2.75

$2.80

$2.85

$2.90

2018 2019 2020 2021 2022

Henry Hub ($/MMBtu)

DI Fcst NYMEX as of 03-26-18

Drillinginfo HH ForecastCHART 43


4Q2017 Earnings Calls Summaries


Highlights and Trends

Onshore U.S. Independent E&P Updates

▪ Spend within cash flow – producers are taking efficiency to the next level and looking to spend capital within generated cash flow from operations

▪ Cost inflation increasing 10-20% from pressure pumping and personnel, some has already been realized as activity recovered in ’17

▪ Production increases – not a surprise, but between reducing rigs in less prolific areas and moving them to core acreage like thePermian, and an emphasis on gradual rig increases and more wells TIL in 2H’18 – we can expect a significant production ramp later this year

▪ Tax reform has had a positive impact on most companies’ balance sheets. Additionally, it has increased the appetite for further investment in US

▪ Return based incentive plans – as the focus from growth to efficiency continues, companies are shifting to return-based executive compensation

▪ Reduce debt and leverage – between the competition of lower Net Debt/EBITDAX ratios, and increasing long term debt expirations, companies iterate strategies to reduce debt in the short term

▪ Return to shareholders, giving the people what they want – most producers struggle in this category, but it’s helpful to promise, even if it is price rally dependent

▪ Producers have noted that the limited amount of trades in very recent months by Permian-only players shows lack of quality of acreage out on the market, and they’re turning to M&A as seen recently with Concho’s acquisition of RSP Permian. In addition, some players like Pioneer and QEP are divesting assets to become Pure-Play Permian, which will also increase activity once they have that cash.

▪ Northeast players peddling how takeaway projects such as Rover, Atlantic Sunrise, and Nexus coming online will help realized price in ’18.


Recent Capital Markets and Deal Activity

Source: FactSet and DI analysis

Fourth Quarter Deal Activity

▪ EQT acquired Rice on Nov 13th, $7.28B

▪ Linn Energy sold non-core Bakken assets (20K net acers, 8 Mboe/d) for $285M

▪ WY Moxa Gas field assets with 86 MMcf/d PDP and 430 non-op wells for $350M

Company Issue Date Issued Rate Maturity

Concho 2017/09/26 800 4.875 2047

Concho 2017/09/26 1000 3.75 2027

SRC 2017/11/29 550 6.25 2025

Hess 2017/11/22 800 5.625 2026

QEP 2017/11/21 500 5.625 2026

Whiting 2017/12/27 1000 6.625 2026

Continental 2017/12/08 1000 4.375 2028

PDC 2017/11/29 600 5.75 2026

Range 2017/10/06 741 5 2023

Range 2017/10/06 580 5 2022

Southwestern 2017/09/25 500 7.75 2027

Southwestern 2017/09/25 650 7.5 2026

EQT 2017/10/04 1250 3.9 2027

EQT 2017/10/04 750 3 2022

EQT 2017/10/04 500 2.106 2020

EQT 2017/10/04 500 2.5 2020

Gulfport 2017/09/07 600 6.375 2025

Gulfport 2017/09/07 650 6 2024

Black Stone 2017/11/01 1000 4.06 2022

Williams 2017/11/17 3500 -- 2021

Antero Midstream 2017/10/26 1500 2.81 2022

Antero Resources 2017/10/26 2500 2.96 2022

Hess 2017/12/01 4000 -- 2021

Hess 2017/11/22 600 -- 2022

Halcon 2017/09/07 1000 -- 2022

Erin Energy 2017/09/19 -- 5 2018

California Resources 2017/11/17 1300 -- 2022

Fourth Quarter Debt Activity Over $500MTABLE 4

Industry Returns/Valuation

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Industry Returns/ValuationCHART 44

Adjusted for the commodity price, E&P industry returns continue to be weak and valuation multiples continue to decrease, with valuations at their 2 year low and 7.6x off their high in Dec-16

Source: FactSet and DI analysis

11.712.4

14.314.9

14.3

16.2 16.2 15.9

18.419.0

18.017.1 16.9 17.0

14.3 14.3 14.5

13.114.0 14.1

13.1 13.4 13.7

11.4

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

-50.00%

-40.00%

-30.00%

-20.00%

-10.00%

0.00%

10.00%

20.00%

30.00%

Multip

le

% R

etu

rn

EV/EBITDA LTM WTI Adj. Industry Return Industry Return


Oil Hedging Update


Industry Oil Hedge SummaryCHART 45Out of 36 E&Ps, only 10 of

them are hedged below 50%.

Mid-Larger caps are more exposed to oil prices in 2018, with 5 of those 10 below 50% had oil revenues greater than $2 billion in 2017 (Marathon, Apache, EOG, Anadarko, and Concho).

Only 4 out of the 26 hedged above 50% had 2017 revenues of $1 to $1.6 billion (Chesapeake, Newfield, Whiting, and Diamondback)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

SN

WP

X

AR

SM HK

CLR

GP

OR

RR

C

SW

N

CH

K

FA

NG

UP

L

PD

CE

EC

R

NF

G

PX

D

NF

X

LPI

EP

E

SD

JON

E

EQ

T

MT

DR

DV

N

CR

ZO

CX

O

CO

G

XE

C

AP

C

OA

S

CP

E

EG

N

MR

O

EO

G

SR

CI

ES

TE

% Oil Hedged Average

FY’18 Avg: 62%

Source: FactSet and DI Analysis. Based on 2018 midpoint of oil guidance. If not provided, based on average consensus production.


Gas Hedging Update


Industry Gas Hedge SummaryCHART 46Out of 36 E&Ps, 15 of them are

hedged below 50% for 2018 production.

Reported unrealized gain on hedges, relative to 2017 revenue, trends positive for this group with the majority of hedges being in the money.

Northeast producers have some of the best unrealized gain relative to revenue, owning 6 of the top 8 spots on this list.

Gulfport – 25%,

Southwestern – 24%

Antero – 24%

Eclipse – 19%

EQT – 17

Range – 15%

0%

20%

40%

60%

80%

100%

120%

SN

WP

X

AR

SM HK

CLR

GP

OR

RR

C

SW

N

CH

K

FA

NG

UP

L

PD

CE

EC

R

NF

G

PX

D

NF

X

LPI

EP

E

SD

JON

E

EQ

T

MT

DR

DV

N

CR

ZO

CX

O

CO

G

XE

C

AP

C

OA

S

CP

E

EG

N

MR

O

EO

G

SR

CI

ES

TE

% Gas Hedged Average

FY’18 Avg: 53%

Source: FactSet and DI Analysis. Based on 2018 midpoint of gas guidance. If not provided, based on average consensus production.


Contact

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Market Intelligence Team Direct [email protected], ext 3

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