einhorn consol presentation

This is a graph of Arkema, which we bought at the wrong part of the last cycle.

The stock deserved to fall, and we looked and felt stupid for owning it.

_____________Source: Bloomberg LP, retrieved November 2015.

3

And this is the graph of CONSOL, an energy company that has gone from $40 to $7.

Again, we timed it poorly, initially buying in the 30s and adding all the way down.

_____________Source: Bloomberg LP as of November 13, 2015.

4

CONSOL is at $7.40 a share, giving it a $1.7 billion market cap, and a $5.5 billion enterprise value.

_____________Source: CNX filings available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐sec; Bloomberg LP pricing as of November 13, 2015; and Greenlight calculations. Minority interest is based on the publically traded value of CNX Coal Resources LP (CNXC) not owned by CNX as of November 2015.

5

The market views CONSOL as a coal company. We disagree, but let's look at it through that lens for a moment.

These are coal stocks, and among them CONSOL is not an outlier.

As you can see, the whole industry has practically been left for dead. Even CONSOL’s bonds trade like it might go out of business.

_____________Source: Greenlight calculations based on pricing data from Bloomberg LP as of November 13, 2015. Comparative coal companies selected in the sole discretion of Greenlight.

6

A decade ago, coal was used to generate roughly half of all electricity in the U.S.

_____________Source: Greenlight calculations using U.S. Energy Information Administration (“EIA”) monthly U.S. electricity generation data, filtered on the electric power sector, retrieved November 2015, from EIA’s custom table builder at www.eia.gov/forecasts/steo/query. Classifications selected in the sole discretion of Greenlight.

7

Thanks to the shale gas revolution and environmental regulations, coal is no longer king. We burn less of it and its price has declined.

_____________Source: Source: Platts Coal, obtained November 2015.

8

While coal used to provide nearly half of U.S. electricity, it’s now providing less than 35%.

_____________Source: Greenlight calculations using EIA monthly U.S. electricity generation data, filtered on the electric power sector, retrieved November 2015, from EIA’s custom table builder at www.eia.gov/forecasts/steo/query. Figures for 2015 are year to date through September 30, 3015. Classifications selected in the sole discretion of Greenlight.

9

We’ve gone from producing more than a billion tons of thermal coal annually to less than 850 million tons in the last five years, and everyone agrees that this trend will continue.

_____________Source: Greenlight calculations using EIA annual U.S. coal supply, consumption, and inventories data, retrieved November 2015, from EIA’s short term energy outlook browser (beta) at www.eia.gov/beta/steo/. Thermal coal is total coal less exported metallurgical coal and coke plant consumption.

10

But coal isn’t disappearing altogether.

11

Even under conservative projections, 20 years from now coal will still provide 25% of the country’s electricity.

That’s about 760 million tons annually. Someone has to supply it.

_____________Source: Greenlight calculations using EIA’s electricity supply, dispositions, prices, and emissions reference case, retrieved November 2015, from EIA’s Analysis of the Impacts of the Clean Power Plan, filtered on Electric Power Sector, available at www.eia.gov/oiaf/aeo/tablebrowser. Classifications selected in the sole discretion of Greenlight.

12

Coal is produced in three major basins across the continental United States

The expense of shipping makes coal a mostly regional business.

_____________Source: Greenlight calculations using EIA’s short‐term energy outlook for November 2015 at www.eia.gov/forecasts/steo/tables/pdf/6tab.pdf, with Appalachia adjusted for exported metallurgical coal and coke plant consumption. Classifications selected in the sole discretion of Greenlight.

13

In case you can't read that cartoon, it says, "I suspect my husband's hiking on me.“

We’re going to focus on the coal coming out of Appalachia, an area known for being a favorite hiking spot of South Carolina governors.

14

Appalachia has been hit especially hard by the falling demand.

In the past few years we’ve seen at least 20 coal companies go into bankruptcy, liquidating their inventories into an already oversupplied market as they do so.

The current spot price is just $43 per ton, down from about $80 four years ago.

15

The contagion should continue for another 12‐18 months until the uncompetitive mines close and inventory comes back into equilibrium.

The players who will survive and ultimately prosper are the ones on the low end of the regional cost curve.

16

This brings us to CONSOL Energy, a company that has been mining coal in Appalachia for 150‐years, and has historically been very profitable.

_____________Source: Greenlight estimates and calculations based on CNX filings and earnings presentations for referenced time periods, available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐irhome.

17

In late 2013, management sold the bulk of its higher‐cost West Virginia coal assets to Murray Energy for $3.5 billion, leaving it with low‐cost, modernized, non‐union mines, mostly in Pennsylvania.

18

The mines have some of the most desirable coal in Northern Appalachia, with high heat and low sulphur content.

Higher heat means more energy, and lower sulphur reduces the costs to burn the coal, making it more attractive to utilities.

_____________Source: CNX Q3 2015 earnings call slides, available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐presentations. Throughout this presentation we use “CONSOL Thermal Coal” to refer to CNX’s Pennsylvania Operations segment.

19

The mines have the capacity to produce up to 28 million tons a year for a long time without substantial investment.

_____________Source: CNX Q3 2015 earnings call slides available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐presentations. Greenlight updated CNX’s 2014 reserve estimate by subtracting Greenlight’s estimate of annual activity for 2015.

20

Assuming clean energy regulations get implemented, the EIA expects Appalachian coal demand to decline nearly 35% over the next 10 years until it stabilizes at around 110 million tons.

_____________Source: Greenlight estimates from 2020 onward based on EIA’s coal production by region and type reference case, retrieved November 2015, from EIA’s Analysis of the Impacts of the Clean Power Plan, filtered on Coal Supply and Prices, available at www.eia.gov/oiaf/aeo/tablebrowser. Greenlight calculations for prior years based upon EIA data utilized in Slide 10, with Appalachia adjusted for exported metallurgical coal and coke plant consumption. Classifications selected in the sole discretion of Greenlight.

21

Only 12% of existing production in Appalachia is lower cost than CONSOL.

Looking at the entire cost curve for the region, the current equilibrium for 168 million tons is approximately $80 per ton. At 2025 demand levels, equilibrium would fall to approximately $50 per ton, assuming no cost inflation.

_____________Source: Supply curve based on data from Wood Mackenzie, provided to Greenlight in November 2015. Chart excludes mines with cash costs per ton greater than $100. Curve covers 145 million tons of Appalachia production. Eventual closures reflect Greenlight estimates.

22

We expect a very weak pricing environment over the next year. Fortunately, CONSOL is protected in the near term, having locked in pricing for the balance of this year at approximately $57 per ton and enough for next year to realize over $50 per ton.

_____________Source: Greenlight estimates based upon CNX filings, earnings presentations, and management guidance for referenced time periods, available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐irhome.

23

CONSOL’s falling costs and recently implemented zero‐based budgeting should bring cash costs toward $33 per ton next year, allowing it to remain quite profitable during the dislocation.

By the end of next year, many uncompetitive mines will have closed and prices should be recovering.

_____________Source: Greenlight estimate of CNX’s thermal coal operations is based upon CNX filings, investor presentations and management guidance for referenced time periods, available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐irhome.

24

EBITDA should settle at around $425 million per year and EBITDA less Capex should be around $280 million.

_____________Source: Greenlight estimate of CNX’s thermal coal operations is based upon CNX filings, investor presentations and management guidance for referenced time periods, available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐irhome.

25

We think that the best way to value a long lasting pile of reserves of any type is with a discounted cash flow analysis. Here, the DCF reflects the value of the entire thermal reserve base down to the full runoff. We will release the full DCF later this week, but the bottom line is the thermal coal business is worth $3 billion. As a cross check, that is about 11x depressed EBITDA less Capex, and less than four dollars per ton of reserves.

_____________Source: Greenlight estimate. Please refer to accompanying thermal coal discounted cash flow model for details and assumptions.

26

CONSOL’s Buchanan mine is the lowest cost metallurgical coal mine in America. It produces 4 million tons of coal and 16 million dollars of EBITDA in today’s depressed markets. I don’t have time to go through the met coal industry, but doing the same work we did for thermal coal generates a DCF value of approximately $490 million.

_____________Source: Greenlight estimates. Please refer to accompanying metallurgical coal discounted cash flow model for details and assumptions.

27

CONSOL produces about 100 Billion Cubic Feet Equivalents (Bcfe) a year of coalbed methane and other legacy gas out of 2 Trillion Cubic Feet Equivalents (Tcfe) of proved reserves, 80% of which are developed. At today’s prices it does not make sense to invest more than the bare minimum in this business, and that’s what CONSOL is doing. Nonetheless, production continues. We use a run‐off analysis to value it at $900 million.

_____________Source: Greenlight estimates. Please refer to accompanying legacy gas discounted cash flow model for details and assumptions. Reserve data from CNX Form 10‐K, available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐reports.

28

CONSOL also owns public shares, a retained interest in gathering systems, and Incentive Distribution Rights (IDRs) in CONE Midstream, ticker CNNX, which CONSOL and its Marcellus joint venture partner Noble took public in September 2014. We value CONSOL’s stake at $667 million.

_____________Source: Greenlight estimate based upon the following values: (a) Common, subordinated and GP units at the closing price of CNNX, as of November 13, 2015; (b) retained interest in gathering systems at 1.75x tangible book; and (c) Greenlight’s estimate of IDR value.

29

Management plans to divest some non‐core assets over the next year. We estimate proceeds to be around $500 million in addition to any assets we are counting elsewhere. We believe the value of the thermal coal, met coal, legacy oil and gas, and assets to be sold equal today's enterprise value.

_____________Source: Greenlight calculation based upon prior slides.

30

If that’s all there was, then CONSOL would be roughly fairly valued at today’s price. But, wait…

31

CONSOL owns a lot of shale gas.

32

It is one of the largest players in the Marcellus and Utica shales. It has a million net acres and 54 tcfe of resources in these two basins.

That is enough gas to supply the entire country for two years.

We believe that’s valuable.

_____________Source: CNX Q3 2015 earnings call slides, available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐presentations.

33

And yes, I remember that I presented a short thesis on oil frackers at the Sohn Investing Conference last May, calling them “value destroyers”.

But not all fracking is created equal. We noted then that the natural gas frackers had attractive economics, which was true at the time. Since then, the price of gas has fallen.

34

Before getting into CONSOL’s fracking business, let’s briefly revisit Pioneer, which we highlighted as the Mother‐Fracker. In May we showed that Pioneer did not have a positive value on a DCF basis. A key assumption was based on Pioneer’s 2014 finding costs of $20.66 per BOE or barrel of oil equivalent in its horizontal drilling program.

_____________Source: Greenlight presentation on May 4, 2015, available at www.greenlightcapital.com.

35

Last month, we had a long visit with Pioneer management and went through our thesis. Their main objection was that our capital intensity was too high – they said their wells were more productive than we gave them credit for, and $15 per BOE would make more sense as a long‐term target.

This is not what the company did last year, or what it will do this year, but it’s what management said Pioneer can do longer term.

36

We updated our Pioneer DCF model based on their feedback and the current commodity strip prices, which shows Pioneer generates about $33 per BOE in revenues and $19 of undiscounted cash flows. The present value of those is $12 per BOE, which is less than management’s targeted long‐term capex of $15. So, at current strip prices, Pioneer’s drilling program continues to destroy shareholder value.

_____________Source: Revenue per BOE for WTI oil and Henry Hub natural gas calculated using an average of 2016, 2017, and 2018 NYMEX futures price, obtained from Bloomberg LP in November 2015. Realized revenues per BOE for oil, natural gas and NGL based on Greenlight estimates. Greenlight’s estimated % of BOE mix from oil, natural gas, and NGL based on estimates from ITG. Greenlight’s estimated capital and operating cost for PXD based on management guidance and Q3 2015 results.

37

We updated the Pioneer DCF analysis as well. While the improved capital efficiency helps, the lower commodity price brings the value back to $7 per share at today’s curve as shown in the orange intersection.

_____________Source: Greenlight’s DCF value from May 2015 is highlighted in yellow. Greenlight’s DCF value from November 2015 is highlighted in orange. Critical assumptions in the updated DCF are:• Greenlight’s type curve based on data from Wood Mackenzie and ITG• Capex is 37% higher in first year and 7% growth thereafter• 10.2 billion BOE developed over 40 years• Oil price at forward curve until 2023, flat thereafter• Natural gas price at forward curve until 2027, then grows 2% per year• Operating costs down 30% in 2016 from 2014, then flat thereafter• Capex at $15 per BOE• Corporate WACC of 7.7%

38

In effect, Pioneer is just an option on much higher oil prices. With a market cap of $21 billion and a DCF value of only $1 billion, investors are paying $20 billion in the hope that long term oil prices will be much higher than the futures market expects. The current value reflects energy prices more than 30% higher across the curve.

_____________Source: Greenlight calculation based upon prior slides.

39

Let’s look at CONSOL’s Marcellus and Utica assets on the same basis.

These are the economics for CONSOL to get gas out of the ground and to market based on today’s prices.

Similar to the oil frackers, drilling now destroys value. But it’s not as bad for gas as it is for oil.

_____________Source: Revenue per Mcfe for WTI oil and Henry Hub natural gas calculated using an average of 2016, 2017, and 2018 NYMEX futures price, obtained from Bloomberg LP in November 2015. Realized revenues per BOE for oil, natural gas and NGL based on Greenlight estimates. Estimated % of Mcfe mix of natural gas, NGL, and oil based on modelled new well production mix. Greenlight’s estimated capital and operating cost for CNX based on management guidance and Q3 2015 results. Critical assumptions are disclosed in Slide 49.

40

Drilling and completion techniques are pretty much standard whether fracking for gas or oil, and so are the costs.

_____________Source: Picture of gas rig by Michael Henninger of the Post‐Gazette, copyright owned by PG Publishing Co. Picture of oil rig by Birrell Services, copyright owned by Birrell Services.

41

But what they produce is not the same. For example, Marcellus wells recover 2.5 times more energy than Permian wells. Even at today’s incredibly depressed gas prices, the revenues at spot prices are higher for a CONSOL Marcellus well than a Pioneer Permian well.

_____________Source: Revenue at spot are Greenlight estimates, based on the following:• WTI oil, Henry Hub natural gas, and Mount Belvieu NGL pricing from Bloomberg LP as of November 13,

2015. • Bcfe mix for CNX based on modelled new well production mix. • BOE mix for PXD based on estimates from ITG. • Total recoverables of 15 bcfe for CNX based on data in Q3 2015 earnings call slides available at

http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐presentations. • Total recoverables of 1 mmboe for PXD based on data in Q3 earnings call slides available at

http://investors.pxd.com/phoenix.zhtml?c=90959&p=irol‐presentations.• No adjustment for transport differentials or royalties.

42

You’d expect the oil frackers like Pioneer to be cutting capex faster than the gas companies. Nope. Instead, while CONSOL has stopped drilling new wells, Pioneer has added rigs.

43

CONSOL will spend money to complete and bring on line wells that have already been drilled, allowing it to show production growth that would excite many oil and gas analysts.

But to us, what's exciting is that management is disciplined enough to defer new investment until the economics make sense.

_____________Source: 2012 to 2014 reflect data from CNX Forms 10‐K for periods presented, available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐sec. 2015 and 2016 estimates reflect management guidance.

44

And CONSOL can afford to be patient. The company owns much of this land outright, so unlike many of its peers it doesn’t pay royalties and it doesn’t need to drill in order to maintain its rights.

45

Like Pioneer, CONSOL needs higher prices to drill profitably. The difference is that Pittsburgh‐based CONSOL is unwilling to invest Capex for negative returns, while Dallas‐based Pioneer plans to invest right through them.

46

Just as with the oil frackers, we believe the most accurate way to measure value is to do a long‐term DCF.

47

This is the NYMEX futures price for natural gas. The curve reflects a recovery, subject to seasonality. We use the commodity forward curve in our DCF.


48

These are the critical assumptions in our DCF. Notably, we assume drilling restarts in 2018 even though I think gas prices will improve faster than the market thinks. I’ll get to that shortly.

_____________Source: Greenlight estimates. Please refer to accompanying shale gas discounted cash flow model for details and assumptions.

49

Putting it all together, this leads to a total base case value for CONSOL’s shale gas business of $6.6 billion.

_____________Source: Greenlight estimate based upon data presented in Slide 49. Please refer to accompanying shale gas discounted cash flow for details and assumptions.

50

The DCF value converts to $6,200 per net acre and $0.12 per mcfe of potential resource.

Here, we compare that to the values of 6 other pure plays in the Marcellus/Utica on a per acre and per potential resource basis. The industry experts will tell you that all acres aren’t equal. But, the point I’m making is that our DCF‐derived value isn’t too far from the current market values of the pure plays.

_____________Source: Greenlight estimates and calculations, as follows:For CNX: • “Adjusted EV” is the enterprise value based on Greenlight’s shale gas DCF, • “Net Acre” based upon CNX investor presentations, and • “Resource” based upon CNX investor presentations and Greenlight estimates.

For all other issuers (which were selected in the sole discretion of Greenlight): • “Adjusted EV” is the enterprise value based upon issuer filings, reduced by Greenlight for book value of

balance sheet derivative assets, and where appropriate, reduced by either the market value or book value of equity investments,

• “Net Acre” is based upon investor presentations. The EV/Net Acre Calculation reflects only Marcellus and Utica net acres, with the exception of Cabot, which also includes Eagle Ford net acres, and

• “Resource” based upon investor presentations, analyst research reports, and Greenlight estimates.

51

And compared to oil frackers like Pioneer, well… there is no comparison. Whereas Pioneer gets valued at $20 billion for its undrilled acreage, CONSOL’s stock implies negative value for its undrilled acreage.

That’s puzzling considering how remarkable the Marcellus and Utica are.

52

The story of 21st century natural gas is the story of the Marcellus & Utica.

From a standing start a decade ago, the area has been virtually all of the supply growth, and now produces more than 20% of America's gas.

_____________Source: Total U.S. natural gas production from EIA’s U.S. natural gas supply, consumption, and inventories data, retrieved November 2015, from EIA’s short term energy outlook browser (beta) at www.eia.gov/beta/steo/. Marcellus and Utica percent of total calculated by Greenlight from EIA’s drilling productivity reports at www.eia.gov/petroleum/drilling/xls/dpr‐data.xlsx, retrieved November 2015.

53

The EIA projects the region to double from here by the end of the decade, and we’ve still just scratched the surface.

Experts think there is enough recoverable gas to supply America for the next century.

54

It is not only the most prolific acreage; its gas is by far the cheapest to produce.

_____________Source: Wood Mackenzie, 9th Annual Sector Forum, Cost Efficiency & Capital Discipline, October 8, 2015.

55

All the low cost gas has driven down the price. This is a graph of historical Henry Hub natural gas.

In the last ten years it has spiked into the double digits. Today, it is near its lows around $2.


56

Historically, gas at Dominion South, near Pittsburgh, has traded at a premium to Henry Hub. Today, it’s at a big discount. This gap is known as the basis or the differential.

Right now, all the new production has created a shortage of pipeline to take gas out of the region, which has created a localized glut.

In early November, when Henry Hub gas was $2.25, it was about half that at Dominion South.

_____________Source: Greenlight calculations based on pricing data from Bloomberg LP, retrieved November 2015.

57

Generally speaking, when new entrants disrupt a market as the low cost producer, the disrupters’ stocks soar, while the incumbents’ stocks fade.

But here, with each discovery of additional low cost supply, the market groans at the disrupters.

The Marcellus and Utica gas frackers’ stocks have fallen. CONSOL has done even worse because the market insists it's nothing but a coal stock.

_____________Source: Greenlight calculations based on pricing data from Bloomberg LP, retrieved November 2015. Comparative E&P companies selected in the sole discretion of Greenlight.

58

Ordinarily, I would add this all up and say that the sum of the parts is $8.2 billion, or $35.81 per share, and be done with it.

But I'd like to spend a couple more minutes on natural gas. We valued CONSOL based on the current forward curve but what if the price actually went up?

59

Optimism on natural gas is pretty unpopular these days. Even the perma‐bulls have given up.

In Dallas last month, T. Boone Pickens said, “I don’t think natural gas will ever go up.”

_____________Source: Great Investors Best Ideas 9th Annual Investment Symposium on October 6, 2015.

60

Like any commodity the cure for low prices is low prices.

Prices can't stay below the cost of the lowest cost producers for long.

61

At the beginning of the year, producers reacted to lower prices and dramatically slowed drilling for natural gas.

_____________Source: Baker Hughes weekly natural gas rig count, retrieved from Bloomberg LP in November 2015.

62

There is a lag between when drilling stops and volumes fall because partially drilled and completed wells will continue to come online for the next couple years.

63

But since production from existing wells decline about 25% per year, supply and demand can correct quickly.

_____________Source: ITG natural gas base decline rate for the lower 48 states through December 2014, obtained from ITG in October 2015.

64

The lagged impact of reduced drilling may be showing up now, as year‐over‐year production growth has decelerated and is pushing zero.

_____________Source: EIA’s weekly production growth data, retrieved November 2015, available at www.eia.gov/naturalgas/weekly.

65

While low prices pressure supply, recent demand has been strong, up mid‐single digits, driven primarily by electricity usage. Longer‐term demand should grow almost 3% per year.

_____________Source: Greenlight estimate based upon data provided by BTU Analytics, LLC.

66

And because gas is hard to store, we don't store very much of it – usually only about 40 days’ worth.

_____________Source: Greenlight calculations based on EIA’s U.S. dry natural gas production data through August 2015, retrieved November 2015, available at www.eia.gov/dnav/ng/hist/n9070us2m.htm; EIA’s weekly production growth data from August 2015 to November 2015, retrieved November 2015, available at www.eia.gov/naturalgas/weekly; and Bloomberg LP storage data (DOENUST1 Index), retrieved November 2015.

67

To recap:

• supply is decelerating and threatening to fall due to lack of investment;• demand has secular growth;• we don't store very much;• prices are below the cost of the lowest cost producers; and • everyone is bearish.

So unless Amazon decides to go into the gas business, gas prices are likely to go up.

68

And the basis problem that is killing Pennsylvania prices is being solved by the market. This is a timeline of new pipeline capacity coming to the region, and the situation should start improving next year.

_____________Source: BTU Analytics, LLC, A Firm Dilemma, August 2015.

69

In the longer‐term the outlook for gas pricing is upward sloping while the oil curve flattens.

I think this is because the demand outlook is better for gas.


70

When I met with Pioneer management, we discussed the conversion of the transportation fleet to other energy sources, which would be bearish for oil and the long‐term value of Pioneer's resources.

The CEO responded by asking: “Do you drive a Tesla?” I said that I did. He responded “Thought so.”

71

But, there is a serious point here. I can fill my Tesla with electricity from my wall at the equivalent of 3 cents per mile and the only reason for me to go to a gas station is to buy Funyuns and Slim Jims.

72

Over the next number of years, improvements in technology will allow more efficient utilization of the auto fleet, and battery technology will allow more cars to run on gas‐fired electricity. Oil will get left out.

73

Based purely on energy content, six Mcfe is the same as a barrel of oil. Prices stopped reflecting this a few years ago because we ran out of places where we could switch oil to gas. With additional substitution as we convert the transportation fleet to electricity, prices should at least partly re‐converge toward energy equivalence over the next decade. This is why the long term gas curve continues to rise while the oil curve stays flat.

_____________Source: Greenlight calculations based upon pricing of the first active oil and gas futures contracts, retrieved from Bloomberg LP in November 2015.

74

Here is the DCF sensitivity in the shale business to higher gas prices, not counting the additional optionality for higher coal prices, which would probably follow gas prices higher. Remember, Wall Street insists this is a coal company.

_____________Source: Greenlight estimates and calculations. Please refer to accompanying shale gas discounted cash flow model for details assumptions.

75

But it may not be for long. We have a very good management team here. They have a long history of making good decisions.

_____________Source: CNX filings and press releases for referenced time periods available at http://phx.corporate‐ir.net/phoenix.zhtml?c=66439&p=irol‐irhome.

76

I mentioned that the company is selling some non‐core assets. Once it does and uses the proceeds to pay down some debt, it’s very likely that management will separate the gas business from the coal business, which will force the market to reconsider.

77

After Arkema went to 10, it turned around and went to 70.

I think there is a decent chance than CONSOL will do something like that.


78

Thank you very much.

79

There are several appendices attached to this presentation:

• Appendix A: Shale Gas DCF• Appendix B: Legacy Gas DCF• Appendix C: Thermal Coal DCF• Appendix D: Metallurgical Coal and Other DCF

80

CONSOL Energy - Shale Gas

Discounted Cash Flow Key Assumptions & Statistics

Base Case

PV of cash flows ($B) $6.6 Capital Spending Inputs Development Data (B)

Capex growth rate (b) 5.3% Starting capex $0.45

Capex growth period 20 years Peak capex $2.2

Peak capex period 35 years Peak cumm FCF burn $0.4

Well production period 50 years Total tcfe developed 52.4

Capex / mcfe $0.95 Total tcfe produced 53.9

Capex / mcfe terminal growth rate (c) 2.0%

Cost of Capital Commodity Assumptions Opex / mcfe

Equity risk premium 5.4% Current curve strip prices Oil & gas production (d)(e) $1.08

Adjusted beta 1.25 Natural gas (2027) $4.23 Production taxes (e) 5.2%

Risk-free rate 2.3% NGL (2023) $21 SG&A/Corp/Other (e)(f) $0.22

Equity cost of capital 9.0% Oil (2023) $59

Debt cost of capital 3.5% Natural gas Terminal Growth Rate (c) 2.0% Opex / mcfe terminal growth rate (c) 2.0%

Equity as % of EV 75% LT Production as % of mcfe

Calculated WACC 7.6% Natural gas 85%

GL Dislocation Premium (a) 0.8% NGL 12% Cash tax rate 35%

WACC 8.4% Oil (Condensate) 3%

Notes:

Includes Marcellus and Utica segments.

Estimated % of mcfe mix of Natural Gas, NGLs and Oil (Condensate) based on recent production mix adjusting for increasing mix of dry gas Utica.

Marcellus and Utica horizontal type curves published by EQT, adjusted to terminal decline rate and economic life variables developed in discussion with CONSOL.

Cash tax calculation based on current & future estimated net operating loss carryforwards.

Hess drilling carry realized in 2016. Noble drilling carry realized when natural gas exceeds $4.00/mmbtu and is based on estimated Marcellus capital spend.

Incorporates pro rata share of CONSOL's in place gas hedges.

Assumed differentials are based on recent results adjusted for a modest improvement over the next several years as additional takeaway capacity comes online.

(a) To be conservative we made an adjustment to increase the cost of capital because our value was already plenty high.

(b) 2016-2035 CAGR.

(c) Terminal growth rate starting in 2028.

(d) Includes transportation, gathering and compression, lifting and direct administrative and selling segment level costs.

(e) Weighted average cost structure from 2016-2027.

(f) Incorporates pro rata net expenses from the Other Gas segment, not directly related to Other Gas segment production.

This includes G&A, corporate, net unutilized FT expense, net gas royalty income, net purchased gas income, exploration and other costs and other income.

A-1


Discounted Cash Flow

Base Case

($M unless otherwise noted)

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Capex -450 -232 -557 -723 -793 -847 -879 -935 -949 -902

Reserves Developed (bcfe) 640 244 586 761 835 891 925 984 999 950

Proved Developed Reserves (bcfe) 2,344 2,320 2,590 2,960 3,329 3,683 4,007 4,324 4,602 4,796

Production (bcfe) 294 268 316 390 465 537 602 666 721 755

Revenues / mcfe ($) 2.62 2.73 2.84 2.94 3.05 3.19 3.33 3.47 3.61 3.74

Revenues 771 732 897 1,149 1,421 1,713 2,006 2,313 2,601 2,824

Cash opex / mcfe ($) 1.61 1.57 1.52 1.47 1.47 1.47 1.46 1.47 1.47 1.46

Opex 474 421 481 576 683 788 882 977 1,057 1,106

EBITDA 297 311 416 573 738 925 1,124 1,336 1,544 1,718

Gross Capex -450 -232 -557 -723 -793 -847 -879 -935 -949 -902

Drilling Carry Realization 30 0 0 0 0 0 0 0 0 0

Cash flow -124 80 -141 -150 -55 78 244 402 596 816

Cash tax 0 0 0 0 0 0 0 0 -149 -285

After tax cash flow -124 80 -141 -150 -55 78 244 402 447 530

0 0 0 0 0 0 0 0 0 0

A-2



Base Case


Capex

Reserves Developed (bcfe)

Proved Developed Reserves (bcfe)

Production (bcfe)

Revenues / mcfe ($)

Revenues

Cash opex / mcfe ($)

Opex

EBITDA

Gross Capex

Drilling Carry Realization

Cash flow

Cash tax

After tax cash flow

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

-899 -886 -920 -958 -999 -1,041 -1,085 -1,113 -1,157 -1,202

947 933 950 970 991 1,012 1,035 1,040 1,060 1,080

4,960 5,090 5,217 5,344 5,470 5,597 5,724 5,837 5,950 6,063

783 802 823 843 864 886 908 927 947 967

3.86 3.98 4.06 4.13 4.20 4.28 4.36 4.44 4.52 4.60

3,024 3,197 3,336 3,481 3,633 3,791 3,956 4,114 4,278 4,449

1.46 1.46 1.49 1.52 1.55 1.58 1.61 1.65 1.68 1.71

1,145 1,173 1,226 1,282 1,341 1,402 1,465 1,526 1,590 1,656

1,880 2,024 2,109 2,199 2,292 2,389 2,491 2,588 2,688 2,792

-899 -886 -920 -958 -999 -1,041 -1,085 -1,113 -1,157 -1,202

120 118 123 128 133 139 145 148 154 160

1,100 1,256 1,312 1,368 1,427 1,487 1,551 1,623 1,686 1,751

-385 -440 -459 -479 -499 -521 -543 -568 -590 -613

715 816 853 889 927 967 1,008 1,055 1,096 1,138

0 0 0 0 0 0 0 0 0 0

A-3



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Gross Capex


Cash flow

Cash tax

After tax cash flow

2036 2037 2038 2039 2040 2041 2042 2043 2044 2045

-1,098 -1,120 -1,142 -1,165 -1,188 -1,212 -1,236 -1,261 -1,286 -1,312

967 967 967 967 967 967 967 967 967 967

6,063 6,063 6,063 6,063 6,063 6,063 6,063 6,063 6,063 6,063

967 967 967 967 967 967 967 967 967 967

4.68 4.77 4.86 4.95 5.04 5.13 5.23 5.32 5.42 5.52

4,530 4,613 4,698 4,784 4,872 4,962 5,054 5,147 5,243 5,340

1.75 1.78 1.82 1.85 1.89 1.93 1.97 2.01 2.05 2.09

1,689 1,723 1,758 1,793 1,829 1,865 1,902 1,940 1,979 2,019

2,841 2,890 2,940 2,992 3,044 3,097 3,152 3,207 3,264 3,321

-1,098 -1,120 -1,142 -1,165 -1,188 -1,212 -1,236 -1,261 -1,286 -1,312

110 112 35 0 0 0 0 0 0 0

1,853 1,882 1,833 1,827 1,856 1,885 1,915 1,946 1,977 2,009

-648 -659 -641 -639 -649 -660 -670 -681 -692 -703

1,204 1,223 1,191 1,187 1,206 1,225 1,245 1,265 1,285 1,306

0 0 0 0 0 0 0 0 0 0

A-4



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Gross Capex


Cash flow

Cash tax

After tax cash flow

2046 2047 2048 2049 2050 2051 2052 2053 2054 2055

-1,338 -1,365 -1,392 -1,420 -1,449 -1,478 -1,507 -1,537 -1,568 -1,599

967 967 967 967 967 967 967 967 967 967

6,063 6,063 6,063 6,063 6,063 6,063 6,063 6,063 6,063 6,063

967 967 967 967 967 967 967 967 967 967

5.63 5.73 5.84 5.95 6.06 6.17 6.29 6.40 6.52 6.65

5,439 5,541 5,644 5,749 5,857 5,966 6,078 6,192 6,308 6,427

2.13 2.17 2.22 2.26 2.31 2.35 2.40 2.45 2.50 2.55

2,059 2,100 2,142 2,185 2,229 2,274 2,319 2,365 2,413 2,461

3,380 3,440 3,502 3,564 3,628 3,693 3,759 3,827 3,896 3,966

-1,338 -1,365 -1,392 -1,420 -1,449 -1,478 -1,507 -1,537 -1,568 -1,599

0 0 0 0 0 0 0 0 0 0

2,042 2,075 2,109 2,144 2,179 2,215 2,252 2,290 2,328 2,367

-715 -726 -738 -750 -763 -775 -788 -801 -815 -828

1,327 1,349 1,371 1,394 1,417 1,440 1,464 1,488 1,513 1,538

0 0 0 0 0 0 0 0 0 0

A-5



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Gross Capex


Cash flow

Cash tax

After tax cash flow

2056 2057 2058 2059 2060 2061 2062 2063 2064 2065

-1,631 -1,664 -1,697 -1,731 -1,766 -1,801 -1,837 -1,874 -1,911 -1,950

967 967 967 967 967 967 967 967 967 967

6,063 6,063 6,063 6,063 6,063 6,063 6,063 6,063 6,063 6,063

967 967 967 967 967 967 967 967 967 967

6.77 6.90 7.03 7.16 7.30 7.44 7.58 7.72 7.87 8.02

6,548 6,671 6,797 6,926 7,057 7,190 7,327 7,466 7,607 7,752

2.60 2.65 2.70 2.75 2.81 2.87 2.92 2.98 3.04 3.10

2,510 2,560 2,612 2,664 2,717 2,771 2,827 2,883 2,941 3,000

4,038 4,111 4,186 4,262 4,340 4,419 4,500 4,582 4,666 4,752

-1,631 -1,664 -1,697 -1,731 -1,766 -1,801 -1,837 -1,874 -1,911 -1,950

0 0 0 0 0 0 0 0 0 0

2,407 2,447 2,489 2,531 2,574 2,618 2,663 2,708 2,755 2,803

-842 -857 -871 -886 -901 -916 -932 -948 -964 -981

1,564 1,591 1,618 1,645 1,673 1,702 1,731 1,760 1,791 1,822

0 0 0 0 0 0 0 0 0 0

A-6



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Gross Capex


Cash flow

Cash tax

After tax cash flow

2066 2067 2068 2069 2070 2071 2072 2073 2074 2075

-1,989 -2,028 -2,069 -2,110 -2,152 0 0 0 0 0

967 967 967 967 967 0 0 0 0 0

6,063 6,063 6,063 6,063 6,063 5,184 4,458 3,856 3,355 2,936

967 967 967 967 967 879 726 602 501 419

8.17 8.33 8.48 8.65 8.81 8.98 9.15 9.33 9.50 9.69

7,899 8,050 8,203 8,360 8,520 7,894 6,641 5,613 4,765 4,063

3.16 3.23 3.29 3.36 3.43 3.49 3.56 3.63 3.71 3.78

3,060 3,121 3,183 3,247 3,312 3,072 2,586 2,188 1,859 1,586

4,840 4,929 5,020 5,113 5,207 4,822 4,055 3,425 2,906 2,477

-1,989 -2,028 -2,069 -2,110 -2,152 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

2,851 2,901 2,951 3,002 3,055 4,822 4,055 3,425 2,906 2,477

-998 -1,015 -1,033 -1,051 -1,069 -1,688 -1,419 -1,199 -1,017 -867

1,853 1,885 1,918 1,952 1,986 3,135 2,636 2,226 1,889 1,610

0 0 0 0 0 0 0 0 0 0

A-7



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Gross Capex


Cash flow

Cash tax

After tax cash flow

2076 2077 2078 2079 2080 2081 2082 2083 2084 2085

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

2,583 2,286 2,035 1,821 1,639 1,475 1,328 1,195 1,075 968

352 297 251 214 182 164 148 133 119 108

9.87 10.06 10.26 10.45 10.65 10.86 11.07 11.28 11.50 11.72

3,478 2,989 2,579 2,233 1,940 1,780 1,633 1,498 1,374 1,261

3.86 3.93 4.01 4.09 4.18 4.26 4.34 4.43 4.52 4.61

1,359 1,169 1,009 875 760 698 641 588 540 496

2,119 1,821 1,570 1,359 1,180 1,082 992 910 834 765

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

2,119 1,821 1,570 1,359 1,180 1,082 992 910 834 765

-742 -637 -550 -476 -413 -379 -347 -318 -292 -268

1,377 1,183 1,021 883 767 703 645 591 542 497

0 0 0 0 0 0 0 0 0 0

A-8



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Gross Capex


Cash flow

Cash tax

After tax cash flow

2086 2087 2088 2089 2090 2091 2092 2093 2094 2095

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

871 784 706 635 571 514 463 417 375 337

97 87 78 71 63 57 51 46 42 37

11.95 12.18 12.42 12.66 12.90 13.15 13.41 13.67 13.93 14.20

1,157 1,061 973 893 819 752 690 633 581 533

4.70 4.80 4.89 4.99 5.09 5.19 5.30 5.40 5.51 5.62

455 418 384 352 323 297 272 250 230 211

701 643 590 541 496 455 417 383 351 322

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

701 643 590 541 496 455 417 383 351 322

-246 -225 -206 -189 -174 -159 -146 -134 -123 -113

456 418 383 352 322 296 271 249 228 209

0 0 0 0 0 0 0 0 0 0

A-9



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Gross Capex


Cash flow

Cash tax

After tax cash flow

2096 2097 2098 2099 2100 2101 2102 2103 2104 2105

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

304 273 246 221 199 179 161 145 131 118

34 30 27 25 22 20 18 16 15 13

14.48 14.76 15.05 15.34 15.64 15.95 16.26 16.58 16.90 17.23

489 448 411 377 346 318 292 268 246 225

5.73 5.85 5.96 6.08 6.20 6.33 6.46 6.58 6.72 6.85

193 178 163 150 137 126 116 106 98 90

295 271 248 228 209 192 176 161 148 136

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

295 271 248 228 209 192 176 161 148 136

-103 -95 -87 -80 -73 -67 -62 -56 -52 -47

192 176 161 148 136 125 114 105 96 88

0 0 0 0 0 0 0 0 0 0

A-10



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Gross Capex


Cash flow

Cash tax

After tax cash flow

2106 2107 2108 2109 2110 2111 2112 2113 2114 2115

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

106 95 86 77 69 63 56 49 42 35

12 11 10 9 8 7 7 7 7 7

17.57 17.91 18.26 18.62 18.98 19.35 19.73 20.12 20.52 20.92

207 190 174 160 147 134 137 140 143 145

6.99 7.13 7.27 7.41 7.56 7.71 7.87 8.03 8.19 8.35

82 75 69 64 58 54 55 56 57 58

124 114 105 96 88 81 82 84 86 87

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

124 114 105 96 88 81 82 84 86 87

-44 -40 -37 -34 -31 -28 -29 -29 -30 -31

81 74 68 62 57 53 54 55 56 57

0 0 0 0 0 0 0 0 0 0

A-11



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Gross Capex


Cash flow

Cash tax

After tax cash flow

2116 2117 2118 2119 2120

0 0 0 0 0

0 0 0 0 0

28 21 14 7 0

7 7 7 7 7

21.33 21.75 22.17 22.61 23.05

148 151 154 157 160

8.52 8.69 8.86 9.04 9.22

59 60 62 63 64

89 91 93 94 96

0 0 0 0 0

0 0 0 0 0

89 91 93 94 96

-31 -32 -32 -33 -34

58 59 60 61 62

0 0 0 0 0

A-12

CONSOL Energy - Legacy Gas


Base Case

PV of cash flows ($B) $0.9 Capital Spending Inputs Development Data (B)

Assumes a blow down of existing proved Starting capex $0.0

Cost of Capital developed reserves with no further capital Peak capex $0.0

WACC (a) 8.4% spending (b) Total tcfe developed 0.0

Total tcfe produced 1.6

Commodity Assumptions Coalbed Methane Opex / mcfe

Current curve strip prices Oil & gas production (d)(e) $1.57

Natural gas (2027) $4.23 Production taxes (e) 3.7%

Oil (2023) $59 SG&A/Corp/Other (e)(f) $0.22

Natural gas Terminal Growth Rate (c) 2.0% Opex / mcfe terminal growth rate (c) 2.0%

LT Production as % of mcfe Other Gas Opex / mcfe

Natural gas 99% Oil & gas production (d)(e) $1.80

NGL 0% Production taxes (e) 5.0%

Oil 1% SG&A/Corp/Other (e)(f) $0.22

Opex / mcfe terminal growth rate (c) 2.0%

Cash tax rate 35%Notes:

Includes Coalbed Methane and Other Gas segments.

Estimated % of mcfe mix of Natural Gas and Oil based on recent segment level production mix.

Legacy gas production is forecast to decline until reported proven developed reserves (as of 12/31/14) are exhausted.

Cash tax calculation based on current & future estimated net operating loss carryforwards.

Incorporates pro rata share of CONSOL in place gas hedges.

Assumed differentials are based on recent results adjusted for a modest improvement over the next several years as additional takeaway capacity comes online.

(a) Using CONSOL corporate WACC calculated in Appendix A-1.

(b) To the extent CONSOL spends incremental capital in its legacy gas business we would expect it to generate incremental production and EBITDA to what is modelled herein.

(c) Terminal growth rate starting in 2028.

(d) Includes transportation, gathering and compression, lifting and direct administrative and selling segment level costs.

(e) Weighted average cost structure from 2016-2027.

(f) Incorporates pro rata net expenses from the Other Gas segment, not directly related to Other Gas segment production.

This includes G&A, corporate, net unutilized FT expense, net gas royalty income, net purchased gas income, exploration and other costs and other income.

B-1



Base Case


2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Capex 0 0 0 0 0 0 0 0 0 0

Reserves Developed (bcfe) 0 0 0 0 0 0 0 0 0 0

Proved Developed Reserves (bcfe) 1,472 1,379 1,290 1,203 1,120 1,041 964 891 820 753

Production (bcfe) 96 93 90 86 83 80 76 73 70 68

Revenues / mcfe ($) 2.68 2.67 2.73 2.82 2.94 3.08 3.23 3.39 3.55 3.70

Revenues 257 248 245 243 244 245 247 249 250 251

Cash opex / mcfe ($) 2.02 2.02 1.99 1.96 1.96 1.97 1.97 1.98 1.98 1.99

Opex 194 187 178 169 163 157 151 145 140 134

EBITDA 64 61 67 74 81 88 96 104 110 116

Capex 0 0 0 0 0 0 0 0 0 0

Cash flow 64 61 67 74 81 88 96 104 110 116

Cash tax 0 0 0 0 0 0 0 -5 -6 -7

After tax cash flow 64 61 67 74 81 88 96 98 104 109

14 14 16 19 21 23 25 22 23 24

B-2



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Capex

Cash flow

Cash tax

After tax cash flow

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

688 625 566 510 456 405 357 311 268 226

65 62 59 56 53 51 48 46 44 41

3.85 3.99 4.07 4.16 4.25 4.34 4.43 4.52 4.61 4.71

250 249 241 234 227 220 214 207 201 195

1.99 1.99 2.03 2.07 2.11 2.15 2.19 2.24 2.28 2.33

129 124 120 116 113 109 106 103 99 96

121 125 121 118 114 111 108 105 102 99

0 0 0 0 0 0 0 0 0 0

121 125 121 118 114 111 108 105 102 99

-8 -22 -23 -23 -22 -22 -22 -22 -21 -21

113 103 98 95 92 89 86 83 80 78

24 25 24 23 23 22 21 20 20 19

B-3



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Capex

Cash flow

Cash tax

After tax cash flow

2036 2037 2038 2039 2040 2041 2042 2043 2044 2045

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

187 161 151 141 133 124 116 108 101 94

39 26 10 9 9 8 8 8 7 7

4.81 4.92 5.09 5.20 5.30 5.41 5.52 5.63 5.74 5.86

189 129 50 49 47 46 45 43 42 41

2.37 2.46 2.71 2.77 2.82 2.88 2.94 2.99 3.05 3.12

93 65 27 26 25 24 24 23 22 22

96 65 24 23 22 21 21 20 20 19

0 0 0 0 0 0 0 0 0 0

96 65 24 23 22 21 21 20 20 19

-21 -15 -6 -6 -6 -6 -6 -6 -5 -5

75 50 17 17 16 16 15 15 14 14

18 18 17 17 16 16 15 15 14 14

B-4



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Capex

Cash flow

Cash tax

After tax cash flow

2046 2047 2048 2049 2050 2051 2052 2053 2054 2055

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

88 81 75 70 64 59 54 50 46 41

7 6 6 6 5 5 5 5 4 4

5.97 6.09 6.21 6.34 6.47 6.60 6.73 6.86 7.00 7.14

39 38 37 36 35 34 33 32 31 30

3.18 3.24 3.31 3.37 3.44 3.51 3.58 3.65 3.72 3.80

21 20 20 19 18 18 17 17 16 16

18 18 17 17 16 16 15 15 14 14

0 0 0 0 0 0 0 0 0 0

18 18 17 17 16 16 15 15 14 14

-5 -5 -5 -5 -5 -5 -4 -4 -4 -4

13 13 12 12 12 11 11 10 10 10

13 13 12 12 12 11 11 10 10 10

B-5



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Capex

Cash flow

Cash tax

After tax cash flow

2056 2057 2058 2059 2060 2061 2062 2063 2064 2065

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

37 34 30 27 24 21 18 15 12 10

4 4 4 3 3 3 3 3 3 2

7.29 7.43 7.58 7.73 7.89 8.05 8.21 8.37 8.54 8.71

29 28 27 26 25 25 24 23 22 22

3.87 3.95 4.03 4.11 4.19 4.28 4.36 4.45 4.54 4.63

15 15 14 14 13 13 13 12 12 11

13 13 13 12 12 11 11 11 10 10

0 0 0 0 0 0 0 0 0 0

13 13 13 12 12 11 11 11 10 10

-4 -4 -4 -4 -4 -3 -3 -3 -3 -3

9 9 9 9 8 8 8 8 7 7

9 9 9 9 8 8 8 8 7 7

B-6



Base Case


Capex



Production (bcfe)

Revenues / mcfe ($)

Revenues


Opex

EBITDA

Capex

Cash flow

Cash tax

After tax cash flow

2066 2067 2068 2069 2070

0 0 0 0 0

0 0 0 0 0

7 5 3 1 0

2 2 2 2 1

8.89 9.06 9.25 9.43 9.62

21 20 20 19 10

4.72 4.82 4.91 5.01 5.11

11 11 10 10 5

10 10 9 9 5

0 0 0 0 0

10 10 9 9 5

-3 -3 -3 -3 -1

7 7 6 6 3

7 7 6 6 3

B-7

CONSOL Energy - Thermal Coal


Base Case

PV of cash flows ($B) $3.0 Commodity Assumptions (b)

2016-2024 Realized Price CAGR 1%

LT Price (starting in 2024) $55

Cost of Capital Development Data

WACC (a) 8.4% Starting Reserves (tons in millions) 762

Annual Production (tons in millions) 26

Final Year of Production 2045

Maintenance Capex per ton $6

Opex / ton

Operating Costs $30

Direct Admin & Selling $1

Royalty/Production Taxes $2

G&A, Corp. & Other Income, Net $1

Cash tax rate 25%

Notes:

Includes CONSOL's Pennsylvania Operations segment. Pennsylvania Operations include the Company's Bailey, Enlow Fork and Harvey Mines.


(b) Reflects mix of contracted and open tons in 2016-2017, with open prices increasing modestly from 2018 to 2024.

C-1



Base Case


2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Reserves Remaining (tons in millions) 736 710 684 658 632 606 580 554 528 502

Production (tons in millions) 26 26 26 26 26 26 26 26 26 26

Revenues / ton ($) 50 51 49 50 51 52 53 54 55 55

Revenues 1,310 1,315 1,281 1,294 1,319 1,348 1,381 1,414 1,430 1,430

Mine Level Cash Opex / ton ($) 33 33 33 33 33 33 33 33 33 33

Mine Level Cash Opex 858 858 858 858 858 858 858 858 858 858

G&A, Corp. & Other Income, Net / ton ($) 1 1 1 1 1 1 1 1 1 1

G&A, Corp. & Other Income, Net 28 28 28 28 28 28 28 28 28 28

EBITDA 423 429 394 408 433 462 494 528 544 544

Capex -143 -143 -143 -143 -143 -143 -143 -143 -143 -143

Cash Flow 280 286 251 265 290 319 351 385 401 401

Cash tax -58 -59 -51 -54 -60 -68 -76 -84 -88 -88

After tax cash flow 222 227 200 210 229 251 276 301 312 312

C-2



Base Case


Reserves Remaining (tons in millions)

Production (tons in millions)

Revenues / ton ($)

Revenues

Mine Level Cash Opex / ton ($)

Mine Level Cash Opex

G&A, Corp. & Other Income, Net / ton ($)

G&A, Corp. & Other Income, Net

EBITDA

Capex

Cash Flow

Cash tax

After tax cash flow

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

476 450 424 398 372 346 320 294 268 242

26 26 26 26 26 26 26 26 26 26

55 55 55 55 55 55 55 55 55 55

1,430 1,430 1,430 1,430 1,430 1,430 1,430 1,430 1,430 1,430

33 33 33 33 33 33 33 33 33 33

858 858 858 858 858 858 858 858 858 858

1 1 1 1 1 1 1 1 1 1

28 28 28 28 28 28 28 28 28 28

544 544 544 544 544 544 544 544 544 544

-143 -143 -143 -143 -143 -143 -143 -143 -143 -143

401 401 401 401 401 401 401 401 401 401

-88 -88 -88 -88 -88 -88 -88 -88 -88 -88

312 312 312 312 312 312 312 312 312 312

C-3



Base Case


Reserves Remaining (tons in millions)

Production (tons in millions)

Revenues / ton ($)

Revenues

Mine Level Cash Opex / ton ($)

Mine Level Cash Opex

G&A, Corp. & Other Income, Net / ton ($)

G&A, Corp. & Other Income, Net

EBITDA

Capex

Cash Flow

Cash tax

After tax cash flow

2036 2037 2038 2039 2040 2041 2042 2043 2044 2045

216 190 164 138 112 86 60 34 8 0

26 26 26 26 26 26 26 26 26 8

55 55 55 55 55 55 55 55 55 55

1,430 1,430 1,430 1,430 1,430 1,430 1,430 1,430 1,430 459

33 33 33 33 33 33 33 33 33 33

858 858 858 858 858 858 858 858 858 276

1 1 1 1 1 1 1 1 1 1

28 28 28 28 28 28 28 28 28 6

544 544 544 544 544 544 544 544 544 177

-143 -143 -143 -143 -143 -143 -143 -143 -143 -46

401 401 401 401 401 401 401 401 401 131

-88 -88 -88 -88 -88 -88 -88 -88 -88 -29

312 312 312 312 312 312 312 312 312 102

C-4

CONSOL Energy - Met Coal and Other


Base Case

PV of cash flows ($B) $0.5 Met (VA Ops) Commodity Assumptions

Short term Met Price (2016-2018) $51

Long term Met Price (starting in 2019) $65

Cost of Capital Met (VA Ops) Development Data

WACC (a) 8.4% Starting Reserves (tons in millions) 203

Annual Production 2016-2017 (tons in millions) 4

Annual Production starting in 2018 (tons in millions) 7

Final Year of Production 2046

Maintenance Capex per ton $6

Met (VA Ops) Opex / ton

Operating Costs $39

Direct Admin & Selling $1

Royalty/Production Taxes $3

G&A, Corp. & Other Income, Net $3

Cash tax rate 25%

Notes:

Includes CONSOL's Virginia Operations segment, Other Coal segment and Other Division (unallocated corporate activities).

Virginia Operations segment includes the Company's Buchanan mine.

Other Coal segment mine level activities include the Company's Miller Creek complex.

Other Coal segment non-mine level activities includes purchased coal, terminal operations, freight, rental income, royalty income, certain gain on sale of assets, right of way,

closed and idle mine costs, coal reserve holding costs, lease rental expense, certain pension and opeb plan expenses and other income and expenses.

Other Division activities include certain bank fees and other unallocated expenses.


D-1



Base Case


2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

VA Ops Reserves Remaining (tons in millions) 200 196 189 182 176 169 162 155 149 142

VA Ops Production (tons in millions) 4 4 7 7 7 7 7 7 7 7

VA Ops Revenues / ton ($) 51 51 51 65 65 65 65 65 65 65

VA Ops Revenues 193 193 347 439 439 439 439 439 439 439

VA Ops Mine Level Cash Opex / ton ($) 44 44 44 44 44 44 44 44 44 44

VA Ops Mine Level Cash Opex 164 164 294 294 294 294 294 294 294 294

VA Ops G&A/Corp/Other Income, Net / ton ($) 3 3 3 3 3 3 3 3 3 3

G&A/Corp/Other Income, Net 13 13 23 23 23 23 23 23 23 23

VA Ops EBITDA 16 16 30 121 121 121 121 121 121 121

Other Coal Ops Production (tons in millions) 2 2 2 2 2 2 2 2 2 0

Other Coal Ops Mine Level EBITDA 11 16 16 16 16 16 16 16 16 0

Other Coal Segment Non-Mine Level EBITDA -35 -29 -23 -17 -11 -5 1 7 13 0

Other Division EBITDA -18 -14 -10 -10 -10 -10 -10 -10 -10 -10

Total EBITDA -25 -9 13 111 117 123 129 135 141 111

Total Capex -35 -35 -53 -53 -53 -53 -53 -53 -53 -41

Cash Flow -60 -44 -39 58 64 70 76 82 88 70

Cash tax 26 22 25 0 -1 -3 -4 -6 -7 -9

After tax cash flow -34 -22 -15 58 63 67 72 76 81 62

D-2



Base Case


VA Ops Reserves Remaining (tons in millions)

VA Ops Production (tons in millions)

VA Ops Revenues / ton ($)

VA Ops Revenues

VA Ops Mine Level Cash Opex / ton ($)

VA Ops Mine Level Cash Opex

VA Ops G&A/Corp/Other Income, Net / ton ($)

G&A/Corp/Other Income, Net

VA Ops EBITDA

Other Coal Ops Production (tons in millions)

Other Coal Ops Mine Level EBITDA

Other Coal Segment Non-Mine Level EBITDA

Other Division EBITDA

Total EBITDA

Total Capex

Cash Flow

Cash tax

After tax cash flow

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

135 128 122 115 108 101 95 88 81 74

7 7 7 7 7 7 7 7 7 7

65 65 65 65 65 65 65 65 65 65

439 439 439 439 439 439 439 439 439 439

44 44 44 44 44 44 44 44 44 44

294 294 294 294 294 294 294 294 294 294

3 3 3 3 3 3 3 3 3 3

23 23 23 23 23 23 23 23 23 23

121 121 121 121 121 121 121 121 121 121

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

-10 -10 -10 -10 -10 -10 -10 -10 -10 -10

111 111 111 111 111 111 111 111 111 111

-41 -41 -41 -41 -41 -41 -41 -41 -41 -41

70 70 70 70 70 70 70 70 70 70

-9 -9 -9 -9 -9 -9 -9 -9 -9 -9

62 62 62 62 62 62 62 62 62 62

D-3



Base Case


VA Ops Reserves Remaining (tons in millions)

VA Ops Production (tons in millions)

VA Ops Revenues / ton ($)

VA Ops Revenues

VA Ops Mine Level Cash Opex / ton ($)

VA Ops Mine Level Cash Opex

VA Ops G&A/Corp/Other Income, Net / ton ($)

G&A/Corp/Other Income, Net

VA Ops EBITDA

Other Coal Ops Production (tons in millions)

Other Coal Ops Mine Level EBITDA

Other Coal Segment Non-Mine Level EBITDA

Other Division EBITDA

Total EBITDA

Total Capex

Cash Flow

Cash tax

After tax cash flow

2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046

68 61 54 47 41 34 27 20 14 7 0

7 7 7 7 7 7 7 7 7 7 7

65 65 65 65 65 65 65 65 65 65 65

439 439 439 439 439 439 439 439 439 439 439

44 44 44 44 44 44 44 44 44 44 44

294 294 294 294 294 294 294 294 294 294 294

3 3 3 3 3 3 3 3 3 3 3

23 23 23 23 23 23 23 23 23 23 23

121 121 121 121 121 121 121 121 121 121 121

0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0

-10 -10 -10 -10 -10 -10 -10 -10 -10 -10 -10

111 111 111 111 111 111 111 111 111 111 111

-41 -41 -41 -41 -41 -41 -41 -41 -41 -41 -41

70 70 70 70 70 70 70 70 70 70 70

-9 -9 -9 -9 -9 -9 -9 -9 -9 -9 -9

62 62 62 62 62 62 62 62 62 62 62

D-4

einhorn consol presentation

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