1

April 15, 2019

$2.2

$8.0

$9.9 $10.7

$4.9

$15.8

$21.2 $21.9 $24.1

$17.0

$9.1 $9.2

$20.8

$8.2

$31.6

$19.5

$1.4 $1.3

--

50

100

150

200

250

300

350

400

450

500

--

$10

$20

$30

$40

$50

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19

61% 83% 74% 79% 39% 52% 62% 71% 93% 24% 68% 82% 91% 64% 46% 93% 51% 100%

Nu

mb

er

of

Tra

ns

acti

on

s

Tra

ns

acti

on

Valu

e (

$b

n)

Asset Corporate Number of Transactions

% Oil

IndicatorCurrent

Value

Week's

Change

%

Change Direction

Prompt Oil Price ($/bbl) $63.58 $1.48 2.4%

Prompt Gas Price ($/mmbtu) $2.66 $0.02 0.8%

Wkly Trans. Value ($mm) $1,225 $1,178 nmf

Wkly Trans. Count 2 (2) (50%)

US Rig Count 1,022 (3) (0.3%)

US Oil Prod'n (mmbbl/d) 12.2 -- --

US Gas Prod'n (bcf/d)(1) 108.1 -- --

US Oil Storage (mmbbl) 456.6 7.0 1.6%

US Gas Storage (tcf) 1.2 0.0 2.2%

Debt

Markets

Five issuers priced six tranches for $5 billion in proceeds

Year-to-date U.S. volume is down 2% year-on-year

U.S. high yield funds reported an inflow of $655 million

ETFs reported an inflow of $210 million, while mutual funds reported an inflow of $445 million

High yield index yield was 6.28%; high yield energy index yield was 7.82%

Source: BMO Transaction Database, Baker Hughes, BMO Commodity Products Group, Bloomberg, EIA, PLS

Note: Current quarter’s data is through the week covered by this issue.

1. EIA U.S. natural gas gross withdrawals and production reported monthly as of January 2019.

2. S&P E&P = S&P Oil & Gas E&P Select Industry, SPX = S&P 500 Index.

3. Does not reflect Chevron / Anadarko transaction. This transaction will be reflected in next week’s newsletter.

Key Industry Indicators

Quarterly Deal Activity(3)

S&P E&P(2) outperformed last week 2.2% vs. SPX(2) 0.3%

The major U.S. equity indexes finished mixed last week. Consumer discretionary, consumer staples,

financials, real estate, and tech finished higher. Health care, industrials, and materials finished lower

Equity

Markets

Oil ended last week up. With stress in Venezuela and Iran causing tightening of the global oil markets,

supply has been continually decreasing. President Trump designated Iran’s Revolutionary Guard Corps

as a foreign terrorist organization. Fighting erupted in Libya near Tripoli. Oil output from Libya had

increased in recent months as peace fragilely took hold but it is apparent that crude flows cannot resume

until peace talks are underway. The expectation is that with a tightening of supply, prices will continue to

climb as demand increases going into the summer. Crude exports hit the lowest level since January

mainly due to the partial closure of the Houston Ship Channel because of the ITC terminal fire and some

recent bad weather which caused a decrease in crude outflows. The near-term contract closed up $1.48,

or 2.4%, at $63.58

Natural gas ended last week up. SoCal basis markets were well offered throughout the next year as

SoCal storage increased in an effort to stockpile before a potentially volatile summer. Fundamentals

remain bearish short-term. The near-term contract closed up $0.02, or 0.8%, at $2.66

Commodities

Week in Review

In Commodities, ECM and DCM, let’s go to journalism standards, even

though that’s not how we get the text from those groups. Main change is

that any number below 10 is spelled out (one instead of 1). This does not

apply to statistical analyses, percentages, or money, of course.

Let’s follow these guidelines when sorting articles:

• First priority: Domestic A&D, ranked by size

• Next: Domestic M&A

• Then: US companies doing international deals (like

Noble’s Tamar)

• Then: Others (Cabot’s Lackawanna)

• Then: Prices, rig count, completions, etc.

To paste the arrows with colors,

• FactSet

• Settings

• Presentation Linking and Formatting

• Import

• Colors

• Change Color Font

For the primary Commodities bullet points on oil and gas

prices, please start with “The near-term contract opened the

week at $___” and end that same bullet point with “The

near-term contract closed the week at $____, down(up)

$___, or ___%.” You don’t have to use exactly those words

as long as the opening and closing prices are included . For

example, you could write, “Opening the week at $45.21, the

near-term oil contract declined steadily based on …” – you

know, think like a journalist, be creative.

Covering the Week of April 5 to April 11, 2019

The October issue of BMO Calgary’s A&D (Canadian)

Market Monitor went live last week – read more here

[TBU]

[TBU]

[TBU]

[TBU]

[TBU] [TBU]

This is the final issue for 2018. The Market Monitor will

return on Monday, January 7th. Happy Holidays from the

BMO Capital Markets team!

On Friday, April 12th, Chevron announced an agreement to

acquire Anadarko Petroleum for ~$50 billion (see page 4 for

more detail)

Shell signed an agreement to sell its 22.45% non-operated

interest in the Caesar-Tonga asset in the Gulf of Mexico to

Delek CT Investment for $965 million (see page 5 for more

detail)

Callon Petroleum Company announced it entered into a

definitive agreement to divest non-core assets in the Midland

Basin for $260 million

Maverick Natural Resources announced that it has closed an

acquisition of producing properties in the Overton Field in East

Texas

All references to last week in the comments below are through Thursday

(3)

(3)

2

April 15, 2019

y = 36.369e-0.07x

R² = 0.3547

--

$10

$20

$30

$40

$50

$60

-- 5.0x 10.0x 15.0x 20.0x 25.0x 30.0x

Sa

les

Pri

ce

/ P

rove

d R

es

erv

es

($

/bo

e @

15

:1)

R / P

Ann'd Date Buyer Seller Area Asset Description Value(1)

Proved Multiple

Prod.Multiple Net Acres

($mm) ($/boe) ($/boe/d) ($/acre)

11-Apr-19 Delek Group Shell Gulf of Mexico 22.45% WI in Caesar-Tonga Field $965 n.a. $60,540 n.a.

08-Apr-19 Sequitur Energy Resources Callon Permian 9,850 net acres in Reagan & Upton, TX $260 n.a. $65,000 $26,396

02-Apr-19 Dorchester Minerals, L.P. H. Huffman & Co. Multi-Region Mineral & royalty assets across the U.S. $44 n.a. $139,419 nmf

27-Mar-19 Undisclosed Buyer Rosehill Resources Permian ~880 net acres in Lea Co., NM $22 n.a. n.a. $25,000

27-Mar-19 Diversified Gas & Oil HG Energy II LLC Marcellus/Utica Huckleberry assets in Appalachia $400 n.a. $19,364 n.a.

26-Feb-19 Ring Energy Inc Wishbone Energy Partners Permian 37,206 net Central Basin Platform acres $300 $8.75 $50,000 $8,063

19-Feb-19 Scout Energy Partners Mid-Con Energy Partners Other North Texas assets $60 $8.22 n.a. n.a.

19-Feb-19 Mid-Con Energy Partners Scout Energy Partners Mid-Continent Caddo, Grady, and Osage cos., OK $28 n.a. $20,960 n.a.

19-Feb-19 Undisclosed Buyer Noble Energy Permian Non-core acreage in the Delaware Basin $63 n.a. n.a. n.a.

19-Feb-19 Undisclosed Buyer Noble Energy Permian 13,000 net acres in Reeves Co., TX $132 n.a. n.a. $10,154

Blue = BMO provided transaction advisory services Green = BMO provided acquisition financing or related services

Purple = BMO provided both transaction advisory services and acquisition financing or related services

R / PSales Value /

Proved Reserves (15:1)

(ratio) ($ / boe) ($ / mcfe)

8x $20.71 $1.38

10x $17.99 $1.20

15x $12.65 $0.84

20x $8.90 $0.59

Permian38%

Rockies (ex. Bakken)

10%Bakken

4%

Appalachia3%

Mid-Con16%

Eagle Ford6%

Ark-La-Tex5%

Gulf of Mexico3%

Other17%

LTM By Region

Oil69%

Gas31%

LTM By Commodity

Public Company

37%

PE / PE-Backed

24%

Private18%

Other21%

LTM By Buyer Type

The 10 Most Recent Asset Transactions Over $20 Million

A&D Valuation Trends(3)

Source: BMO Transaction Database, Baker Hughes, BMO Commodity Products Group, Bloomberg, PLS1. Represents total enterprise value. 2. Calculated as percentage of total LTM transaction count (number of transactions, not dollar value).3. 64 transactions from January 2015 to 2019 with transaction value >$20mm. Adjusted for changes in price outlooks. Recalculated boe reserves are on a 15:1

(gas:oil) basis. Acreage transactions excluded by using deals with PDP of >= 40% of total proved. 4. Year-to-date data is through this week’s date for each respective year. Does not reflect Chevron / Anadarko transaction. This transaction will be reflected in next week’s newsletter.

(2) (2) (2)

YTD Deal Activity ($bn)(4)

$15.4 $12.6

$8.8 $9.6

$6.2

$24.2 $22.2

$2.7

2016 2017 2018 2019

249 483 399 61

Asset Corporate

Deal Count

3

April 15, 2019

4/11/2019

Appalachia 1

Ark-La-Tex 8

Bakken 6

Eagle Ford 5

Mid-Con 8

Other 16

Permian 20

Rockies 5

69

Select Significant Deals on the Market

Disclaimer: The foregoing links are for convenience only and relate to materials that were not prepared or reviewed by BMO Capital Markets. BMO Capital Markets takes

no responsibility for and makes no representations with respect to the contents thereof. These materials may be inconsistent with the views of BMO Capital Markets.

Source of Select Significant Deals on the Market: BMO Transaction Database

Industry Headlines

Appalachia

1 Deals

Mid-Con

8 Deals

Eagle Ford

5 Deals

Permian

20 Deals

Other

16 Deals

Rockies

5 Deals

(Click headline to link to the full article)

A&D Headlines

Bakken

6 Deals

Ark-La-Tex

8 Deals

BMO Deals (Status)

Enerplus Elm Coulee (In Market) – See page 6

Juno Permian (In Market) – See page 7

Rio Glasscock County (In Market) – See page 8

Crude Has Surged >35% in 2018 as OPEC+ Limit

Output

IEA Says Oil Market Tightening, But Global Demand

May Falter

As Conflict Escalates in Libya, So Do Global Oil Prices

Trump's Keystone XL Pipeline Permit Back in Court as

Indigenous Group Files Complaint

Donald Trump's Executive Action Speeds Critical

Energy Infrastructure

Permian Basin's Future Depends on the Reservoir

Study Group, or "Really Smart Guys"

Permian's Flaring Rises by 85% as Oil Boom

Continues

Chevron Announces Agreement to Acquire Anadarko

Shell Sells Stake in Caesar-Tonga Field in Gulf of

Mexico to Delek Group for $965 Mln

Callon Petroleum Sells Permian Assets After Houston

HQ Move

Maverick Natural Resources Announces Acquisition of

Producing Properties in East Texas

[TBU]

[TBU] [TBU]

[TBU]

Talos Energy Announces Full Year 2019 Operating

and Financial Guidance (includes A&D

announcement)

BMO Deals (Status)

Juno Permian (In Market) – See page 4

Rio Glasscock County (In Market) – See page 5

4

April 15, 2019

On April 12, 2019, Chevron Corporation (NYSE: CVX)

(“Chevron”) announced it entered into an agreement to

acquire all of the outstanding shares of Anadarko

Petroleum Corporation (NYSE: APC) (“Anadarko”) for

a total transaction value of ~$50 billion, including the

assumption of $15 billion of net debt

Chevron will issue approximately 200 million

shares of stock and pay approximately $8 billion in

cash

Based on Chevron’s closing price on April 11,

2019, Anadarko shareholders will receive 0.3869

shares of Chevron and $16.25 in cash for each

Anadarko share

Anadarko valued at $65 per share

Transaction is expected to achieve run-rate cost

synergies of $1 billion before tax and capital spending

reductions of $1 billion within a year of closing

Transaction is expected to close in 2H 2019

Upon closing, Chevron will remain headquartered in

San Ramon, California

TRANSACTION SUMMARY

Source: Press releases, company presentations

1. Cash includes assumption of 2018YE net debt of $15 billion and based on 499.58 million APC shares as of 01-Feb-19. Stock consideration based on 200 million

CVX shares issued and closing CVX share price on 11-Apr-19.

ASSET SUMMARY

U.S. assets in the Permian Basin, DJ Basin, Powder

River Basin, Greater Natural Buttes, and Gulf of

Mexico

240,000 net acres in the Permian Basin

400,000 net acres in the DJ Basin

Interest in 231 blocks in the Gulf of Mexico

Other assets in Mozambique, Algeria, and Ghana

77.8% limited partner interest and entire general

partner interest in Western Gas Partners LP

2018YE proved reserves of 1,473 mmboe

~45% oil, ~90% U.S.

Q4 2018 net production of 701 mboe/d

Interesting Deal of the Week #1:

Chevron Acquires Anadarko Petroleum for ~$50 Billion

ACQUIRED ASSETS TRANSACTION METRICS

Anadarko Assets

Rockies

Permian

Gulf of Mexico

Algeria

Ghana

Purchase Price (US$ mm)(1)

Cash $23,240

Stock $25,198

Total Consideration $48,438

Metrics

Net Production (boe/d) 701,000

Net Reserves (mmboe) 1,473

Multiples

TEV / Net Production ($/boe/d) $69,099

TEV / Net Reserves ($/boe) $32.88Mozambique

OBSERVATIONS

Strengthens Chevron’s Delaware Basin position,

creating a 75-mile-wide corridor across the basin

Enhances Chevron’s high-margin position in the Gulf

of Mexico

Chevron plans to divest $15 to $20 billion of assets

between 2020 and 2022

CVX Share Price 4/11 $125.99

Shares mm 200.0

Total Stock $25,198

APC Shares mm 2/1 499.58

Cash $16.25

Total Cash $8,118

ST Debt $919

ST Debt $28

LT Debt $15,470

Cash $1,295

Net Debt $15,122

5

April 15, 2019

On April 11, 2019, Delek Group (OTCMKT: DGRLY)

(“Delek”) announced it signed an agreement to

acquire 22.45% interest in the Caesar-Tonga oil field

in the Gulf of Mexico from Royal Dutch Shell for $965

million

Acquisition will be financed by non-recourse loans

from international banks, along with Delek Group

funds

Delek also signed a long-term off-take agreement with

Shell to purchase oil produced from the field for 30

years at market prices or prices matched to third party

offers

Delek will co-own the asset with three other operators

Anadarko Petroleum (33.75% operated interest)

Equinor (23.5% non-op interest)

Chevron (20.25% non-op interest)

TRANSACTION SUMMARY

Source: Press releases, company presentations

ASSET SUMMARY

Located in the Gulf of Mexico 300 kilometers south of

Louisiana, the Caesar-Tonga oil field is one of the top

ten largest deepwater resources in the Gulf of Mexico

Depth of 1,500 meters

Production horizon spanning tens of years

Currently contains eight wells connected by undersea

pipeline network to a production platform owned by

Anadarko

Gross production of 71,000 boe/d (90% oil)

Net production ~16,000 boe/d

Net 2P reserves of 78 mmboe

Annual EBITDA of $230 million

Interesting Deal of the Week #2:

Delek Group Acquires Non-Operated Interest in Gulf of Mexico Assets for $965 Million

ACQUIRED ASSETS TRANSACTION METRICS

Purchase Price (US$ mm)

Cash $965

Total Consideration $965

Metrics

Net Production (boe/d) 16,000

Net 2P Reserves (mmboe) 78

Annual EBITDA ($mm) $230

Multiples

TEV / Net Production ($/boe/d) $60,313

TEV / Net 2P Reserves ($/boe) $12.37

TEV / Annual EBITDA 4.2x

Shell Assets

6

April 15, 2019

Opportunity to acquire a largely contiguous, ~54,000 net acre

position in the heart of the prolific Elm Coulee Field in Montana’s

Williston Basin (>90% HBP)

PDP net production of 2,684 boe/d, 72% oil (June 2019E)

Low decline rate of ~10%

Strong PDP cash flow of ~$30 mm/yr (June 2019E annualized)

from 329 gross PDP wells(1)

Substantial OOIP, with additional recovery potential from infill wells,

refracs, and EOR

Proven potential for improvement in Bakken well performance

driven by completion optimization and longer laterals

Significant refrac potential with modern completion designs;

wells historically completed with ~150 lbs/ft

Cost reduction potential from additional field automation

Company owned SWD infrastructure helps reduce water disposal

costs and can support additional volumes from future development

or third parties

Data rooms open now

Contact Chelsea Neville at enerplus.montana@bmo.com or 713-

546-9703 for a Confidentiality Agreement, access to the VDR,

and/or to request a data room presentation

Source: Enerplus Elm Coulee Divestiture announcement

1. Does not include SWD well.

Stable Production

and Cash Flow

PDP net production of 2,684 boe/d (72% oil) from 329 wells (June 2019E)

Strong, predictable PDP cash flow of ~$30 mm/yr (June 2019E annualized) with high netbacks supports exploitation and

financing activities

~95% of operated oil production is gathered by pipe with direct access to Dakota Access Pipeline and legacy pipeline

capacity out of the basin; nearly all gas gathered via pipeline

Large,

Contiguous

Position in the

Heart of the

Prolific Elm

Coulee Field

~54,000 contiguous net acre position in the Bakken’s Elm Coulee Field provides significant recoverable resources and

allows for full efficiency of surface operations and LOE optimization

Assets provide high degree of operational control as >90% of acreage HBP

Average WI of ~89% (83% 8/8th NRI) on operated wells

Tremendous

Resource

Potential

Bakken reservoir properties and boundaries are very well understood and highly homogenous across the field, which

supports low risk drilling and predictable outcomes with low capital costs

Upper and Middle Bakken exhibit rock properties equal to or better than the core of the Williston Basin in North Dakota

Middle Bakken average porosity of 8% and water saturation under 10%

Upper Bakken average TOC of 9.3% and maturation temperature of 444° C

Enerplus’ position is the core of the field and offers the highest average net pay in Elm Coulee

Oil in place benefits from high oil saturation of 68-92% across the majority of the Enerplus position

Original, understimulated completions achieved a very low recovery factor, providing substantial upside for refracs and infill

drilling opportunities

Extensive and

Highly Economic

Upside

Opportunity

Many of the best early Bakken wells in the Williston Basin were drilled at Elm Coulee in the early 2000s

Significant refrac potential as majority of wells were completed before 2011 with ~150 lbs/ft of proppant

67 economic infill locations in the core of the Elm Coulee Field

Currently on the Market from BMO: Enerplus Elm Coulee Divestiture

ASSET HIGHLIGHTS

ASSET OVERVIEW PROCESS OVERVIEW

Area Exit for

Company

Full exit of Montana (all rights, all depths)

Assets have not been a recent core focus area for Enerplus and likely have significant unquantified opportunities remaining

7

April 15, 2019

Long-life, shallow decline oil assets located in the prolific Clearfork

Trend of the Permian Basin

Largely contiguous 10,250 net acre position located in the Hoople

Field in Crosby and Lubbock Counties, Texas

100% operated with high WI (100%) and NRI (>75%)

Favorable leasehold position with little-to-no drilling

obligations until 2021; >50% of acreage position under two

leases from one landowner

Current production of ~300 net bopd (100% oil) with significant

remaining drilling inventory consisting of ~200+ low-risk Clearfork

locations

Asset provides substantial, economic running room for organic and

acquisitive growth

Existing Clearfork acreage only ~15% developed based on

10-acre development plan

– Additional upside through 5-acre development,

secondary recovery and Glorieta development, all of

which have been demonstrated in offsetting acreage;

CO2 EOR and Wolfcamp potential

Multiple bolt-on acquisition opportunities and new leasing

opportunities

Acreage position delineated through existing and offset

development; full-scale development plan in place with drill-ready

infrastructure

Data rooms open now

Contact Chelsea Neville at juno.permian@bmo.com or 713-546-

9703 for a Confidentiality Agreement, access to the VDR, and/or to

request a data room presentation

Source: Juno Permian Divestiture announcement

Substantial

Unquantified

Upside

Potential for additional improvement in well performance through further enhanced completions

Near-term development potential by exploiting the Glorieta across Juno’s acreage position

Glorieta present on Juno position and position on trend with offset Glorieta development

Potential development opportunity to commingle Clearfork and Glorieta production, yielding twice the reserves with

little incremental D&C capex

Additional reserve recovery from waterflood operations and 5-acre development; future tertiary recovery

Offset operator testing horizontal Wolfcamp potential in the area

Large,

Contiguous

Acreage Position

in the Prolific

Clearfork Oil

Trend

High quality anchor asset in the heart of the Midland Basin’s Eastern Shelf with multiple stacked pay potential

Acreage situated in the Hoople Field, the most active Clearfork development area since 2015

Majority of Juno’s acreage is situated in the core of the field with vertical Clearfork EURs of ~60 Mbo

Primary recovery economics provide attractive IRRs with low development costs

Secondary recovery provides an incremental increase of 150% of primary EUR based on analog fields

Clearfork “A” STOOIP of up to 13 Mmbo per section based on core and log analysis

Minimal drilling obligations until 2021; moderate thereafter

Increased Oil

Cuts and

Improved

Economics from

Enhanced

Completions

Targeted, more optimized (“Gen II”) fracs demonstrate robust EURs and lower WOR vs. offset results

Fracture growth limited to ~40 feet from perf

Oil cuts have improved by three-fold using selective completions

Prior generation completions took the entirety of the pay zone, thereby increasing communication with higher water

saturation intervals

Asset Ready for

Full-Scale

Development

Significant inventory of 200+ economic Clearfork locations remaining (at 10-acre spacing)

Fast cycle times and favorable land position provides the ability to accelerate development within the first year

Juno II in the Hoople Field grew production by over 25x in less than 3 years

Juno III assets positioned to grow similarly

Inexpensive access to water sources and disposal provides for low-cost waterflood and frac’ing operations

Significant existing investment in infrastructure, including electrical, roads, pipelines and facilities, enable quick ramp to full-

scale development

No deferred maintenance or P&A issues

Currently on the Market from BMO: Juno Permian Divestiture

ASSET HIGHLIGHTS

ASSET OVERVIEW PROCESS OVERVIEW

LOCATOR MAP

8

April 15, 2019

Opportunity to acquire highly economic and

contiguous 1,645 gross acre position in the Midland

Basin located in west-central Glasscock County,

Texas

WI package provides high degree of operational

control with 98% operated, 74% HBP, and 67%

average WI

Ten active vertical wells hold the majority of acreage

Proven development opportunities targeting the Lower

Spraberry, Wolfcamp A, and Wolfcamp D formations

Active development by Parsley, Oxy, Diamondback,

and others highlights robust returns and de-risked

drilling locations

Continued improvement in well performance driven by

completion optimization

WI and ORRI packages available

Data rooms open now

Contact Chelsea Neville (rio.glasscock@bmo.com or 713-546-

9703) for a Confidentiality Agreement, access to the VDR, and/or

to request a data room presentation

Source: Rio Oil and Gas II Glasscock County Divestiture announcement

Active

Development By

Offset Operators

Producing Robust

Returns

Outstanding position in one of the most active basins in the U.S. with 181 rigs in the Midland Basin and 14 in Glasscock

County

~3,500 feet of porous, brittle, hydrocarbon rich pay available from the top of the Spraberry to the base of the Wolfcamp

Active offsetting development in the Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp D by Parsley, OXY,

Crownquest, Cinnabar, Encana, SM, Callon, Diamondback, Hunt, and others

Parsley is actively developing with strong results its directly offsetting Calverley assets in the LS, WCA, and WCB

– Parsley brought 17 wells online in 2018; outperformed historical results with peak rates up to

2,000 boepd (84% oil)

– Parsley acquired Calverley position through BTA acquisition ($40,000+/net acre)

OXY recently completed five wells (offsetting Rio) targeting the WCA and has two additional permits ready to drill

IP and EURs continue to increase through optimization of completion techniques: predominantly slickwater fracs with

proppant loading at ~1,900 lbs/ft

Over 30 potential stacked locations with additional unquantified upside in the Wolfcamp D

Operated Asset

Set Up For

Efficient, Stacked-

Pay, Long Lateral

Development

Contiguous 1,064 net acres in west-central Glasscock County; an additional 134 net overriding royalty acres also available

to further increase NRIs

75% effective (8/8ths) net revenue interest for WI package, excluding ORRI package

74% of net acres HBP from vertical producers with remaining acreage in primary term with 2+ years remaining

Leasehold primed for efficient cube development with 100% of locations expected to support 7,500’+ laterals; 100% of

acreage owns Spraberry through WCA rights and select ownership of WCD

No long term oil and gas sales dedications offer the purchaser marketing flexibility

Full Area Exit

Full area exit for Rio

Rio’s investments have been focused on assembling the position, perfecting subsurface interpretation, and readying the

asset for full-field development

Currently on the Market from BMO: Rio Oil & Gas II Glasscock County Divestiture

ASSET HIGHLIGHTS

ASSET OVERVIEW PROCESS OVERVIEW

LOCATOR MAP

9

April 15, 2019

25%

35%

45%

55%

65%

Feb-16 Aug-16 Feb-17 Aug-17 Feb-18 Aug-18 Feb-19

% o

f W

TI

NGL as % of WTI

$1

$2

$3

$4

$5

Apr-18 Oct-18 Apr-19 Oct-19 Apr-20

($/m

mb

tu)

$20

$30

$40

$50

$60

$70

$80

Apr-18 Oct-18 Apr-19 Oct-19 Apr-20

($/b

bl)

Historical Prices as of 11-Apr-19 Close ($/gal)

NGLs Current Last Wk. 6 Mo. Ago 1 Yr. Ago

Ethane $0.25 $0.22 $0.38 $0.28

Propane $0.67 $0.62 $0.96 $0.81

Butane $0.68 $0.66 $1.07 $0.81

Iso-butane $0.78 $0.74 $1.11 $0.91

Pentane+ $1.31 $1.27 $1.54 $1.56

NYMEX Gas Futures as of 11-Apr-19 Close ($/mmbtu)

Period(1) Current Last Wk. 6 Mo. Ago 1 Yr. Ago

12 Mo. Strip $2.85 $2.82 $2.96 $2.83

2019 $2.80 $2.78 $2.89 $2.79

2020 $2.77 $2.74 $2.69 $2.77

2021 $2.68 $2.67 $2.62 $2.81

2022 $2.85 $2.84 $2.75 $2.96

2023 $2.85 $2.84 $2.75 $2.96

NYMEX WTI Futures as of 11-Apr-19 Close ($/bbl) NYMEX Gas Futures as of 11-Apr-19 Close ($/mmbtu)

Period(1) Current Last Wk. 6 Mo. Ago 1 Yr. Ago

12 Mo. Strip $62.96 $61.73 $70.36 $63.99

2019 $63.45 $62.12 $70.05 $60.52

2020 $60.66 $59.77 $66.87 $56.18

2021 $57.34 $56.72 $63.38 $53.34

2022 $55.15 $54.63 $60.32 $51.72

2023 $54.10 $53.69 $58.12 $51.15

NGL PRICING(2)

HENRY HUB NATURAL GAS (HISTORICAL / FORECAST)

Commodity Prices

Source: BMO Commodity Products Group, Bloomberg, FactSet

1. Future prices are calendar year average unless stated otherwise.

2. Assumes typical Gulf Coast barrel composition.

WTI OIL (HISTORICAL / FORECAST)

Links:

http://www.nasdaq.com/markets/crude-oil.aspx

http://www.bloomberg.com/quote/CL1:COM

http://www.nasdaq.com/markets/natural-gas.aspx

http://www.bloomberg.com/quote/NG1:COM

Link to Detailed

Futures Data

Link to Detailed

Historical Graph

Link to Detailed

Futures Data

Link to Detailed

Historical Graph

[TBU]

[TBU]

[TBU]

10

April 15, 2019

Clearbrook

Midland

Cushing

St. James

(LLS)

East Coast

U.S. (Brent)

Midland Sweet-

Sour Spread

EMS

AECO

Northern

California

Sumas

Southern

California

El Paso - SJ

Waha

HSC

Henry Hub

Panhandle

CIG Chicago

Dominion

Transco

NATURAL GAS PRICING & DIFFERENTIALS TO HENRY HUB ($ / MMBTU) – AS OF 11-APR-19

Commodity Prices (cont’d)

OIL PRICING & DIFFERENTIALS TO CUSHING WTI ($ / BBL) – AS OF 11-APR-19

Legend

Price

Diff.

Legend

Price

Diff.

Source: BMO Commodity Products Group, Bloomberg

Note: Prices and differentials are for prompt month futures except for Clearbrook which is based on spot prices.

MAPS IN

MASTER VIEW

TBU

[TBU]

[TBU]

$63.58

$0.45 $65.95

$2.37

$2.31

($0.35)

$1.93

($0.73)

$2.66

$2.49

($0.17)

$58.73

($4.85)

$70.83

$7.25

$62.33

($1.25)

$59.83

($3.75)

$2.43

($0.23)

$2.69

$0.03

($0.42)

($3.08)

$1.94

($0.72)$1.34

($1.32)$1.97

($0.69)

$0.97

($1.69)$2.05

($0.61)

$3.16

$0.50

11

April 15, 2019

1,1561,294

1,0911,1491,223

9931,212

1,014868

1,2491,090

1,254

271

Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19

H V+D

Item Value Wkly Change Last Week Item Value Wkly Change Last Week

Rig Count 464 2 462 Oil Differential ($4.40) ($3.15) ($1.25)

Permitting Activity 71 (205) 276 Gas Differential ($3.04) $0.03 ($3.07)

0%

10%

20%

30%

40%

50%

--

100

200

300

400

500

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

H V+D % of Total Rigs

-$4.80

-$3.20

-$1.60

$0.00

$1.60

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

-$18.00

-$12.00

-$6.00

$0.00

$6.00

$ /

mm

btu

$ /

bb

l

Midland Waha

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18

mm

cf/

d

mb

bl/

d

Oil Gas3,789

12,169

--$10,000$20,000$30,000$40,000$50,000$60,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

1 2 8 8 6 6 12 13 15 7 3 2 7 2 5 4 1 1

$ /

acre

# Deals

$26,459

--

$50,000

$100,000

$150,000

$200,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

1 2 6 9 5 7 11 9 9 6 1 0 7 2 5 4 1 1

$ /

bo

e/d

# Deals

$119,543

Ann'd

Date Buyer Seller Asset Description Value(1)

Proved

Multiple

Prod.

Multiple Net Acres

($mm) ($/boe) ($/boe/d) ($/acre)(2)

08-Apr-19 Sequitur Energy Resources LLCCallon 9,850 net acres in Reagan & Upton, TX $260 n.a. $65,000 $26,396

27-Mar-19 Undisclosed Buyer Rosehill Resources ~880 net acres in Lea Co., NM $22 n.a. n.a. $25,000

26-Feb-19 Ring Energy Inc Wishbone Energy Partners 37,206 net Central Basin Platform acres $300 $8.75 $50,000 $8,063

19-Feb-19 Undisclosed Buyer Noble Energy Non-core acreage in the Delaware Basin $63 n.a. n.a. n.a.

19-Feb-19 Undisclosed Buyer Noble Energy 13,000 net acres in Reeves Co., TX $132 n.a. n.a. $10,154

Mean $155 $8.75 $57,500 $17,403

Median $132 $8.75 $57,500 $17,577

Blue = BMO provided transaction advisory services Green = BMO provided acquisition financing or related services

Purple = BMO provided both transaction advisory services and acquisition financing or related services

GROSS PRODUCTION

TRANSACTION ACTIVITY (EXCLUDES CORPORATE DEALS)

TRANSACTION PRODUCTION MULTIPLES(3) TRANSACTION ADJUSTED NET ACRE MULTIPLES(3,4)

PERMITTING ACTIVITY BY MONTH

DIFFERENTIALS

Permian Snapshot

RIG COUNT

Source: BMO Transaction Database, Baker Hughes, BMO Commodity Products Group, Bloomberg, Drilling Info, PLS

Note: Current quarter’s data is through the week covered by this issue.

1. Represents total enterprise value. Excludes transactions with deal value <$20 million. 2. $/acre multiple not adjusted for value associated with production.

3. Red line denotes average since 01-Jan-17. Calculated as the weighted average of each quarter’s transactions.

4. Production valued at $45,000/boepd in 2014, $30,000/boepd in 2015, $35,000/boepd in 2016 & 2017, and $40,000/boepd in 2018 & 2019.

[TBU]

[TBU]

[TBU] [TBU]

[TBU] [TBU]

[TBU]

12

April 15, 2019

426474

438379

455

329402

344 312

396354

466

96

Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19

H V+D

Item Value Wkly Change Last Week Item Value Wkly Change Last Week

Rig Count 93 (1) 94 Oil Differential $6.50 ($0.05) $6.55

Permitting Activity 36 (41) 77 Gas Differential $0.03 $0.01 $0.02

0%

5%

10%

15%

20%

--

100

200

300

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

H V+D % of Total Rigs

-$0.30

-$0.20

-$0.10

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

-$6.00

-$4.00

-$2.00

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$ /

mm

btu

$ /

bb

l

LLS HSC

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

1,000

1,200

1,400

1,600

1,800

2,000

2,200

Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18

mm

cf/

d

mb

bl/

d

Oil Gas

1,494

8,295

--$10,000$20,000$30,000$40,000$50,000$60,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

0 1 2 1 2 2 0 4 2 3 1 2 4 2 1 3 0 0

$ /

acre

# Deals

$6,130

--

$50,000

$100,000

$150,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

1 1 3 1 2 2 2 4 4 3 1 2 7 2 0 3 0 0

$ /

bo

e/d

# Deals

$70,217

Ann'd

Date Buyer Seller Asset Description Value(1)

Proved

Multiple

Prod.

Multiple Net Acres

($mm) ($/boe) ($/boe/d) ($/acre)(2)

19-Nov-18 Lonestar Resources Inc Sabine Oil & Gas Corp 2,706 net acres in Eagle Ford $39 $2.98 $48,375 $14,302

20-Sep-18 WildHorse Undisclosed Seller 20,305 net Eagle Ford/Austin Chalk acres $35 n.a. n.a. $1,743

07-Sep-18 Undisclosed Buyer Viking Minerals LLC 1,191 net royalty acres in Eagle Ford $28 n.a. n.a. nmf

31-Jul-18 EP Energy Corp Undisclosed Seller Additional working interests in Eagle Ford $31 n.a. n.a. n.a.

26-Jul-18 BP BHP Billiton Permian, Eagle Ford, and Haynesville $10,500 n.a. n.a. n.a.

Mean $2,127 $2.98 $48,375 $8,022

Median $35 $2.98 $48,375 $8,022

Blue = BMO provided transaction advisory services Green = BMO provided acquisition financing or related services

Purple = BMO provided both transaction advisory services and acquisition financing or related services

Eagle Ford Snapshot

TRANSACTION ACTIVITY (EXCLUDES CORPORATE DEALS)

PERMITTING ACTIVITY BY MONTH

DIFFERENTIALS RIG COUNT

Source: BMO Transaction Database, Baker Hughes, BMO Commodity Products Group, Bloomberg, Drilling Info, PLS

Note: Current quarter’s data is through the week covered by this issue.

1. Represents total enterprise value. Excludes transactions with deal value <$20 million. 2. $/acre multiple not adjusted for value associated with production.

3. Red line denotes average since 01-Jan-17. Calculated as the weighted average of each quarter’s transactions.

4. Production valued at $45,000/boepd in 2014, $30,000/boepd in 2015, $35,000/boepd in 2016 & 2017, and $40,000/boepd in 2018 & 2019.

TRANSACTION PRODUCTION MULTIPLES(3) TRANSACTION ADJUSTED NET ACRE MULTIPLES(3,4)

GROSS PRODUCTION

13

April 15, 2019

157168

154 163 167 177 179

111 104

165

108122

32

Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19

H V+D

Item Value Wkly Change Last Week Item Value Wkly Change Last Week

Rig Count 66 (2) 68 Oil Differential $6.50 ($0.05) $6.55

Permitting Activity 6 (25) 31 Gas Differential -- -- --

0%

5%

10%

15%

20%

--

20

40

60

80

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

H V+D % of Total Rigs

--

$2.00

$4.00

$6.00

$8.00

$10.00

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

--

$2.00

$4.00

$6.00

$8.00

$10.00

$ /

mm

btu

$ /

bb

l

LLS Henry Hub

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

80

90

100

110

120

130

140

Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18

mm

cf/

d

mb

bl/

d

Oil Gas

95

10,967

--$2,000$4,000$6,000$8,000

$10,000$12,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

0 0 5 1 1 3 2 3 0 2 2 0 1 1 2 1 0 0

$ /

mcfe

/d

# Deals

$5,209

--

$5,000

$10,000

$15,000

$20,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

0 0 3 1 1 2 1 3 0 1 2 0 1 1 1 1 0 0

$ /

acre

# Deals

$3,349

Ann'd

Date Buyer Seller Asset Description Value(1)

Proved

Multiple

Prod.

Multiple Net Acres

($mm) ($/mcfe) ($/mcfe/d) ($/acre)(2)

19-Dec-18 Comstock Shelby Shale LLC 6,023 net acres in Haynesville $21 n.a. n.a. $3,404

19-Nov-18 Aethon III QEP Resources Inc 49,700 net acres in Haynesville $735 $0.77 $2,475 $14,789

05-Sep-18 Viking Energy Group Multiple Sellers Texas and Louisiana assets $100 n.a. n.a. n.a.

05-Sep-18 Equinor Texegy LLC 60,000 net acres in Austin Chalk $75 n.a. n.a. $1,250

06-Aug-18 Mission Creek Resources Bonanza Creek Energy Inc 11,132 net acres in the Cotton Valley $117 $1.69 $6,500 $10,510

Mean $210 $1.23 $4,487 $7,488

Median $100 $1.23 $4,487 $6,957

Blue = BMO provided transaction advisory services Green = BMO provided acquisition financing or related services

Purple = BMO provided both transaction advisory services and acquisition financing or related services

Ark-La-Tex Snapshot

TRANSACTION ACTIVITY (EXCLUDES CORPORATE DEALS)

PERMITTING ACTIVITY BY MONTH

DIFFERENTIALS RIG COUNT

Source: BMO Transaction Database, Baker Hughes, BMO Commodity Products Group, Bloomberg, Drilling Info, PLS

Note: Current quarter’s data is through the week covered by this issue.

1. Represents total enterprise value. Excludes transactions with deal value <$20 million. 2. $/acre multiple not adjusted for value associated with production.

3. Red line denotes average since 01-Jan-17. Calculated as the weighted average of each quarter’s transactions.

4. Production valued at $3,000/mcfepd in 2014, and $2,000/mcfepd in 2015, 2016, 2017, 2018, and 2019.

TRANSACTION PRODUCTION MULTIPLES(3) TRANSACTION ADJUSTED NET ACRE MULTIPLES(3,4)

GROSS PRODUCTION

14

April 15, 2019

282328 299 269

493

373 370305

258

397321

423

60

Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19

H V+D

Item Value Wkly Change Last Week Item Value Wkly Change Last Week

Rig Count 81 (3) 84 Oil Differential $7.25 ($0.05) $7.30

Permitting Activity 18 (29) 47 Gas Differential ($0.28) ($0.09) ($0.19)

0%

5%

10%

15%

20%

--

50

100

150

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

H V+D % of Total Rigs

-$3.00

-$2.00

-$1.00

$0.00

$1.00

$2.00

$3.00

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

-$15.00

-$10.00

-$5.00

$0.00

$5.00

$10.00

$15.00

$ /

mm

btu

$ /

bb

l

Brent Dominion

12,000

17,000

22,000

27,000

32,000

50

70

90

110

130

150

Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18

mm

cf/

d

mb

bl/

d

Oil Gas

121

29,659

--$5,000

$10,000$15,000$20,000$25,000$30,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

0 1 0 0 1 2 2 3 2 5 1 4 3 4 3 1 1 0

$ /

mcfe

/d

# Deals

$4,758

--$2,000$4,000$6,000$8,000

$10,000$12,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

0 1 0 0 1 2 2 4 2 4 1 3 1 3 2 0 0 0

$ /

acre

# Deals

$2,083

Ann'd

Date Buyer Seller Asset Description Value(1)

Proved

Multiple

Prod.

Multiple Net Acres

($mm) ($/mcfe) ($/mcfe/d) ($/acre)(2)

27-Mar-19 Diversified Gas & Oil HG Energy II LLC Huckleberry assets in Appalachia $400 n.a. $3,227 n.a.

15-Oct-18 Undisclosed Buyer Range Resources Corp Overriding royalty interests in Appalachia $300 n.a. $17,649 nmf

27-Aug-18 PennEnergy Resources Rex Energy Corp 141,026 net acres in PA and OH $601 $0.58 $2,781 $4,258

26-Jul-18 Encino Acquisition Partners Chesapeake 938,000 net acres in the Utica $1,900 $0.66 $2,960 $2,026

29-Jun-18 Ascent Resources LLC Utica Minerals; Undisclosed 35,400 acres in the Utica $700 n.a. $15,217 $19,774

Mean $780 $0.62 $8,367 $8,686

Median $601 $0.62 $3,227 $4,258

Blue = BMO provided transaction advisory services Green = BMO provided acquisition financing or related services

Purple = BMO provided both transaction advisory services and acquisition financing or related services

Appalachia Snapshot

TRANSACTION ACTIVITY (EXCLUDES CORPORATE DEALS)

PERMITTING ACTIVITY BY MONTH

DIFFERENTIALS RIG COUNT

Source: BMO Transaction Database, Baker Hughes, BMO Commodity Products Group, Bloomberg, Drilling Info, PLS

Note: Current quarter’s data is through the week covered by this issue.

1. Represents total enterprise value. Excludes transactions with deal value <$20 million. 2. $/acre multiple not adjusted for value associated with production.

3. Red line denotes average since 01-Jan-17. Calculated as the weighted average of each quarter’s transactions.

4. Production valued at $3,000/mcfepd in 2014, and $2,000/mcfepd in 2015, 2016, 2017, 2018, and 2019.

TRANSACTION PRODUCTION MULTIPLES(3) TRANSACTION ADJUSTED NET ACRE MULTIPLES(3,4)

GROSS PRODUCTION

15

April 15, 2019

108138 126

171 164

127

201

12896

133114

138

41

Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19

H V+D

Item Value Wkly Change Last Week Item Value Wkly Change Last Week

Rig Count 61 -- 61 Oil Differential ($1.25) ($0.75) ($0.50)

Permitting Activity 8 (31) 39 Gas Differential ($0.73) ($0.11) ($0.61)

0%

5%

10%

15%

20%

--

50

100

150

200

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

H V+D % of Total Rigs

-$1.00

-$0.50

$0.00

$0.50

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

-$20.00

-$10.00

$0.00

$10.00

$ /

mm

btu

$ /

bb

l

Clearbrook CIG

1,100

1,300

1,500

1,700

1,900

2,100

2,300

2,500

2,700

800

900

1,000

1,100

1,200

1,300

1,400

1,500

Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18

mm

cf/

d

mb

bl/

d

Oil Gas

1,427

2,635

--

$5,000

$10,000

$15,000

$20,000

$25,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

0 0 1 2 0 0 2 3 1 0 3 2 0 5 2 0 0 0

$ /

acre

# Deals

$2,712

--

$20,000

$40,000

$60,000

$80,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

0 1 1 4 0 2 3 3 0 1 3 3 0 6 3 0 0 0

$ /

bo

e/d

# Deals

$43,532

Ann'd

Date Buyer Seller Asset Description Value(1)

Proved

Multiple

Prod.

Multiple Net Acres

($mm) ($/boe) ($/boe/d) ($/acre)(2)

31-Jul-18 Northern Oil and Gas W Energy Partners 10,600 net acres in Williston Basin $288 n.a. $42,708 $27,196

18-Jul-18 Northern Oil and Gas Pivotal Petroleum Partners LP Producing assets in Williston Basin $152 n.a. $37,032 n.a.

12-Jul-18 PetroShale Inc Slawson Exploration Co 1,981 net acres in Williston Basin $55 $6.04 $100,000 $27,764

06-Jul-18 Energy Resources 12 LP Bruin E&P Partners LLC 2.8% non-operated WI in Bakken assets $83 n.a. n.a. n.a.

25-Jun-18 Riverbend Oil & Gas LLC Oasis Petroleum 10,167 net acres in Williston Basin $153 n.a. $49,196 $15,049

Mean $146 $6.04 $57,234 $23,336

Median $152 $6.04 $45,952 $27,196

Blue = BMO provided transaction advisory services Green = BMO provided acquisition financing or related services

Purple = BMO provided both transaction advisory services and acquisition financing or related services

Bakken Snapshot

TRANSACTION ACTIVITY (EXCLUDES CORPORATE DEALS)

PERMITTING ACTIVITY BY MONTH

DIFFERENTIALS RIG COUNT

Source: BMO Transaction Database, Baker Hughes, BMO Commodity Products Group, Bloomberg, Drilling Info, PLS

Note: Current quarter’s data is through the week covered by this issue.

1. Represents total enterprise value. Excludes transactions with deal value <$20 million. 2. $/acre multiple not adjusted for value associated with production.

3. Red line denotes average since 01-Jan-17. Calculated as the weighted average of each quarter’s transactions.

4. Production valued at $45,000/boepd in 2014, $30,000/boepd in 2015, $35,000/boepd in 2016 & 2017, and $40,000/boepd in 2018 & 2019.

TRANSACTION PRODUCTION MULTIPLES(3) TRANSACTION ADJUSTED NET ACRE MULTIPLES(3,4)

GROSS PRODUCTION

16

April 15, 2019

328456

551666

523 510

681

824 807

346 394478

108

Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19

H V+D

Item Value Wkly Change Last Week Item Value Wkly Change Last Week

Rig Count 77 (1) 78 Oil Differential ($1.25) ($0.75) ($0.50)

Permitting Activity 12 (139) 151 Gas Differential ($0.73) ($0.11) ($0.61)

0%

5%

10%

15%

20%

--

50

100

150

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

H V+D % of Total Rigs

-$1.00

-$0.50

$0.00

$0.50

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

-$20.00

-$10.00

$0.00

$10.00

$ /

mm

btu

$ /

bb

l

Clearbrook CIG

11,500

12,000

12,500

13,000

13,500

14,000

400

500

600

700

800

900

Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18

mm

cf/

d

mb

bl/

d

Oil Gas

841

13,150

--$20,000$40,000$60,000$80,000

$100,000$120,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

2 0 4 4 1 6 2 0 1 6 3 9 3 1 3 1 1 0

$ /

bo

e/d

# Deals

$37,548

--

$5,000

$10,000

$15,000

$20,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

0 0 3 3 0 1 1 0 1 0 1 5 2 0 2 1 0 0

$ /

acre

# Deals

$4,655

Ann'd

Date Buyer Seller Asset Description Value(1)

Proved

Multiple

Prod.

Multiple Net Acres

($mm) ($/boe) ($/boe/d) ($/acre)(2)

14-Feb-19 Undisclosed Buyer Harvest Oil & Gas Corp San Juan Basin assets $43 $1.57 $10,835 n.a.

31-Jan-19 Undisclosed Buyer Extraction Oil & Gas 5,000 net acres in Powder River $22 n.a. n.a. $4,480

01-Oct-18 DJR Energy LLC Encana 182,000 net acres in San Juan Basin $480 n.a. $88,889 $2,637

28-Aug-18 Vermilion Energy Inc Massif Oil & Gas LLC 55,000 acres in Powder River Basin $150 n.a. $56,604 $2,727

28-Aug-18 Rebellion Energy II LLC Liberty Resources II LLC 19,000 net acres in Powder River Basin $100 n.a. n.a. $5,263

Mean $159 $1.57 $52,109 $3,777

Median $100 $1.57 $56,604 $3,604

Blue = BMO provided transaction advisory services Green = BMO provided acquisition financing or related services

Purple = BMO provided both transaction advisory services and acquisition financing or related services

TRANSACTION ACTIVITY (EXCLUDES CORPORATE DEALS)

PERMITTING ACTIVITY BY MONTH

DIFFERENTIALS

Rockies (excl. Bakken) Snapshot

RIG COUNT

Source: BMO Transaction Database, Baker Hughes, BMO Commodity Products Group, Bloomberg, Drilling Info, PLS

Note: Current quarter’s data is through the week covered by this issue.

1. Represents total enterprise value. Excludes transactions with deal value <$20 million. 2. $/acre multiple not adjusted for value associated with production.

3. Red line denotes average since 01-Jan-17. Calculated as the weighted average of each quarter’s transactions.

4. Production valued at $45,000/boepd in 2014, $30,000/boepd in 2015, $35,000/boepd in 2016 & 2017, and $40,000/boepd in 2018 & 2019.

TRANSACTION PRODUCTION MULTIPLES(3) TRANSACTION ADJUSTED NET ACRE MULTIPLES(3,4)

GROSS PRODUCTION

17

April 15, 2019

366 355

438380

426388

335327 303

339288

341

98

Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19

H V+D

Item Value Wkly Change Last Week Item Value Wkly Change Last Week

Rig Count 115 (2) 117 Oil Differential -- -- --

Permitting Activity 22 (70) 92 Gas Differential ($0.72) ($0.07) ($0.65)

0%

5%

10%

15%

20%

--

100

200

300

400

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

H V+D % of Total Rigs

-$1.00

-$0.75

-$0.50

-$0.25

$0.00

$0.25

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

-$1.00

-$0.75

-$0.50

-$0.25

$0.00

$0.25

$ /

mm

btu

$ /

bb

l

Cushing Panhandle

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

400

450

500

550

600

650

700

Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18

mm

cf/

d

mb

bl/

d

Oil Gas

598

8,670

--

$5,000

$10,000

$15,000

$20,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

1 3 1 2 0 3 3 2 4 1 2 1 0 0 0 1 0 0

$ /

acre

# Deals

$5,760

--

$50,000

$100,000

$150,000

$200,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

1 4 1 3 1 6 3 1 4 2 4 5 2 2 5 4 1 0

$ /

bo

e/d

# Deals

$44,453

Ann'd

Date Buyer Seller Asset Description Value(1)

Proved

Multiple

Prod.

Multiple Net Acres

($mm) ($/boe) ($/boe/d) ($/acre)(2)

19-Feb-19 Mid-Con Energy Partners Scout Energy Partners Caddo, Grady, and Osage cos., OK $28 n.a. $20,960 n.a.

31-Dec-18 Unit Corp Undisclosed Seller ~8,700 net acres in Western OK $30 $11.38 n.a. $3,402

11-Dec-18 Undisclosed Buyer Riviera Resources Inc 37,000 net acres in the Arkoma Basin $68 n.a. $17,000 $1,838

02-Nov-18 SandRidge Energy Undisclosed Seller Mississippi Lime and NW STACK assets $25 n.a. $6,649 n.a.

31-Oct-18 Casillas Petroleum Corp Sheridan Production Partners 29,600 net acres in SCOOP assets $260 n.a. $78,078 $8,784

Mean $82 $11.38 $30,672 $4,675

Median $30 $11.38 $18,980 $3,402

Blue = BMO provided transaction advisory services Green = BMO provided acquisition financing or related services

Purple = BMO provided both transaction advisory services and acquisition financing or related services

Mid-Continent Snapshot

TRANSACTION ACTIVITY (EXCLUDES CORPORATE DEALS)

PERMITTING ACTIVITY BY MONTH

DIFFERENTIALS RIG COUNT

Source: BMO Transaction Database, Baker Hughes, BMO Commodity Products Group, Bloomberg, Drilling Info, PLS

Note: Current quarter’s data is through the week covered by this issue.

1. Represents total enterprise value. Excludes transactions with deal value <$20 million. 2. $/acre multiple not adjusted for value associated with production.

3. Red line denotes average since 01-Jan-17. Calculated as the weighted average of each quarter’s transactions.

4. Production valued at $45,000/boepd in 2014, $30,000/boepd in 2015, $35,000/boepd in 2016 & 2017, and $40,000/boepd in 2018 & 2019.

TRANSACTION PRODUCTION MULTIPLES(3) TRANSACTION ADJUSTED NET ACRE MULTIPLES(3,4)

GROSS PRODUCTION

18

April 15, 2019

2733

29 2932 33

39

32 30 32 33

26

9

Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19

Item Value Wkly Change Last Week Item Value Wkly Change Last Week

Rig Count 23 1 22 Oil Differential $6.50 ($0.05) $6.55

Permitting Activity 2 (7) 9 Gas Differential -- -- --

0%

5%

10%

15%

20%

--

10

20

30

40

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

Deep Water Shelf % of Total Rigs

--

$2.00

$4.00

$6.00

$8.00

$10.00

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

--

$2.00

$4.00

$6.00

$8.00

$10.00

$ /

mm

btu

$ /

bb

l

LLS Henry Hub

2,000

2,500

3,000

3,500

4,000

4,500

1,000

1,200

1,400

1,600

1,800

2,000

2,200

Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18

mm

cf/

d

mb

bl/

d

Oil Gas

1,744

2,708

--

$10

$20

$30

$40

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

0 0 1 0 0 0 2 1 0 0 0 1 2 1 0 1 1 0

$ /

bo

e

# Deals

$18.10

--

$15,000

$30,000

$45,000

$60,000

$75,000

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

0 0 1 1 0 0 2 0 0 0 0 1 2 2 2 1 1 1

$ /

bo

e/d

# Deals

$35,001

Ann'd

Date Buyer Seller Asset Description Value(2)

Proved

Multiple

Prod.

Multiple Net Acres

($mm) ($/boe) ($/boe/d) ($/acre)(3)

11-Apr-19 Delek Group Shell 22.45% WI in Caesar-Tonga Field $965 n.a. $60,540 n.a.

16-Jan-19 Talos Energy Inc Samson Energy Co LLC Non-op Gulf of Mexico working interest $30 $13.45 $17,939 n.a.

10-Oct-18 Murphy Petrobras Gulf of Mexico joint venture $900 $15.00 $21,951 n.a.

04-Sep-18 Talos Energy Inc Whistler Energy II LLC Leases in Green Canyon federal waters $91 n.a. $60,667 n.a.

27-Apr-18 Stone Energy Shell; ExxonMobil; Anadarko GOM Ram Powell assets $234 n.a. $38,361 n.a.

Mean $444 $14.23 $39,891 n.a.

Median $234 $14.23 $38,361 n.a.

Blue = BMO provided transaction advisory services Green = BMO provided acquisition financing or related services

Purple = BMO provided both transaction advisory services and acquisition financing or related services

Gulf of Mexico Snapshot

PERMITTING ACTIVITY BY MONTH(1)

DIFFERENTIALS RIG COUNT

Source: BMO Transaction Database, Baker Hughes, BMO Commodity Products Group, Bloomberg, Drilling Info, PLS

Note: Current quarter’s data is through the week covered by this issue.

1. Permits include directional and unidentified drilling permits. 2. Represents total enterprise value. Excludes transactions with deal value <$20 million.

3. $/acre multiple not adjusted for value associated with production.

4. Red line denotes average since 01-Jan-17. Calculated as the weighted average of each quarter’s transactions.

GROSS PRODUCTION

TRANSACTION ACTIVITY (EXCLUDES CORPORATE DEALS)

TRANSACTION PRODUCTION MULTIPLES(4) TRANSACTION PROVED RESERVE MULTIPLES(4)

19

April 15, 2019

Upcoming Industry Events

Disclaimer: The foregoing links are for convenience only and relate to materials that were not prepared or reviewed by BMO Capital Markets. BMO Capital Markets takes

no responsibility for and makes no representations with respect to the contents thereof. These materials may be inconsistent with the views of BMO Capital Markets.

Click event to open

July 2019 Jul 10 Houston Producers Forum Luncheon

Jul 19 ADAM-Houston Monthly Luncheon

April 2019 Apr 15 DUG Sand (Fort Worth)

Apr 15 DUG Water (Fort Worth)

Apr 15-17 DUG Permian (Fort Worth)

Apr 16 Houston Producers Forum Luncheon

Apr 17 SPE Business Development Event

Apr 22-23 Mineral & Royalty Conference

ADAM-Houston Monthly Luncheon – 3rd Friday

Houston Producers Forum Luncheon – 3rd Tuesday

Note: Event features a speaker from BMO

Houston’s A&D Group.

May 2019 May 1 HPF/SPE YP Crawfish Boil

May 6-9 Offshore Technology Conference

May 10 Petroleum Resources Economics Conference

May 13-17 SPE Electric Submersible Pumps Symposium

May 14-15 DUG Rockies (Denver)

May 16 IADC Drilling Onshore Conference & Exhibition

May 17 ADAM-Houston Monthly Luncheon

May 21 Houston Producers Forum Luncheon

June 2019 Jun 5-6 Midstream Texas Conference & Exhibition

Jun 18 Houston Producers Forum Luncheon

Jun 18-20 DUG East (Pittsburgh)

Jun 19-20 IADC World Drilling Conference & Exhibition

Jun 21 ADAM-Houston Monthly Luncheon

Jun 24-26 IPAA Midyear Meeting

Jun 25 176th OPEC Meeting

August 2019 Aug 16 ADAM-Houston Monthly Luncheon

Aug 20 IPAA Oil & Gas Overview Course

Aug 20 Houston Producers Forum Luncheon

Aug 21-22 Summer NAPE

September 2019 Sep 17 Houston Producers Forum Luncheon

Sep 20 ADAM-Houston Monthly Luncheon

Sep 24-26 DUG Eagle Ford (San Antonio)

Sep 30-Oct 2 SPE Annual Technical Conference and Exhibition

January 2019 Jan 31 SPE A&D Symposium

October 2019 Oct 9 IPAA Leaders in Industry Luncheon

Oct 15 Houston Producers Forum Luncheon

Oct 18 ADAM-Houston Monthly Luncheon

Oct 22-23 A&D Strategies and Opportunities Conference

2020

Apr 20-22 OGIS New York

Jul 22-24 SPE Unconventional Resources Technology

Aug 11-14 Enercom Oil & Gas Conference

November 2019 Nov 4-6 Executive Oil Conference & Exhibition

Nov 15 ADAM-Houston Monthly Luncheon

Nov 19 IPAA Oil & Gas for Newcomers

Nov 19 Houston Producers Forum Luncheon

Nov 19-21 DUG Midcontinent (Oklahoma City)

December 2019 Dec 17 Houston Producers Forum Luncheon

Dec 20 ADAM-Houston Monthly Luncheon

January 2019 Jan 15 Houston Producers Forum Luncheon

Jan 25 ADAM-Houston Monthly Luncheon

Jan 24 IPAA Private Capital Conference

Jan 31 SPE A&D Symposium

March 2019 Mar 26-28 International Petroleum Technology Conference

January 2020 Jan 23 IPAA Private Capital Conference

Jan 17 ADAM-Houston Monthly Luncheon

Jan 21 Houston Producers Forum Luncheon

February 2020 Feb 19 Houston Producers Forum Luncheon

Feb 25-26 DUG Haynesville (Shreveport)

20

April 15, 2019

SCOOP/STACK/Merge

DJ-Niobrara

Eagle Ford

Haynesville

Granite Wash

GOM

Permian

Marcellus

Utica

Williston

Gulf Coast Onshore

Piceance

Powder River Green River

Legend

Current

Change

This material is prepared by the BMO Capital Markets’ Investment and Corporate Banking Department, for distribution to BMO Capital Markets’ clientele. It is not a product of

BMO Capital Markets’ Research Department. The views of the Investment and Corporate Banking Department may differ from those of the Research Department.

BMO Capital Markets is a trade name used by BMO Financial Group for the wholesale banking businesses of Bank of Montreal, BMO Harris Bank N.A. (member FDIC), Bank of Montreal

Ireland p.l.c, and Bank of Montreal (China) Co. Ltd and the institutional broker dealer businesses of BMO Capital Markets Corp. (Member FINRA and SIPC) in the U.S., BMO Nesbitt

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trademark of Bank of Montreal in the United States, Canada and elsewhere. ™ Trademark of Bank of Montreal in the United States and Canada.

Bank of Montreal or its subsidiaries (“BMO Financial Group”) has lending arrangements with, or provide other remunerated services to, many issuers covered by BMO Capital Markets.

The opinions, estimates and projections contained in this report are those of BMO Capital Markets as of the date of this report and are subject to change without notice. BMO Capital

Markets endeavors to ensure that the contents have been compiled or derived from sources that we believe are reliable and contain information and opinions that are accurate and

complete. However, BMO Capital Markets makes no representation or warranty, express or implied, in respect thereof, takes no responsibility for any errors and omissions contained

herein and accepts no liability whatsoever for any loss arising from any use of, or reliance on, this report or its contents. Information may be available to BMO Capital Markets or its

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objectives, should not be construed as advice designed to meet the particular investment needs of any investor. This material is for information purposes only and is not an offer to sell or

the solicitation of an offer to buy any security. BMO Capital Markets or its affiliates will buy from or sell to customers the securities of issuers mentioned in this report on a principal basis.

BMO Capital Markets or its affiliates, officers, directors or employees have a long or short position in many of the securities discussed herein, related securities or in options, futures or

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sell securities of issuers discussed herein.

All values in this document are in US$ unless otherwise specified.

Source of rig count stats: Baker Hughes

Rig Count Summary

MAPS IN

MASTER VIEW

Contacts

Disclaimer

Geoff Roberts

MD & Co-Head of U.S. A&D

713-518-1268

geoff.roberts@bmo.com

Jason Martinez

MD & Co-Head of U.S. A&D

713-546-9771

jason.martinez@bmo.com

Howard Barnwell

MD & Transactions Mgr.

713-546-9767

howard.barnwell@bmo.com

Rob Priske

MD & Transactions Mgr.

713-546-9727

rob.priske@bmo.com

Marian Yu

Associate

Aaron Moeller

Associate

Chelsea Neville

Transactions Coordinator

BMO uses updated basin outlines, and the resulting rig counts, to more accurately represent current basin knowledge. The data below reflect these changes

and is different than those shown by Baker Hughes. The totals are the same.

464

2

61

--

18

3

63

(6)30

(1)

23

1

14

184

(3)

66

(2)

93

(1)

20

3

4

--

23

--18

--

[TBU]

This

Week Change

Last

Week

Last

Year

Total Rigs 1,022 (3) 1,025 1,008

Oil 833 2 831 815

Gas 189 (5) 194 192

Miscellaneous -- -- -- 1

Directional 78 8 70 70

Horizontal 889 (12) 901 883

Vertical 55 1 54 55

Basin

Permian 464 2 462 445

SCOOP/STACK/Merge 84 (3) 87 107

Granite Wash 14 1 13 19

Eagle Ford 93 (1) 94 93

Haynesville 66 (2) 68 61

Marcellus 63 (6) 69 55

Utica 18 3 15 25

Williston 61 -- 61 55

DJ-Niobrara 30 (1) 31 24

Green River 18 -- 18 20

Powder River 23 -- 23 15

Piceance 4 -- 4 7

Gulf Coast Onshore 20 3 17 22

GOM 23 1 22 16

Alaska 8 -- 8 8

Other 33 -- 33 36

Mid-Con 17 -- 17 18

Rockies 2 -- 2 3

Western 13 -- 13 15

Eastern 1 -- 1 --