Mercer Capital's Value Focus: Energy Industry | Q1 2019 | Region Focus: Eagle Ford

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VALUE FOCUS
Exploration & Production
First Quarter 2019 // Region Focus: Eagle Ford
EXECUTIVE SUMMARY
After a sharp decline in crude prices and the stock market in general, the first quarter saw prices bounce back to finish
about halfway between their Q4 peak and trough. Concerns about economic slowdowns increased in the fourth quarter,
though these have subsided somewhat. The Federal Reserve indicated in March that it would not raise rates for the
rest of 2019, further easing concerns. OPEC production declines helped ease supply and raise prices, though U.S.
production has continued to grow. Despite this domestic growth, investors have shown a preference for returns and
capital discipline, not just surging growth.

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In This Issue
E&P Industry
Oil and Gas Commodity Prices 1
OPEC 2
Outlook for the Rest of 2019 3
Region Focus: Eagle Ford
Location, Location, Location 4
Free Cash Flow vs Growth Potential 6
End of the Eagle Ford? 7
Rig Counts and
Production 8
Valuation Implications 10
Market Valuations
Transaction Activity 11
Selected Public Company Information 16
Rig Count 19

© 2019 Mercer Capital // Business Valuation Financial Advisory Services // www.mercercapital.com 1
Mercer Capital’s Value Focus: EP Industry // First Quarter 2019 @MercerEnergy
Nearly a quarter of the way through 2019, prices have rebounded somewhat after a tumultuous end to 2018.
First quarter energy prices again moved in opposite directions, with crude prices increasing steadily over the period
and natural gas prices decreasing from $2.94 at the start of the year to $2.80 per Mcf by mid-March despite peaking
at over $3.50 in mid-January.
$0
$1
$2
$3
$4
$5
$6
$0
$20
$40
$60
$80
$100
$120
$140
3/31/14
9/30/14
3/31/15
9/30/15
3/31/16
9/30/16
3/31/17
9/30/17
3/31/18
9/30/18
3/31/19
DollarperMcf
DollarsperBarrel
WTI Brent Henry Hub
Source: Bloomberg
EP Industry
Oil and Gas
Commodity Prices
Crude Oil and Natural Gas Prices

EP Industry
OPEC
OPEC continues to impact prices, as it did in the first quarter by cutting production, but its influence may be waning.
The significant production increases in the United States have played a role, and when OPEC decreases supply to
raise prices, the U.S. obtains increased market share. In April, the group decided to table its April ministerial meeting
until June. This will keep production cuts in place until at least the next meeting, with the group’s reported reason
being to get a better read on the oil markets and how to manage supplies for the second half of the year. However,
there appear to be more structural issues with which OPEC must grapple.
The turn of the year saw Qatar drop out of OPEC after being a member since 1961. While the country produced rela-
tively less crude oil, it has significant production of LNG and was seen as an important diplomatic bridge, capable of
negotiating with regional rivals as one of the few member countries not in the Middle East. The departure is largely
viewed as symbolic and not likely to cause more groups to leave, though the situation remains tenuous. OPEC has
historically had issues with getting all member countries to stick to their agreements as they are economically disin-
centivized from cutting their production just to not benefit from the increased price it enables.
The largest players in the current supply cut agreement are Saudi Arabia and Russia, who is not even a member of
OPEC. OPEC delivered on its promises, though not necessarily intentionally, to decrease supply by 800 thousand
barrels per day (bpd). Sanctions and power outages played a role in this reduction, but Saudi Arabia voluntarily
dropped its production 220 thousand bpd in March from the prior month. Overall production for OPEC has dropped
to its lowest since 2015. It remains to be seen whether this will continue as Russia’s interest in maintaining these cuts
is not likely long-term, and Saudi Arabia likely will not want to shoulder this burden as all of the others benefit from
the increased prices. Supply cuts boost the price which is beneficial to members, though the U.S. appears to be the
largest benefactor of both higher prices received as well as increasing market share.

According to the latest Short-Term Energy Outlook, the EIA expects regular retail gasoline prices to average $2.76
per gallon during the upcoming summer driving season, down from $2.85 the prior year. Brent crude spot prices
averaged $66 per barrel in March, up $2 from February, and down $4 from the prior year. Prices are expected to trend
modestly downward as the EIA forecasts Brent spot prices will be $65 per barrel for 2019 and $62 for 2020. West
Texas Intermediate (WTI) crude oil prices will average about $8 dollar per barrel lower than Brent prices for the first
half of 2019, before the spread gradually trends down towards $4 in late-2019 and through 2020. More infrastructure is
expected to come online to ease these differentials, and production is expected to grow to an average of 12.4 million
barrels per day in 2019 and 13.1 million in 2020 fueled mostly by growth in the Permian.
Meanwhile Henry Hub natural gas spot prices averaged $2.95 per MMBtu in March, up 26 cents from February due to
colder than normal temperatures across the country. As the temperature warms up, prices are expected to drop, and
the EIA forecasts increased production will also cut prices to an average of $2.82 in 2019 and $2.77 in 2020. This is
a notable drop from the average of $3.15 in 2018.
EP Industry
Outlook for the
Rest of 2019

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 Eagle Ford region.
Location is crucial for oil and gas plays, particularly when looking at the acreage multiples paid across various regions.
The Eagle Ford Shale has quietly delivered solid results, overshadowed by some of the other shale plays, particularly
the Permian to the west. The Eagle Ford’s location provides a distinct advantage, however, as it is closer to higher
Brent-related pricing seen on the Gulf Coast. Its higher cut of oil also opens it up to Louisiana Light Sweet pricing.
Even though the attention on the Permian has increased both acreage multiples and congestion due to transportation
issues, it has been less of a concern in the Eagle Ford because the product has a shorter distance to travel to get
to market. In a time where Permian differentials were particularly wide in 2018, this pricing advantage was helpful to
Eagle Ford Shale producers.
While proximity to better pricing is clearly a boon, location within the region also plays a large role. Less choice areas
of the Eagle Ford may have higher breakevens, but overall the play, particularly its oil window, boasts among the
lowest costs in the country (particularly for shale plays), challenging the Permian in this respect. These low costs are
due to shallower wells, lower cost drilling, higher cuts (more oil and less water produced), and resultant premium com-
modity pricing near the Gulf Coast. The chart on the next page shows various breakeven estimates for the Eagle Ford
in the first quarter. Chesapeake’s $35-$45 range illustrates the variance within particular areas of the play.
Eagle Ford
Location, Location,
Location

The Eagle Ford has areas where the cost of supply is as low as $20 to $30 per barrel according to Greg Leveille,
Chief Technology Officer of ConocoPhillips. EOG Resources, the largest operator in the region, has noted similar
supply costs as well. According to Thomas Tunstall, senior researcher with UTSA’s Institute of Economic Devel-
opment, “EOG has some of the choicest leases in the Eagle Ford. They have indicated publicly that they can make
money at $30 per barrel.” This has a considerable impact particularly with WTI prices currently trading around double
that figure. Costs could be lower for operators in 2019 who are focused on producing from existing DUC wells such
as Murphy Oil.
Eagle Ford
Location, Location,
Location
(continued)
1Q19 Eagle Ford Breakeven (Estimates)
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
Credit Suisse - Oil Credit Suisse -
Gas/Condensate
Chesapeake - Low Chesapeake - High Carrizo
Source: Company Reports Investor Presentations

Eagle Ford
Free Cash Flow vs.
Growth Potential
Operators in the Eagle Ford have enjoyed the reliable production inherent in a later life-stage play. Along with the
pricing benefits as previously noted, companies that have operated in the region for a while have been able to benefit
from experience. Todd Abbott, Marathon Oil’s VP of Resource Plays South, attributed the company’s success in the
region to drilling innovation and efficiency and repeatability of a stable drilling program. He further noted, “We are
completing wells in a quarter of the time it took us to complete them in 2012.” This notion was furthered by Cono-
coPhillips’ CTO Leveille who touted innovations in well-spacing and stacking, which have allowed the company to
achieve a 20% field-level recovery factor in the Eagle Ford Shale.
Technical innovations and experience have led to free cash flow for operators, which is something investors have
been seeking. In fact, according to Marathon’s Abbott, the Eagle Ford has been able to effectively subsidize its
efforts in regions such as the Permian and Oklahoma Stack as it is generating the free cash flow that the others are
consuming. It also allows for diligence in capital spending, where investors have also begun to prioritize capital
efficiency over capital expenditure. Key producers in the region (EOG, BPX, and Chesapeake) are consolidating
acreage to be more strategic about their capex, seeking to maximize wells and minimize spending. As noted in the
table below, total capex can decline while number of wells increases.
Capex Metrics in the Eagle Ford
Trend Metrics EOG BPX Chesapeake Carrizo
2019 Total Capex Budget (Includes Eagle Ford) $6.1 - 6.5 Billion $2 Billion $1.2 - 1.3 Billion $550 Million
Change from 2018 +8% +45% -12% -29%
Eagle Ford 2019 Well Program Estimate (Net) 300 Wells NA 208 Wells 90 Wells
Change from 2018 Wells Estimate +15.4% NA +48.6% +23.3%
Breakeven Prices in Eagle Ford per barrel $ NA NA $35 - 45 $32
Net Acreage in Eagle Ford (Most Recent Estimate) 579,000 194,000 655,000 76,500
Source: Company Reports ShaleExperts.com

Eagle Ford
End of the Eagle Ford?
While there is plenty of current production in addition to cash flow, there are concerns about the longevity of the region.
Even regional giant EOG is looking to diversify. On a recent earnings call, EVP of Exploration Production, Ezra
Yacob, noted expanding exploration in those areas will “help increase the quality of our inventory” and “should hopefully
shallow the decline that these unconventional plays are kind of known for.” The company still plans to drill about the
same number of wells in the region in 2019, after posting a 9% crude oil production increase. The Eagle Ford repre-
sented 43% of EOG’s crude production last year, so diversifying to other regions doesn’t necessarily indicate a bearish
view. Instead, it seems to be in line with the strategy alluded by Marathon, using the cash flow generated in the Eagle
Ford to pay for growth in other plays.
Like other shale plays, the Eagle Ford struggles with steep decline curves and production replacement, thus impacting
rates of return. Economic critics of the shale plays warn of the “treadmill” effect of replacing production and the costs to
do so. There is validity to this. While new drilling techniques allow for more efficiency as noted earlier, these follow on
wells in pad drilling are also susceptible to productivity problems known as parent-child well interference. Carrizo and
Equinor have changed their frac designs to attempt to counter this, and the downside risk to operators investing in the
play is whether or not they will be able to flatten their production declines enough to keep Eagle Ford wells economical
for longer periods of time. Many companies have questioned where Eagle Ford assets fit in their long-term plans. As
discussed in more detail later, some operators are leaving the region, and Sanchez Energy, a long time region producer,
was recently delisted from the NYSE.
Despite the older nature of the play, many people around the industry believe there is plenty of value still under the sub-
surface in south Texas. Director at BMO Capital Markets Max van Adrichem called the Eagle Ford a good alternative
to “some of the more mature basins which may not have enough running room to get you through 5 to 10 years.” Martin
Thalken, Chairman and CEO of pure-play Eagle Ford operator Protégé Energy III, supports this line of thinking. He com-
mented the Eagle Ford “is still in the early innings” on applications like primary EOR and refracturing. John Thaeler,
CEO of Vitruvian Exploration IV also employed a baseball analogy, saying “the dry gas Eagle Ford is just in the second
inning.” Marathon’s Abbott agrees, “We believe there is a lot of running room left in the Eagle Ford for Marathon and
the rest of the industry.”
Also, in a time where oil and liquid production (as opposed to reserve accumulation) is the energy industry’s focus, the
Eagle Ford Region is, according to the EIA, the second most prolific oil region in the United States from a myriad of
standpoints: (i) overall oil production, (ii) per rig production, and even (iii) DUC well count.

Eagle Ford
Rig Counts and
Production
According to calculations based on data from Baker Hughes, rig counts in North America decreased 4.2% in the last
three months, but increased 3.6% over the last twelve months. The Eagle Ford Shale had the highest annual increase
at 15.5%, but its 82 rigs only represent 8.0% of total rigs in North America. Despite a 4.5% decline in the past three
months, the Permian Basin continues to lead the way with 464 rigs, representing about 45% of the total. By comparison,
the Eagle Ford has the second most rigs, just ahead of Appalachia at 79 and the Bakken with 56.
Despite the increase in rig counts, production increases over the past year for both oil (14.4%) and gas (8.3%) have
trailed production gains seen in other regions. This is likely due to the older nature of the play, and its stage in the pro-
duction cycle. The lack of production growth does not mean there is low production, however. It continues to provide
solid production, with crude oil production on par with the Bakken, and significantly above Appalachia, which is known
for its natural gas. The Eagle Ford also leads the Bakken in terms of natural gas production.
Much of the attention, particularly in Texas, has been on crude as opposed to natural gas. Despite this, the graph on the
next page shows natural gas production in the Permian has increased significantly in the past year. As noted earlier, the
Eagle Ford’s location, specifically its proximity to the Henry Hub in Louisiana, may be a reason why the chasm between
the amounts of natural gas produced in the two regions hasn’t increased further than it has. Much like crude, operators
focused on natural gas in the Eagle Ford have benefitted from higher pricing as well as lower costs. According to
Michael J. Wieland, President and CEO of Laredo Energy VI LP, the economics of dry gas in the Eagle Ford are partic-
ularly strong. Wieland further estimated finding and development costs to be 50 cents per thousand cubic feet (Mcf) and
netbacks of about $2/Mcf. SilverBow Resources’ EVP and CFO, Gleeson Van Riet, said the company has drilled 20 of
the top 50 Eagle Ford gas wells and that the play is the best place to be in the U.S. for natural gas because it has the best
prices, good infrastructure, and is located in the demand growth area. SilverBow (formerly Swift Energy) is the Eagle
Ford’s only public pure-play in dry gas. Whether an operator focuses on crude oil, natural gas, or both, neither seems to
be in short supply in the region. Natural gas produced in the basin will be very competitive in the oncoming LNG market
growth on the Texas coast as well.

Eagle Ford
Rig Counts and
Production
(continued)
Daily Production of Crude Oil
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
M
ar-14
Sep-14
M
ar-15
Sep-15
M
ar-16
Sep-16
M
ar-17
Sep-17
M
ar-18
Sep-18
M
ar-19
ThousandCubicFeetperDay
Bakken Eagle Ford Permian Appalachia
Source: EIA
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
M
ar-14
Sep-14
M
ar-15
Sep-15
M
ar-16
Sep-16
M
ar-17
Sep-17
M
ar-18
Sep-18
M
ar-19
ThousandBarrelsperDay
Source: EIASource: EIA
Daily Production of Natural Gas

Price per Flowing Barrel
Eagle Ford
Valuation Implications
To further understand the current production profile of the Eagle Ford and oil and gas plays in general, we can compare
them to a typical company. In the early stages, companies retain earnings to fund growth opportunities as the return on
investment can be quite high. As the company matures, however, there are fewer high return investments to be made,
and companies tend to pay more dividends. Returns shift from capital appreciation from retained earnings to a yield in
the form of dividends paid as a reward for years of investment. The Eagle Ford is in the stage of paying dividends.
As has been the case for some time now, operators in the Permian continue to lead the other regions in terms of EV/
production multiples, also known as price per flowing barrel. The Bakken was about on par with the Permian at the end
of 2018, but it slid back towards the Eagle Ford, which edged up over the past three months. Multiples continue to trail
levels seen in the past as enterprise values have been somewhat lower and production figures have increased.
$0
$30,000
$60,000
$90,000
$120,000
$150,000
2017 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4 2019 Q1
Source: Bloomberg

Over the last twelve months, the Eagle Ford Region has experienced steady growth and healthy transaction activity.
According to the Society of Petroleum Engineers, crude production from the south Texas play climbed steadily
throughout the year and continued to achieve its highest marks ever. New, upstart independents came back to the
region, including one led by the former head of Occidental Petroleum, as investors looked beyond the neighboring
Permian Basin with its crowded top-tier acreage and pipelines. Additionally, operators began joining forces to increase
the scale of their operations, headlined by Chesapeake Energy’s merger with WildHorse Resource Development.
The region’s strengths–such as its low cycle times, high oil cuts, and Louisiana Light Sweet crude and Brent oil
pricing–have facilitated free cash flow and made the area attractive to both investors and operators. As long as entry
costs and well costs remain reasonable, the Eagle Ford Shale has strong potential for continued economic growth.
Details of recent transactions in the Eagle Ford Shale, including some comparative valuation metrics, are shown
on the next page.
Eagle Ford
Market Valuations
Transaction Activity

Transactions in the Eagle Ford
Announced
Date Buyer Seller
Deal Value
($MM) $ / Acre $ / Boepd
3/18/19 Inpex Corp Gulftex Energy – nm –
2/18/19 Undisclosed Buyer Harvest Oil Gas Corp. $52 nm –
2/7/19 Kimbell Royalty Partners LP Encap Investments $151 $12,402 $94,563
11/21/18 Kimbell Royalty Partners LP Undisclosed Seller $108 $6,455 $90,588
11/19/18 Lonestar Resources Ltd. Sabine Oil Gas Corp , Alerion Gas Axa LLC $39 $12,549 $48,375
10/31/18 Undisclosed Buyer Pioneer Natural Resources Co. $132 $45,517 $42,581
10/30/18 Chesapeake Energy Corp WildHorse Resource Development $3,977 $9,469 $84,617
10/29/18 Denbury Resources Inc. Penn Virginia Corp $1,700 $20,224 $77,273
10/11/18 Oracle Energy Corp. Undisclosed Seller – nm –
9/20/18 WildHorse Resource Development Undisclosed Seller $43 $1,387 $1,102,564
8/21/18 Magnolia Oil Gas Harvest Oil Gas Corp. $191 $1,675 $39,792
8/21/18 Undisclosed Buyer Harvest Oil Gas Corp. $4 nm –
7/27/18 BP Plc BHP Billiton Limited $10,500 $22,340 $55,263
7/5/18 Sumitomo Corporation, Summit Discovery Resources LLC IOG Capital LP – nm –
6/4/18 Osprey Energy Acquisition Corp. Royal Resources $894 $3,562 $187,657
6/1/18 Venado Oil Gas Llc Texas American Resources Co. $300 $12,951 $62,500
4/4/18 USG Energy Producer Holdings Comstock Resources Inc. $125 $12,626 $49,135
4/2/18 Protege Energy III LLC Contango Oil Gas Co. $21 $20,000 $168,000
Median $132 $12,549 $77,273
Average $1,216 $13,935 $161,762
Source: Shale Experts
*Does not include every transaction in each region for 2018-2019

Chesapeake Closes Acquisition of WildHorse for Nearly $4 Billion
Chesapeake has made several major transactions over the last nine months. In the middle of 2018, the company
sold its entire stake in the Utica Shale, and experts speculated that the company would put the sales proceeds
towards an acquisition in the Eagle Ford or Powder Basin area. Chesapeake did just that when it closed a deal with
Houston-based WildHorse Resource Development with a transaction value of $3.977 billion. For perspective, Wild-
Horse was the fourth most active driller in the Eagle Ford in 2018 while Chesapeake was the fifth.
The consideration for the transaction consisted of either 5.989 shares of Chesapeake common stock or a combination
of 5.336 shares of Chesapeake common stock and $3 cash, in exchange for each share of WildHorse common stock.
Chesapeake intended to finance the cash portion of the WildHorse acquisition, which was expected to be between
$275 million and $400 million, through its revolving credit facility.
In a statement, Chesapeake’s CEO, Doug Lawler said: “In 2018, Chesapeake Energy continued to build upon our
track record of consistent business delivery and transformational progress through both financial and operating
improvements. The addition of the WildHorse assets to our high-quality, diverse portfolio, combined with our operating
expertise and experience, provides another oil growth engine with significant oil inventory for years to come and gives
us tremendous flexibility and optionality to help achieve our strategic goals.” Following the deal, Chesapeake is now
the top acreage holder in the Eagle Ford with approximately 655,000 nets acres, pro forma.
New Kids on the Block
At the DUG Eagle Ford conference in San Antonio, Stephen Chazen, former Occidental executive, noted “General
investors want reasonable growth, earnings per share, and free cash flow.” After leaving Occidental, Chazen became
Chairman, President and CEO of Magnolia Oil Gas, a recently formed small independent company. Magnolia
Oil generated free cash flow in excess of capital on acquisition spending and ended 2018 with $136 million of
cash on the balance sheet, an increase of approximately $100 million compared to the end of the third quarter.
These kinds of results show that the region has been a cash flow generator for the year and has been a main
driver for most of the recent and anticipated transaction activity, especially companies under $1 billion in market
capitalization. The cash flows allow smaller players to compete as the market is less interested in upstart companies
in the high growth stage.
Eagle Ford
Market Valuations
(continued)

Eagle Ford
Market Valuations
(continued)
Anticipated Large Operator Divestitures in 2019
As alluded to earlier, several larger operators in the Eagle Ford area are potential candidates for divestiture.
Following Q4 2018 earnings calls, five operators indicated that they are open to selling all or parts of their Eagle Ford
assets in 2019. After purchasing Newfield, Encana Corp now considers the Eagle Ford as non-core. Pioneer Natural
Resources has been actively selling pieces of their Eagle Ford asset since 2018, and Norway’s Equinor announced
plans to potentially do the same. Matador will outspend cash flow this year and may plug that gap with an Eagle Ford
asset sale. Earthstone is trying to convert itself into a Permian-only player, and reports from Shale Experts expect
they will be looking to offload their Eagle Ford assets in the near-term. Collectively, the net acreage under consider-
ation totals over 100,000 net acres.
Equinor has an ownership interest in the Eagle Ford Shale formation located in south Texas through a joint venture
with Repsol. Through transactions in 2013 and 2015, Equinor obtained full operatorship in the joint venture and
increased its working interest to 63%. The company’s net acreage position in the Eagle Ford at the end of 2018 was
approximately 71,000 net acres and production of 43,000 boe/d. In a recent interview, Al Cook, the company’s
head of strategy, said that Equinor is looking to add to its large position in Appalachia in an attempt to chase natural
gas-rich acreage. This move is consistent with trends we identified last quarter in our transaction analysis of the
Appalachia Region.
Divestitures are also a natural part of the consolidation cycle as top producers commit and less successful operators
exit the play. As noted earlier, it is less dependent on size, and more on expertise and focus (core vs. non-core).
The good news for these exiting producers is that they are getting better prices as they leave. Where they cashed
out around $8,000 per acre a year or more ago, many are getting closer to $18,000 per acre now. Even gas heavy
producers are more optimistic as the Eagle Ford is the single most proximate play to many oncoming LNG facilities
in south Texas.

as of 3/31/2019
Company Name Ticker
3/31/2019
Enterprise Value
YOY % Change
in EV
EBITDAX
Margin
EV/
EBITDAX
Daily
Production
(mboe/d)
Price per Flowing
Barrel*
Global Integrated
Exxon Mobil Corp XOM $383,660 5.95% 14.8% 9.3x 3,919 $97,900
Royal Dutch Shell PLC RDS/A $311,652 14.75% 14.1% 5.7x 3,755 $82,990
Chevron Corp CVX $260,202 2.85% 21.9% 7.5x 3,100 $83,924
Occidental Petroleum Corp OXY $56,793 -1.90% 54.0% 5.9x 720 $78,897
BP PLC BP $193,165 11.12% 11.2% 5.8x 3,953 $48,865
Group Median 5.95% 14.8% 5.9x 3,755 $82,990
Global EP
Marathon Oil Corp MRO $17,714 -4.95% 68.9% 4.2x 424 $41,825
Hess Corp HES $24,064 20.58% 44.0% 8.6x 283 $85,070
ConocoPhillips COP $84,640 4.06% 42.5% 5.5x 1,352 $62,626
Anadarko Petroleum Corp APC $40,397 -10.94% 53.6% 6.0x 729 $55,408
Noble Energy Inc NBL $18,959 -12.85% 46.7% 8.4x 363 $52,268
Apache Corp APA $22,184 -3.00% 58.1% 5.2x 492 $45,124
Murphy Oil Corp MUR $8,300 29.03% 67.8% 4.9x 193 $43,096
Group Median -3.00% 53.6% 5.5x 424 $52,268
Source: Bloomberg L.P.
• Price per Flowing Barrel is EV/ daily production ($/boe/d)
• Companies included in the Guideline Group were selected from a broader guideline group. The selected companies’ market caps exceed $1 billion and revenues exceed $500 million.
• We have reviewed 10-K’s and annual reports from guideline companies to ensure companies continue to operate in the regions and groups we have identified. The only change from our prior edition is to move EQT Corp from the North American EP
group to the Appalachia Region.
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 3/31/2019
Company Name Ticker
3/31/2019
Enterprise Value
YOY % Change
in EV
EBITDAX
Margin
EV/
EBITDAX
Daily
Production
(mboe/d)
Price per Flowing
Barrel*
North American EP
Ultra Petroleum Corp UPL $2,319 -20.50% 61.7% 4.7x 112 $20,667
Encana Corp ECA $13,969 -1.89% 49.9% 4.7x 570 $24,510
Devon Energy Corp DVN $17,366 -32.68% 18.5% 7.7x 522 $33,236
Enerplus Corp ERF $2,253 -25.30% 58.2% 4.0x 97 $23,175
QEP Resources Inc QEP $4,348 -3.79% -31.6% -7.7x 77 $56,374
WPX Energy Inc WPX $8,018 -5.92% 71.7% 5.6x 159 $50,451
EQT Corp EQT $10,778 -54.39% -5.6% -39.5x 684 $15,763
Chesapeake Energy Corp CHK $14,570 0.42% 23.4% 6.3x 481 $30,314
Group Median -13.21% 36.7% 4.7x 320 $27,412
Bakken
Continental Resources Inc/OK CLR $22,597 -20.52% 73.7% 6.5x 332 $68,095
Whiting Petroleum Corp WLL $5,179 -13.22% 65.7% 4.1x 130 $39,819
Oasis Petroleum Inc OAS $4,843 1.11% 30.7% 8.5x 90 $53,551
Crescent Point Energy Corp CPG $4,908 -29.32% -60.6% -3.4x 172 $28,463
Group Median -16.87% 48.2% 5.3x 151 $46,685
Appendix A

as of 3/31/2019
Company Name Ticker
3/31/2019
Enterprise Value
YOY % Change
in EV
EBITDAX
Margin
EV/
EBITDAX
Daily
Production
(mboe/d)
Price per Flowing
Barrel*
Appalachia
Range Resources Corp RRC $6,648 -13.91% -27.3% -7.6x 388 $17,130
Cabot Oil Gas Corp COG $12,274 1.43% 62.0% 9.4x 404 $30,362
Antero Resources Corp AR $9,009 -23.54% 23.6% 8.6x 535 $16,824
Gulfport Energy Corp GPOR $3,342 -9.82% 61.9% 3.8x 231 $14,467
Southwestern Energy Co SWN $4,656 -39.86% 33.5% 3.7x 352 $13,232
Group Median -13.91% 33.5% 3.8x 388 $16,824
Permian Basin
Concho Resources Inc CXO $26,611 5.53% 87.4% 7.7x 329 $80,830
Parsley Energy Inc PE $8,133 -23.72% 72.4% 6.8x 130 $62,724
Diamondback Energy Inc FANG $21,406 51.69% 73.9% 14.1x 284 $75,276
Halcon Resources Corp HK $783 3.32% 76.4% 4.4x 23 $33,484
Laredo Petroleum Inc LPI $1,678 -39.66% 50.1% 3.1x 72 $23,320
Pioneer Natural Resources Co PXD $26,655 -10.80% 34.3% 8.8x 338 $78,941
Cimarex Energy Co XEC $7,777 -22.30% 70.9% 4.7x 265 $29,309
Group Median -10.80% 72.4% 6.8x 265 $62,724
Appendix A

as of 3/31/2019
Company Name Ticker
3/31/2019
Enterprise Value
YOY % Change
in EV
EBITDAX
Margin
EV/
EBITDAX
Daily
Production
(mboe/d)
Price per Flowing
Barrel*
Eagle Ford
Carrizo Oil Gas Inc CRZO $3,024 -4.70% 70.0% 4.5x 69 $44,014
SM Energy Co SM $4,482 -2.76% 94.8% 2.9x 129 $34,691
EOG Resources Inc EOG $59,738 -10.12% 48.1% 7.3x 816 $73,169
Group Median -4.70% 70.0% 4.5x 129 $44,014
Overall Median -4.95% 50.1% 5.6x 338 $44,014
Appendix A

Appendix B
Rig Count
Rig Count by Region
0
300
600
900
1,200
1,500
1,800
2,100
M
ar-14
Sep-14
M
ar-15
Sep-15
M
ar-16
Sep-16
M
ar-17
Sep-17
M
ar-18
Sep-18
M
ar-19
Bakken Eagle Ford Permian Appalachia Other
Source: Baker Hughes
Baker Hughes collects and publishes information regarding active drilling rigs in the United States 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 United States as of March 31, 2019 stood at 1,003, a 1.5% increase from
March 31, 2017, but a 7.1% decline from year-end 2018. Activity in the Eagle Ford followed a similar pattern.
The increase reflects a pickup in drilling activity from the increase of oil prices from $60/bbl to begin 2018, to over $76
in early October, followed by a sharp decline to close the year. Crude prices have improved in the first quarter of 2019,
but rig counts have declined. With changing dynamics within the industry, well counts and DUCs are beginning to play
a more prominent role as a measure of activity over purely looking at rig counts.
1
Calculations based on monthly crude oil and gas production and EIA drilling report by region.

U.S. Rig Count by Oil vs. Natural Gas
0
500
1000
1500
2000
2500
M
ar-14
Sep-14
M
ar-15
Sep-15
M
ar-16
Sep-16
M
ar-17
Sep-17
M
ar-18
Sep-18
M
ar-19
Oil Gas
Appendix B
Rig Count
U.S. Rig Count by Trajectory
0
500
1000
1500
2000
2500
M
ar-14
Sep-14
M
ar-15
Sep-15
M
ar-16
Sep-16
M
ar-17
Sep-17
M
ar-18
Sep-18
M
ar-19
Directional Horizontal Vertical

Mercer Capital
www.mercercapital.com

Mercer Capital's Value Focus: Energy Industry | Q1 2019 | Region Focus: Eagle Ford

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