Mercer Capital's Value Focus: Exploration and Production | Fourth Quarter 2022 | Region Focus: Appalachian Basin

BUSINESS VALUATION &
FINANCIAL ADVISORY SERVICES
VALUE FOCUS
Exploration & Production
Fourth Quarter 2022 // Region Focus: Appalachian Basin
EXECUTIVE SUMMARY
Production in the Marcellus & Utica held steady in 2022 despite historically high commodity price volatility driven by the Russian-Ukraine war, the sabotage of
the Nord Stream pipelines, and rising LNG exports to Europe to stave-off potential winter heating shortages. The Q4 Appalachian rig count is at a level beyond
that needed for production volume maintenance, so there would seem to be at least some potential for Henry Hub price reductions going into 2023. However, the
demand for new natural gas supplies to Europe provides a countervailing wind to any potential downward movement in natural gas prices. In the end, the natural
gas markets seem to be in the midst of a series of events that promise continued supply and demand shifts with no certainty as to where the market will go in 2023.

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In This Issue
Oil and Gas Commodity Prices 1
Macro Update
Appalachian Gas Valuations: A Beautiful 2
Future Emerges From An Ugly Past
Region Focus: Appalachian Basin 8
Production and Activity Levels 8
Financial Performance 10
Market Valuations Transaction History 11
Shareholder Value Creation 11
Abounds; ESG Interest Waning
Sitio Royalties and Brigham Minerals, 12
Inc. Merge to Create the Largest
Public Minerals Owner
EQT Corporation Continues to Add 13
to Core Marcellus Asset Base
Northern Oil and Gas, Inc. Acquires 14
Non-Operated Appalachian Assets
Selected Public Company Information 15
Production 19
Rig Count 20
Industry Segments
Mercer Capital serves the following industry segments:
• Exploration Production
• Oil Field Services
• Midstream Operations
• Alternative Energy
• Downstream
• Retail
Contact Us
Bryce Erickson, ASA, MRICS
214.468.8400
ericksonb@mercercapital.com
Dallas Office
Don Erickson, ASA
214.468.8400
ericksond@mercercapital.com
Dallas Office
J. David Smith, ASA, CFA
713.239.1005
smithd@mercercapital.com
Houston Office
Andrew B. Frew, ASA, ABV
832.966.0345
frewa@mercercapital.com
Houston Office
Sebastian S. Elzein
214.468.8400
elzeins@mercercapital.com
Dallas Office
Thomas G. Kasierski
281.378.1510
kasierskit@mercercapital.com
Houston Office

© 2023 Mercer Capital // Business Valuation Financial Advisory Services // www.mercercapital.com 1
Mercer Capital’s Value Focus: EP Industry // Fourth Quarter 2022 @MercerEnergy
Henry Hub natural gas front-month futures prices have experienced significant volatility over last year. 2022 Prices
began on a general upswing before rising sharply as the market reacted to Russia’s invasion of Ukraine in late Feb-
ruary. As Russia subsequently began leveraging its natural gas supplies against Europe in retaliation of Europe’s
response to the war in Ukraine, natural gas prices became notably more volatile. They rose from an early March low
of $4.56 to an early June high of $9.29 — only to drop back to $5.39 in late June and then hit a 2022 high of $9.42 in
late August. By mid-December, Henry Hub had declined, albeit with only lightly reduced volatility, to $5.79.
2022 Oil prices, as benchmarked by West Texas Intermediate (WTI) and Brent Crude (Brent), also started on a steady
upward trend that took the WTI from $76/bbl to $88/bbl and the Brent from $79/bbl to $91/bbl, prior to the Russian
invasion. As the reality of the Russian-Ukraine war took hold, the oil benchmarks showed a marked uptick in volatility
that lasted into mid-May, with prices hitting highs of $120/bbl and $128/bbl and lows of $93/bbl and $96/bbl. Since
then, WTI and Brent prices have trended downward, exhibiting more typical volatility than the modest rallies in August
and October. As of mid-December, WTI sat at $73/bbl and Brent at $78/bbl.
Oil and Gas
Commodity
Prices
Crude Oil and Natural Gas Prices
$0
$2
$4
$6
$8
$10
$12
-$60
-$40
-$20
$0
$20
$40
$60
$80
$100
$120
$140
12/29/17
6/29/18
12/29/18
6/29/19
12/29/19
6/29/20
12/29/20
6/29/21
12/29/21
6/29/22
12/29/22
Dollars
per
Million
Btu
Dollars
per
Barrel
WTI Brent Henry Hub
Source: Bloomberg

Macro Update Three years ago, I wrote an article about the state of valuations for Appalachian gas companies. I used imagery from
Sergio Leone’s classic: The Good, The Bad, and The Ugly as a theme. At the time bad and ugly dominated over the
good. Henry Hub prices were hovering around $2 per mcf. Valuations were depressed and Appalachian gas pro-
ducers were struggling. Clint Eastwood would have lost that climactic gunfight if that world had remained.
It has not remained.
Today’s solid earnings and strong balance sheets are a far cry from what they were then. Stock prices have risen
alongside a fresh confidence that $4 and $5 gas prices will be sustainable for a while. Mercer Capital’s sector sta-
tistics tell the story. This is an archived snapshot of these producers in 2019:
This is the end of 2022:
Appalachian Gas
Valuations: A Beautiful
Future Emerges From
An Ugly Past
Reprint of Bryce Erickson’s
Forbes.com column.
Originally published December 30, 2022
Source: Cap IQ
Source: Cap IQ

Macro Update
(cont.)
A lot has changed in the past three years that has strengthened and stabilized stock prices, margins, earnings mul-
tiples, and production multiples alike. The Appalachian public comp group saw markedly strong stock price perfor-
mance over the past year (through December 28th), led by Antero and EQT. The remaining members of the comp
group showed more modest 1-year price increases. Stock prices dipped in mid-September but reversed direction
immediately following the sabotage of the Nord Stream pipelines in the Baltic Sea that transport Russian natural gas
to northern Europe.
Antero and EQT led the way among this group for several reasons. For Antero, one reason appears to have been its
lack of hedging for 2023, which has allowed it greater exposure to the uptick in gas prices and has allowed Antero to
be aggressive in paying down debt. EQT, on the other hand, does have more near-term hedging ceilings to deal with.
However, its strength is in its operational efficiencies, whereby their recent literature demonstrates breakeven oper-
ating expenses at $1.37 per mcf. This is among the lowest in the industry and allows them to accumulate cash flow.
Today’s future for this group looks very bright indeed.
The Past
In 2020 it looked like the bad and ugly would hang around indefinitely.
Within about 70 days of my Appalachian gas article being published, the world was whipsawed between the COVID-19
outbreak and the OPEC+ impasse between Saudi Arabia and Russia. Energy markets went into a tailspin. It looked
like the bad and the ugly would continue to reign, and they did especially for Marcellus gas producers. Incredibly,
Henry Hub prices dropped below $2 for much of the first and second quarter of 2020. Entire economies froze in their
tracks as they tried to absorb this new reality. Infrastructure along with it; the Atlantic Coast Pipeline was canceled on
July 5th. Then the Biden administration came to power and rhetoric opposing fossil fuels escalated. Producers like
Antero, EQT, and Range were stuck in neutral and fighting to increase production and financial efficiency amid the
continuing low-price environment. 2020 was spent stuck in the proverbial mud.
However, beneath the surface, some structural and fundamental shifts were starting to take place. First, production
growth slowed. This was not only in response to temporary demand drops due to the economic shocks of COVID. It
was also a response to tight debt markets that were pulling back on exposure to the sector. Capex was harder to get
funded. The market’s message was clear: make the most of what you have now. The era of shale growth was ending,

Macro Update
(cont.)
and the era of production efficiency and moderation was taking shape. This dynamic coincided with the larger past 40
years of steady growth – known by some as the period of Great Moderation – that was ending. The new world would
be shaped by production constraints.
Second, industry began to onshore again in the U.S. Over the course of decades past, industrial investment flowed
out of the US mostly due to lower labor costs elsewhere. Low-cost gas has upturned that equation. Over $200 billion
is in process of being spent on new and expanded US chemical related factories that use gas as a raw material for
making chemicals, more than offsetting higher labor costs. Tens of billions more started going into steel making and
other manufacturing plants seeking lower-cost electricity. Companies ranging from BAE Systems to Samsung to
John Deere began shifting back onshore to the U.S. Every major car maker shifted plans to spend billions in the US
to build EV factories.
Thirdly, around the same time, another shift was happening. Executive compensation moved more in line with
investors. Management incentives moved further away from production incentives and more towards financial perfor-
mance and capital efficiency metrics. While
prices were still hovering around $2 per mcf,
equity investors demanded changes and
wanted cash flow statements to “shift prior-
ities” so to speak. LNG export capability was
coming online and equity investors wanted to
be ready for it.
Otherwise, 2021 slugged along with these
dynamics churning in the background, often-
times very quietly. Gas prices started to drift
upward, and business, airline, and driving
activities all picked up. One very interesting
market dynamic, however, was the rising
overseas gas prices compared to Henry Hub
which widened as the year went along.
By the end of 2021, the table had been set for 2022’s resurgence.
Source: IEA

Macro Update
(cont.)
The Present
Although the Russian Invasion of Ukraine has been the headliner, other trends and framework were being set-up in
the second half of 2021. Europe realized it had made a grave mistake, that will need to partially be fixed with Appa-
lachian natural gas.
Now, in Europe, prices remain incredibly high, particularly for early 2023. When the cold weather finally hits, there
remain concerns Europe could quickly burn through its gas reserves, potentially still leading to extreme tightness in
supplies throughout the winter. Gas at around €115 per megawatt hour is still equivalent to almost $180 per barrel in
oil terms. Contracts for January have been above $230 per barrel equivalent.
In addition, Europe has exhausted almost every available source of gas, from increased LNG imports to asking
Norway to maximize production for months. At this point, there is little in the way of supply additions expected globally
until the middle of this decade. The EU will boost its ability to import LNG through floating terminals in Germany and
the Netherlands, but they’ll be competing for the same limited pool of supply. And without Russian gas, the EU will
need even more LNG over the next 12 months.
Germany finished construction of its first import terminal for LNG, a crucial milestone in its efforts to end its energy
dependency on Russia. However, Europe could still face a 30bn cubic-meter shortfall during next summer’s key
storage refilling period if Russia halts all pipeline deliveries and Chinese demand for liquefied natural gas increases
as it lifts coronavirus restrictions, according to the International Energy Agency.
The US will supply some of that LNG when more export facilities are built. One important happening in March 2023 will
be the reopening of the Freeport LNG terminal which has been closed for several months due to an accident there. In
normal times that terminal handles around 15% of US LNG exports.
That leaves hidden demand to fill that had not been apparent until this year. In fact, a few weeks ago Russian Deputy
Prime Minister Alexander Novak told state television that Russia may cut oil production by between 5%-7% in early
2023 in response to the price cap imposed by Western countries on its crude oil and refined products. This is bound
to have a ripple effect. U.S. natural gas prices have been above $4 per mcf all year and above $5 per mcf since March
with a few brief spikes above $9. Appalachian Basin pricing is also tightening closer to NYMEX futures.

Macro Update
(cont.)
There have been modest increases in rigs and drilling from both EPs and contractors, but this is mostly in the high
single or low double-digit variety. This is being done amid confidence that price increases this past year won’t be
temporary:
Appalachian production held steady in 2022 despite historically high commodity price volatility driven by the Rus-
sian-Ukraine war, the sabotage of the Nord Stream pipelines, and rising LNG exports to Europe to stave-off potential
winter heating shortages.
On an interesting note, valuations for the publics are remarkably tight. Price to earnings ratios are between 5.0 – 5.5x
with the exception of EQT. Other metrics have risen and are healthier than they were, but P/E ratios are the tightest.
Earnings are king right now.
Source: Federal Reserve Bank of Dallas, EIA

Macro Update
(cont.)
The Future
Europe is going to de-industrialize and thus energy demand will diminish as they move heavier towards a service
economy. The EU made a mistake relying on Russia and did not diversify. Now they are paying the price for it. The
world got complacent on cheap oil and gas due, in part, to the shale revolution.
Now supply markets are on edge. Saudi Aramco CEO Amin Nasser warned recently that LNG gas supply is a “hiccup”
away from exposing how fraught the markets really are, and that “there is no spare capacity available on the market.
These are all long-term contracts. So, it’s a much bigger issue for gas and LNG than crude. Solar, wind, and other
renewables are not ready, yet, to shoulder a bigger portion of the energy requirement.” Charif Souki, Chairman of the
Board at Tellurian, thinks $4-5 mcf gas should be here to stay, with plenty of the commodity at this price. The main
problem will be the infrastructure to transport it.
There are risks. No business is without these and, putting aside the risk of Putin causing a world war, the primary one
is a glut of gas hitting the world market. Qatar is a huge supplier and is investing heavily to produce more. They signed
a big contract to supply Germany with LNG. Since that gas only starts to flow in 2026 it is no threat in the near term
and is only a small part of German and global needs. Domestically, all the drilling for oil at high prices this past year
(adding over 100 rigs) has produced a lot of associated gas. East Daley Capital Analytics forecasts 4.6 Bcf/d from
now to the end of 2023. However, East Daley is bullish on LNG in the long haul for Europe and the rest of the world.
The current Appalachian rig count is at a level beyond that needed for production volume maintenance, so there would
seem to be at least some potential for Henry Hub price reductions going into 2023. However, the demand for new
natural gas supplies to Europe provides a countervailing wind to any potential downward movement in natural gas
prices. In the end, the natural gas markets seem to be amid a series of events that promise continued supply and
demand shifts with no certainty as to where the market will go in 2023.
In the meantime, the cautious efficiency is paying off for Appalachian gas producers, and with the wounds from 2019-
2020 healing, the future looks very good indeed.

The economics of oil and gas production varies by region. Mercer Capital focuses on trends in the Eagle Ford,
Permian, Bakken, and Appalachia plays. The cost of producing oil and gas depends on the geological makeup of
the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in dif-
ferent regions depending on these factors. This quarter we take a closer look at the Appalachian Basin.
Estimated Appalachian production (on a barrels of oil equivalent, or “boe” basis) decreased approximately 1% year-
over-year through late December. Production in the Eagle Ford, Permian, and Bakken increased 16%, 11%, and 5%
year-over-year, respectively. Despite a much-improved year-over-year commodity price environment, Appalachian
production was fairly stable, largely due to high price volatility over the year, which left the markets uncertain as to
where prices would be going forward.
Appalachian
Basin
Production and Activity
Levels
1-Year Change in Production
-25.0%
-20.0%
-15.0%
-10.0%
-5.0%
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
D
e
c
-
2
1
J
a
n
-
2
2
F
e
b
-
2
2
M
a
r
-
2
2
A
p
r
-
2
2
M
a
y
-
2
2
J
u
n
-
2
2
J
u
l
-
2
2
A
u
g
-
2
2
S
e
p
-
2
2
O
c
t
-
2
2
N
o
v
-
2
2
D
e
c
-
2
2
Bakken Eagle Ford Permian Appalachia
Source: EIA

Rig counts continued to climb in all four basins over the last year. Growth rates in the Appalachian and Permian
basins were more modest, while rates for the Bakken and Eagle Ford basins were notably higher. The Appalachian
rig count rose 30% from 40 to 52 rigs. Among the oil-focused basins, the Eagle Ford led with a 71% increase from 42
to 72 rigs. The Bakken followed with a 56% increase (27 to 42 rigs), while the Permian had the lowest increase with
a 24% increase (283 to 350 rigs).
Production and Activity
Levels (cont.)
1-Year Change in Rig Count
0%
10%
20%
30%
40%
50%
60%
70%
D
e
c
-
2
1
J
a
n
-
2
2
F
e
b
-
2
2
M
a
r
-
2
2
A
p
r
-
2
2
M
a
y
-
2
2
J
u
n
-
2
2
J
u
l
-
2
2
A
u
g
-
2
2
S
e
p
-
2
2
O
c
t
-
2
2
N
o
v
-
2
2
D
e
c
-
2
2
Bakken Eagle Ford Permian Appalachia Total
Source: Baker Hughes

The Appalachian public comp group saw markedly strong stock price performance over the past year (through
December 12th), led by Antero and EQT with price increases of 90% and 77% as of December 12th. The remaining
members of the comp group showed more modest 1-year price increases of 12% to 38%. Prices peaked in early June
for all members, except EQT, with year-to-date increases of 71% to 171%. EQT’s stock price peaked in mid-September
at a year-to-date increase of 143%. Stock prices fell sharply beginning in mid-September but reversed direction
immediately following the sabotage of the Nord Stream pipelines in the Baltic Sea that transport Russian natural gas
to northern Europe.
Antero and EQT led the way among this group for several reasons. For Antero, one reason appears to be its lack of
hedging for 2023, which allowed it greater exposure to the uptick in gas prices and to aggressively pay down debt.
EQT, on the other hand, does have more near-term hedging ceilings to deal with. However, its strength is in its opera-
tional efficiencies, whereby their recent literature demonstrates breakeven operating expenses at $1.37 per mcf. This
is among the lowest in the industry and allows them to accumulate cash flow.
Financial Performance
1-Year Change in Stock Price

Market Valuations Transaction History
Transactions in the Appalachian Basin 2021
Announced
Date Buyer Seller
Deal Value
($MM) Acreage $ /Acre $ / Mcfe/d
MMcf/Acre
(Annual)
5/6/21 EQT Corp
Alta Resources
Development, LLC
$2,925 300,000 $9,750 $2,925 1.22
3/23/21 LOLA Energy Undisclosed Seller Undisclosed 22,000 nm nm 1.41
2/3/21
Northern Oil and
Gas, Inc.
Reliance Industries
Limited
126 61,800 2,045 1,053 0.71
Median $1,526 61,800 $5,898 $1,989 1.22
Average $1,526 127,933 $5,898 $1,989 1.11
Source: Shale Experts and company filings
Transactions in the Appalachian Basin 2022
Announced
Date Buyer Seller
Deal Value
($MM) Acreage $ /Acre
$ /
Mcfe/d
MMcf/Acre
(Annual)
11/22/22
IOG Capital LP, IOG
Resources II, LLC
National Fuel Gas Co.
Seneca Resources
Undisclosed Undisclosed nm nm na
9/8/22 EQT Corp.
Tug Hill Operating, Xcl
Midstream
5,200 90,000 57,778 6,500 3.25
9/6/22 Sitio Royalties Brigham Minerals, Inc. 4,800 85,710 56,003 63,100 0.32
6/21/22 Undisclosed Riverbend Oil Gas 1,800 Undisclosed nm 6,821 na
1/25/22
Chesapeake
Energy Corp
Tug Hill Operating,
Chief ED Holdings
2,600 113,000 23,009 3,114 2.70
1/5/22 Repsol S.A. Rockdale 222 48,000 4,625 nm na
Median $2,600 87,855 $6,661 2.70
Average $2,924 84,178 $19,884 2.09
Source: Shale Experts and company filings
Through November 2021, there were three MA deals in the Marcellus and Utica shales, compared to 16 in the same
period in 2020, as companies that were looking to get into or out of the Appalachian basins effectively did so in 2020.
The following table summarizes transaction activity in the Marcellus and Utica shales in 2021:
MA activity picked up in 2022, with twice as many transactions announced so far as shown in the following table.
Shareholder Value
Creation Abounds;
ESG Interest Waning

Market Valuations
Transaction History
(cont.)
Sitio Royalties and
Brigham Minerals, Inc.
Merge to Create the
Largest Public
Minerals Owner
What has caused the slight rebound in MA activity in the Marcellus and Utica shales? Companies are focusing on
asset quality, strong balance sheets, prudent capital structures, and free cash flow growth. Below we examine the two
largest transactions that occurred in, but were not limited to, the Marcellus and Utica shales, during 2022.
On September 6, Sitio Royalties Corp. (NYSE: STR) (“Sitio”) and Brigham Minerals, Inc. (NYSE: MNRL) (“Brigham”)
announced a definitive agreement to combine, in an all-stock merger, with an aggregate enterprise value of approx-
imately $4.8 billion based on the closing share prices of Sitio and Brigham on September 2, 2022. The combination
brings together two of the largest public companies in the oil and gas mineral and royalty sector. Upon completion of
the merger, the combined entity will retain the name Sitio Royalties Corp.
Under the terms of the merger agreement, Brigham shareholders will receive a fixed exchange ratio of 1.133 shares
of common stock in the combined company for each share of Brigham common stock owned. Sitio’s shareholders
will receive one share of common stock in the combined company for each share of Sitio common stock, based on
ownership on the closing date. Brigham’s and Sitio’s Class A shareholders will receive shares of Class A common
stock in the combined company, and Brigham’s Class B and Sitio’s Class C shareholders will receive shares of Class
C common stock in the combined company. Upon completion of the transaction, the former Sitio shareholders will
own approximately 54% and the former Brigham shareholders will own approximately 46% of the combined entity on
a fully diluted basis.
Robert Rosa, CEO of Brigham, commented:
Our merger with Sitio creates the industry leading powerhouse in the minerals space … with approxi-
mately 100 rigs running across all of our operating basins and greater than 50 activity wells to continue
to drive production and cash flow growth.
The Sitio-Brigham deal press release discusses operational cash cost synergies, a balanced capital allocation
framework that aligns with shareholder interests to drive long-term returns, enhanced margins, and increased access
to capital. But, as a recent Forbes article points out, despite Kimmeridge Energy, which owns approximately 43.5%
of Sitio, being a heavy promoter of ESG in the shale business, the press release has only a slight mention of ESG. The
only direct mention of ESG is in the last bullet point of the strategic rationale behind the deal.

Market Valuations
Transaction History
(cont.)
N
1
EQT Corporation
Continues to Add to Core
Marcellus Asset Base
On September 8, EQT Corporation (NYSE:EQT) (“EQT”) announced that it entered into a purchase agreement with
THQ Appalachia I, LLC (“Tug Hill”) and THQ-XcL Holdings I, LLC (“XcL Midstream”) whereby EQT agreed to acquire
Tug Hill’s upstream assets and XcL Midstream’s gathering and processing assets for total consideration of $5.2 billion.
The purchase price consists of cash of $2.6 billion and 55 million shares of EQT common stock worth $2.6 billion.
Transaction highlights include:
» ~90,000 core net mineral acres offsetting EQT’s existing core leasehold in West Virginia
» 95 miles of owned and operated midstream gathering systems connected to every major long-haul interstate
pipeline in southwest Appalachia
» Combined upstream and midstream assets at 2.7x next-twelve-month (“NTM”) EBITDA
» Upstream-only valuation of 2.3x NTM EBITDA
» 300 untapped drilling locations in the Marcellus and Utica shales
The deal is the largest U.S. upstream deal since Conoco Phillips purchased Shell’s Permian Basin assets for $9.5
billion in September 2021.
EQT President and CEO Toby Rice commented:
The acquisition of Tug Hill and XcL Midstream checks all the boxes of our guiding principles around MA,
including accretion on free cash flow per share, NAV per share, lowering our cost structure and reducing
business risk, while maintaining an investment grade balance sheet.
The Tug Hill/XcL Midstream transaction piggybacks EQT’s May 2021 $2.93 billion acquisition of all of the mem-
bership interests in Alta Resources Development, LLC’s (“Alta’) upstream and midstream subsidiaries. Consistent
with his comments on the Tug Hill/Xcl Midstream deal, Mr Rice commented at the time that the Alta deal would provide
attractive free cash flow per share accretion to EQT shareholders.
As was the case with the Sitio-Brigham deal, Forbes points out that the EQT-Tug Hill- XcL Midstream press release
provides only a token reference to ESG in a quote by the CEO of Quantum Energy Partners, the .private equity
backers of Tug Hill and XcL Midstream.

Market Valuations
Transaction History
(cont.)
On February 3, Northern Oil and Gas (NYSEAM:NOG) agreed to acquire certain non-operated natural gas assets
in the Appalachian basin from Reliance Marcellus, LLC (“Reliance”), a subsidiary of Reliance Industries, Ltd., for total
consideration of $175 million in cash and approximately 3.25 million warrants to purchase shares of NOG common
stock at an exercise price of $14.00 per share. The transaction was expected to be funded through a combination
of equity and debt financings and anticipated to be leverage neutral on a trailing basis and leverage accretive on a
forward basis. At the effective date of July 1, 2020, the acquired assets were producing approximately 120 MMcfe/d
of natural gas equivalents, net to Northern Oil and Gas. The assets were expected to produce approximately 100,110
MMcfe/d (or approximately 19,000 Boe/d) in 2021, net to Northern Oil and Gas, and consisted of approximately 64,000
net acres containing approximately 102.2 net producing wells, 22.6 net wells in process, and 231.1 net undrilled loca-
tions in the core of the Marcellus and Utica plays.
Furthermore, an inventory of 94 gross highly-economic, work-in-progress (“WIP”) wells was slated for completion over
the following five years by EQT. As of the transaction announcement, approximately $50 million of net development
capital had already been deployed on the WIP wells, which was not subject to reimbursement by Northern Oil and
Gas. The acquisition complemented Northern Oil and Gas’s then-existing approximate 183,000 net acreage portfolio
in the Williston and Permian basins. As of year-end 2020, the acquired assets held an estimated 493 Bcf of proved
reserves, of which approximately 55% were comprised of PDP reserves, with PV-10 of $269 million (at strip pricing as
of January 20, 2021).
Nick O’Grady, Northern Oil and Gas’s CEO, commented:
This transaction furthers our goal of becoming a national non-operated franchise with low leverage, strong free
cash flow and a path towards returning capital to shareholders. With this transaction, we expect increased
opportunities to efficiently allocate capital and diversify risk, our commodity mix and geographic footprint.
Northern Oil and Gas,
Inc. Acquires Non-
Operated Appalachian
Assets

Mercer Capital tracks the performance of Exploration and Production companies across different mineral reserves in order to understand how the current pricing envi-
ronment affects operators in each region. We created an index of seven groups to better understand performance trends across reserves and the industry. The current
pricing multiples of each company in the index are summarized below.
Appendix A
Selected Public Company Information
as of 12/31/2022
Company Name Ticker
12/31/2022
Enterprise Value
YoY % Change in
Stock Price
EBITDAX
Margin
EV/
EBITDAX
Daily
Production
(mboe/d)
Price per Flowing
Barrel*
Global Integrated
Exxon Mobil Corp XOM $476,212 80.3% 21.4% 5.0x 3,782 $125,911
Shell PLC SHEL 250,049 27.6% 20.1% 3.2 2,840 88,044
Chevron Corp CVX 356,226 53.0% 23.6% 5.9 3,023 117,833
BP PLC BP 147,152 27.9% 17.3% 3.3 2,283 64,446
Equinor ASA EQNR 99,570 33.4% 56.7% 1.2 2,084 47,790
Group Median 33.4% 21.4% 3.3x 2,840 $88,044
Global EP
Marathon Oil Corporation MRO $20,180 64.9% 69.7% 3.7x 344 $58,693
Hess Corporation HES 50,820 91.6% 52.5% 8.5 367 138,588
ConocoPhillips COP 153,575 63.5% 44.9% 4.3 1,780 86,285
Occidental Petroleum Corporation OXY 87,257 117.3% 57.6% 4.1 1,230 70,930
APA Corporation APA 21,334 73.6% 59.7% 3.1 406 52,527
Murphy Oil Corporation MUR 9,230 64.7% 62.6% 3.7 183 50,316
Group Median 69.2% 58.6% 3.9x 386 $64,812
Source: Capital IQ
• Price per Flowing Barrel is EV/daily production ($/boe/d) EBITDAX Daily Production figures include quarterly estimates per Capital IQ as available
• We review 10-K’s and annual reports from guideline companies to ensure companies continue to operate in the regions and groups we have identified.
• CLR taken private effective 11/22/2022; CLR market data reflects day before close

as of 12/31/2022
Company Name Ticker
12/31/2022
Enterprise Value
YoY % Change in
Stock Price
EBITDAX
Margin
EV/
EBITDAX
Daily
Production
(mboe/d)
Price per Flowing
Barrel*
Bakken
Continental Resources, Inc.* CLR $31,440 64.6% 74.5% 3.8x 416 $75,666
Chord Energy Corp CHRD 5,466 8.6% 49.6% 3.1 172 31,690
Group Median 36.6% 62.07% 3.4x 294 $53,678
Appalachia
Range Resources Corporation RRC $8,086 40.3% 43.3% 5.3x 367 $22,008
EQT Corporation EQT 17,139 55.1% 46.0% 5.6 874 19,603
Coterra Energy Inc CTRA 21,292 29.3% 74.3% 3.1 631 33,754
Antero Resources Corporation AR 14,276 77.1% 41.7% 4.9 549 26,004
Southwestern Energy Company SWN 11,485 25.5% 18.5% 3.5 781 14,699
Group Median 40.3% 43.3% 4.9x 631 $22,008
Permian Basin
Diamondback Energy, Inc. FANG $31,123 26.8% 80.1% 4.3x 389 $80,025
Permian Resources Corporation PR 7,745 57.2% 74.1% 4.8 146 52,956
Callon Petroleum Company CPE 4,654 -21.5% 57.9% 2.6 107 43,659
Laredo Petroleum, Inc. LPI 1,978 -14.5% 58.3% 1.7 75 26,207
Pioneer Natural Resources Company PXD 58,031 25.6% 51.3% 4.6 663 87,484
Group Median 25.6% 58.3% 4.3x 146 $52,956
Source: Capital IQ
Appendix A

as of 12/31/2022
Company Name Ticker
12/31/2022
Enterprise Value
YoY % Change in
Stock Price
EBITDAX
Margin
EV/
EBITDAX
Daily
Production
(mboe/d)
Price per Flowing
Barrel*
Eagle Ford
EOG Resources, Inc. EOG $76,126 45.8% 47.2% 5.5x 927 $82,116
Magnolia Oil Gas Corporation MGY 4,302 24.3% 79.0% 3.2 77 55,726
SilverBow Resources, Inc. SBOW 1,269 29.9% 62.7% 3.1 55 23,099
Ranger Oil Corporation ROCC 1,874 50.2% 68.6% 2.4 46 40,961
Group Median 37.9% 65.6% 3.1x 66 $48,344
OVERALL MEDIAN 45.8% 56.7% 3.7x 416 $52,956
Source: Capital IQ
Appendix A

Price per Flowing Barrel
Appendix A
Selected Public
Company
Information
The following graph depicts the median of EV/production multiples, also known as price per flowing barrel, for Q1
through Q4 2022.
$0
$30,000
$60,000
$90,000
2022 Q1 2022 Q2 2022 Q3 2022 Q4
Source: Capital IQ

Appendix B
Production
Oil production in the Eagle Ford
and Permian both increased by
12.5% over the last year, while
oil production in the Appalachian
basins increased 10.4%. Year-
over-year growth in oil production
trailed in the Bakken at 1.9%.
The Eagle Ford led the analyzed
regions in natural gas production
growth at 21.8% over the last
year, while natural gas pro-
duction increased in the Bakken,
Permian, and Appalachia by
5.8%, 7.2%, and 1.5%, respec-
tively.
Daily Production of Crude Oil
0
1
2
3
4
5
6
Dec-17
Dec-18
Dec-19
Dec-20
Dec-21
Dec-22
mmbl/d
Source: EIA
0
5
10
15
20
25
30
35
40
Dec-17
Dec-18
Dec-19
Dec-20
Dec-21
Dec-22
mmcf/d
Source: EIA
Daily Production of Natural Gas
Source: EIA
Source: EIA

Appendix C
Rig Count
Rig Count by Region
Baker Hughes collects and publishes information regarding active drilling rigs in the U.S. and internationally. The
number of active rigs is a key indicator of demand for oilfield services equipment. Factors influencing rig counts
include energy prices, investment climate, technological changes, regulatory activity, weather, and seasonality.
The number of active rigs in the U.S. during December 2022 was 777, which represents a 32.6% increase from 586 in
December 2021, and 1.8% greater than 763 in September 2022. The rig count in the Marcellus Utica increased by
30.0% year-over-year, from 40 to 52 rigs.
1
Calculations based on monthly crude oil and gas production and EIA drilling report by region.
0
300
600
900
1,200
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Oil Gas
U.S. Rig Count by Oil vs. Natural Gas
Appendix C
Rig Count
U.S. Rig Count by Trajectory
0
200
400
600
800
1000
1200
Dec-17
Jun-18
Dec-18
Jun-19
Dec-19
Jun-20
Dec-20
Jun-21
Dec-21
Jun-22
Dec-22
Directional Horizontal Vertical

Mercer Capital
www.mercercapital.com

Mercer Capital's Value Focus: Exploration and Production | Fourth Quarter 2022 | Region Focus: Appalachian Basin

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