EQT (EQT) 10-K risk factor changes: FY2019 vs FY2018

[removed: Please note] [added: Note] that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations.

[removed: Natural] [added: Natural] gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect upon our revenue, profitability, future rate of growth, liquidity and financial [removed: position.][added: position.]

[removed: -] [added: | • |] weather conditions and seasonal trends; [added: |]

[removed: -] [added: | • |] the domestic and foreign supply of and demand for natural gas, NGLs and oil; [added: |]

| • | changes in U.S. exports of natural gas, NGLs [removed: and/or] [added: and] oil; |

The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of [removed: $6.88] [added: $4.12] per MMBtu to a low of [removed: $2.48] [added: $1.82] per MMBtu from January 1, [removed: 2018] [added: 2019] through December 31, [removed: 2018,] [added: 2019,] and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of [removed: $77.41] [added: $66.24] per barrel to a low of [removed: $44.48] [added: $46.31] per barrel during the same period.

In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of the significant increases in the supply of natural gas in the Northeast [removed: region] [added: United States] in recent years.

Because our production and reserves predominantly consist of natural gas (approximately [removed: 94%] [added: 95%] of equivalent proved developed reserves), changes in natural gas prices have significantly greater impact on our financial results than oil prices.

Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, [removed: oil and] NGLs [added: and oil] at the Company's ultimate sales points and thus cannot predict the ultimate impact of prices on our operations.

Declines in prices could also adversely affect our drilling activities and the amount of natural gas, NGLs and oil that we can produce economically, which may result in our having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to [removed: earnings in future periods.][added: earnings.]

See [removed: “Impairment] [added: "Impairment] of Oil and Gas [removed: Properties and Goodwill” under] [added: Properties" in] Item [removed: 7, “Management’s] [added: 7., "Management's] Discussion and Analysis of Financial Condition and Results [removed: of Operations” and “Natural gas, NGLs and oil price declines have resulted in impairment of certain of our non-core assets.]

Future declines in commodity prices, increases in operating costs or adverse changes in well performance [added: or additional changes in our development strategy] may result in additional write-downs of the carrying amounts of our assets, including [removed: long lived] [added: long-lived] intangible assets, which could materially and adversely affect our results of operations in future [removed: periods.” We are also exposed to the risk][added: periods.]

Significant natural gas price increases may subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including swap, collar and option agreements and exchange-traded [removed: instruments)] [added: instruments),] which would potentially require us to post significant amounts of cash collateral with our hedge counterparties.

[removed: Drilling] [added: Drilling] for and producing natural gas and oil are high-risk and costly activities with many uncertainties.

Our future financial position, cash flows and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas or oil production or that we will not recover all or any portion of our investment in such [removed: wells.][added: wells.]

[removed: Our] [added: Further, our] decisions to purchase, explore or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

For a discussion of the uncertainty involved in these processes, see [removed: “Our] [added: "Our] proved reserves are estimates that are based [removed: upon] [added: on] many assumptions that may prove to be inaccurate.

[removed: Further, many] [added: Many] factors may curtail, delay or cancel our scheduled drilling projects, including the following:

| • | lack of available gathering [added: and water] facilities or delays in construction of gathering [added: and water] facilities; |

[removed: Our] [added: Our] drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our drilling [removed: locations.][added: locations.]

[added: Our] ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, topography, gathering system and pipeline transportation costs and constraints, access to and availability of water sourcing and distribution systems, coordination with coal mining, regulatory approvals and other factors.

For more information on our drilling locations, see [removed: “Item 2.][added: Item 1., "Business."]

[removed: The] [added: The] amount and timing of actual future natural gas, NGLs and oil production is difficult to predict and may vary significantly from our estimates, which may reduce our [removed: earnings.][added: earnings.]

[removed: Our] [added: Our] proved reserves are estimates that are based [removed: upon] [added: on] many assumptions that may prove to be inaccurate.

Any significant change in these underlying assumptions will greatly affect the quantities and present value of our [removed: reserves.][added: reserves.]

[removed: Numerous changes over time to the] assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas, NGLs and oil we ultimately recover being different from our reserve estimates.

[removed: The] [added: The] standardized measure of discounted future net cash flows from our proved reserves is not the same as the current market value of our estimated natural gas, NGLs and [added: crude] oil [removed: reserves.][added: reserves.]

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated natural gas, NGLs and [added: crude] oil reserves.

In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the [removed: twelve month] [added: twelve-month] unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions.

In addition, the 10% discount factor we use when calculating the standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with [removed: us] [added: our operations] or the natural gas, NGLs and oil industry in general.

[removed: Strategic] [added: Strategic] determinations, including the allocation of capital and other resources to strategic opportunities, are [removed: challenging] [added: challenging,] and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial position and reduce our future [removed: growth rate.][added: prospects.]

Our future [removed: growth] prospects are dependent upon our ability to identify optimal strategies for our business.

In developing our business plan, we considered allocating capital and other resources to various aspects of our business, including well development, reserve acquisitions, [removed: exploratory activities,] corporate items, leasehold maintenance and other alternatives.

[removed: Our] [added: Our] exploration and production operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory [removed: terms.][added: terms.]

If we do not have sufficient borrowing availability under our revolving credit [removed: facility due to the current commodity price environment or otherwise,] [added: facility,] we may seek alternate debt or equity financing, sell assets or reduce our capital expenditures.

[removed: -] [added: | • |] our level of proved reserves and production; [added: |]

[removed: -] [added: | • |] the level of hydrocarbons we are able to produce from existing wells; [added: |]

[removed: -] [added: | • |] our access to, and the cost of accessing, end markets for our production; [added: |]

[removed: -] [added: | • |] the prices at which our production is sold; [added: |]

of Operations" and "Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets.

Numerous changes over time to the

We are under the leadership of a substantially reconstituted Board of Directors and a new executive management team who have implemented a variety of operational, organizational, cultural and other changes to our business and reserves development strategy, and we may not be able to achieve some or all of the anticipated benefits from the transformation plan or reserves development strategy.

Our Board of Directors was substantially reconstituted at our annual meeting of shareholders on July 10, 2019 and, following that meeting, Toby Z.

Rice was appointed as President and Chief Executive Officer.

Thereafter, our new executive management team implemented a detailed transformation plan designed to effect operational, organizational, cultural and other changes to our business in order to lower operating costs and increase free cash flow generation through improved efficiency, well performance and the use of technology, with a primary focus on repositioning the Company to effectively execute on large-scale combo-development projects, which consist of developing multiple wells and pads simultaneously.

Additionally, we cannot be certain that we will be able to successfully execute combo-development projects at the pace and scale that we project, which may delay or reduce our production and our reserves, negatively affecting our associated revenues.

We may not be able to successfully execute our plan to deleverage our business or otherwise reduce our debt level.

In the fourth quarter of 2019, we announced the Deleveraging Plan.

There can be no assurance that we will be able to find attractive asset monetization opportunities or that any such transactions will be completed on our anticipated timeframe, if at all.

Furthermore, our estimated value for the assets to be monetized under the Deleveraging Plan involves multiple assumptions and judgments about future events that are inherently uncertain; accordingly, there can be no assurance that the resulting net cash proceeds from asset monetization transactions will be as anticipated, even if such transactions are consummated.

Some of the factors that could affect our ability to successfully execute the Deleveraging Plan include changes in the financial condition or prospects of prospective purchasers and the availability of financing to potential purchasers on reasonable terms, the number of prospective purchasers, the number of competing assets on the market, unfavorable economic conditions, industry trends and changes in laws and regulations.

If we are not able to successfully execute the Deleveraging Plan or otherwise reduce absolute debt to a level we believe

appropriate, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise or delay our strategic plans.

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In January 2020, Moody's downgraded our senior notes rating to "Ba1" with a "Negative" outlook.

In February 2020, S&P downgraded our senior notes rating to "BB+" with a "Negative" outlook, and Fitch downgraded our senior notes rating to "BB" with a "Negative" outlook.

See Note 10 to the Consolidated Financial Statements for a discussion of the effects of the downgrades on our financial statements subsequent to December 31, 2019.

If there are further downgrades to our credit rating, our access to the capital markets may be impacted, the cost of short-term debt through interest rates and fees under our lines of credit may increase, the interest rate on our Term Loan Facility and Adjustable Rate Notes (each defined in Note 10 to the Consolidated Financial Statements) will increase, the rates available on new long-term debt may increase, our pool of investors and funding sources may decrease, the borrowing costs and margin deposit requirements on our derivative instruments may increase and we may be required to provide additional credit assurances, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts, which could adversely affect our business, results of operations and liquidity.

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Uncertainty related to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of our current or future debt obligations.

Loans to us under our credit facility may be base rate loans or LIBOR loans.

LIBOR is calculated by reference to a market for interbank lending, and it's based on increasingly fewer actual transactions.

This increases the subjectivity of the LIBOR calculation process and increases the risk of manipulation.

of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in our derivative contracts having a positive fair value in our favor.

Our

Properties.”

If any credit rating agency downgrades our ratings, particularly below investment grade, our access to the capital markets may be limited, borrowing costs and margin deposits on our derivatives would increase, we may be required to provide additional credit assurances in support of pipeline capacity contracts, the amount of which may be substantial, or we may be required to provide additional credit assurances related to joint venture arrangements or construction contracts, which could adversely affect our business, results of operations and liquidity.

Investment grade refers to the quality of a company’s credit as assessed by one or more credit rating agencies.

In order to be considered investment grade, a company must be rated “BBB-” or higher by S&P, “Baa3” or higher by Moody’s and “BBB-” or higher by Fitch.

Historically our ownership interest in and control of EQM Midstream Partners, LP (EQM) and Rice Midstream Partners LP (RMP) allowed us to exercise greater control over the development of midstream infrastructure to service our operations.

However, as a result of the Separation, we no longer control those operations and facilities and will be dependent on Equitrans Midstream and other third-party providers of these services.

In addition, some of our third-party contracts involve significant long-term financial commitments on our part and could reduce our cash flow during periods of low prices for natural gas, NGLs and oil.

Our usage of third parties for transmission, gathering and processing services subjects us to the performance risk of such third parties and may make us dependent upon those third parties to get our produced natural gas, NGLs and oil to market.

Following the U.S. Supreme Court’s decision, the EPA and the Corps issued a final rule in January 2018 staying implementation of the WOTUS rule for two years while the agencies reconsider the rule, but a federal judge barred the agencies’ suspension of the rule in August 2018.

Subsequently, various district court decisions

revived the WOTUS rule in 22 states, the District of Columbia, and the U.S. territories and enjoined implementation of the rule in 28 states.

In December 2018, the EPA and the Corps released a proposal to redefine the definition of WOTUS.

The proposed definition may be subject to an expanded comment period and future litigation.

As a result, future implementation of the WOTUS rule is uncertain at this time.

While Pennsylvania is not currently a member of the RGGI, a multi-state regional cap and trade program comprised of several Eastern U.S. states, it is possible that it may join RGGI in the future.

This could result in increased operating costs if our operations are required to purchase emission allowances.

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades.

In addition, our business may be negatively impacted if we are unable to effectively manage our expanded operations going forward.

The integration has required and will continue to require significant time and focus from management and could disrupt current plans and operations, which could delay the achievement of our strategic objectives.

In connection with the Separation, we

The Separation may not achieve some or all of the anticipated benefits.

As independent publicly-traded companies, we and Equitrans Midstream are smaller, less diversified companies with a narrower business focus and may be more vulnerable to changing market conditions, which could materially adversely affect our and its results of operations, cash flows and financial position.

Further, we may be required to expend additional resources to consolidate and/or upgrade our information technology processes and systems to achieve our strategic goals.

[removed: You should read the] [added: *The] following discussion and analysis of financial condition and results of operations [added: should be read] in conjunction with the [removed: consolidated financial statements,] [added: Consolidated Financial Statements] and the notes [removed: thereto,] [added: thereto] included in Item [removed: 8] [added: 8., "Financial Statements and Supplementary Data." For all periods prior to the Separation and Distribution, the results] of [removed: this Annual Report on Form 10-K.][added: operations of Equitrans Midstream are reflected as discontinued operations.]

[removed: The Statements of Consolidated Operations and Consolidated Balance Sheets of] [added: Cash flows related to] Equitrans Midstream are [removed: reflected as discontinued operations] [added: included in the Statements of Consolidated Cash Flows] for all periods [removed: presented.][added: prior to the Separation and Distribution.]

See Note 2 to the Consolidated Financial Statements for amounts [removed: of the] [added: attributable to] discontinued operations [removed: related to Equitrans Midstream which are] included in the Statements of Consolidated Cash Flows.

[removed: Consolidated] [added: Consolidated] Results of [removed: Operations][added: Operations]

Loss from continuing operations for [removed: 2018] [added: 2019] was [removed: $2.4 billion, a loss of $9.12] [added: $1,222 million, $4.79] per diluted share, [added: an improvement of $1,159 million] compared [removed: with income] [added: to loss] from continuing operations [added: for 2018] of [removed: $1.4 billion, $7.39] [added: $2,381 million, $9.12] per diluted [removed: share, in 2017.][added: share.]

See [removed: “Sales] [added: "Sales] Volumes and [removed: Revenues”] [added: Revenues," "Production-Related Operating Expenses"] and [removed: “Operating Expenses”] [added: "Other Operating Expenses"] for [removed: a discussion] [added: discussions] of items [removed: impacting] [added: affecting] operating income and [removed: “Other] [added: "Other] Income Statement [removed: Items”] [added: Items"] for a discussion of other income statement items.

[removed: Average] [added: Average] Realized Price [removed: Reconciliation][added: Reconciliation]

See [removed: “Reconciliation] [added: "Reconciliation] of Non-GAAP Financial [removed: Measures”] [added: Measures"] for a reconciliation of adjusted operating revenues [removed: to] [added: with] total operating [removed: revenues.][added: revenues, the most directly comparable financial measure calculated in accordance with GAAP.]

| | [removed: Years] [added: Years] Ended December [removed: 31, | | | |] [added: 31,] | | | | | | |

| | [removed: (Thousands,] [added: (Thousands,] unless [removed: noted) | | | |] [added: otherwise noted)] | | | | | | |

| [removed: NATURAL GAS | | | |] [added: NATURAL GAS] | | | | | | | |

| Sales volume (MMcf) | [removed: 1,386,718 | | | | 774,076] [added: 1,435,134] | | | | [removed: 683,495] [added: 1,386,718] | | |

| NYMEX price ($/MMBtu) (a) | $ | [removed: 3.10 | | | $ | 3.09] [added: 2.63] | | | $ | [removed: 2.47] [added: 3.10] | |

| Btu uplift | [removed: $ | 0.19 | | | $] [added: 0.13] | [removed: 0.27] | | | [removed: $] [added: 0.19] | [removed: 0.22] | |

| Natural gas price ($/Mcf) | $ | [removed: 3.29 | | | $ | 3.36] [added: 2.76] | | | $ | [removed: 2.69] [added: 3.29] | |

| Basis ($/Mcf) (b) | [removed: (0.25 | | ) | | (0.54] [added: $] | [added: (0.28] | ) | | [removed: (0.81] [added: $] | [added: (0.25] | ) |

| Cash settled basis swaps (not designated as hedges) ($/Mcf) | [removed: $] [added: (0.04] | [removed: (0.08] | ) | | [removed: $ | 0.01 | | | $] [added: (0.08] | [removed: 0.09] | [added: )] |

| Average differential, including cash settled basis swaps ($/Mcf) | $ | [removed: (0.33 | ) | | $ | (0.53] [added: (0.32] | ) | | $ | [removed: (0.72] [added: (0.33] | ) |

| Average adjusted price ($/Mcf) | $ | [removed: 2.96 | | | $ | 2.83] [added: 2.44] | | | $ | [removed: 1.97] [added: 2.96] | |

| Cash settled derivatives [removed: (cash flow] [added: (not designated as] hedges) ($/Mcf) | [removed: — | | | | 0.01] [added: 0.21] | | | | [removed: 0.13] [added: (0.07] | | [added: )] |

| Cash settled derivatives (not designated as hedges) [removed: ($/Mcf) | (0.07 | | ) |] [added: ($/Bbl)] | [removed: 0.05] [added: 1.02] | | | | [removed: 0.31] [added: —] | | |

| Average natural gas price, including cash settled derivatives ($/Mcf) | $ | [removed: 2.89] [added: 2.65] | | | $ | 2.89 | | [removed: | $ | 2.41 | |]

| Natural gas sales, including cash settled derivatives | $ | [removed: 4,004,147 | | | $ | 2,237,234] [added: 3,805,977] | | | $ | [removed: 1,649,831] [added: 4,004,147] | |

| [removed: LIQUIDS | | | |] [added: LIQUIDS] | | | | | | | |

| [removed: NGLs (excluding ethane): | | | |] [added: NGLs, excluding ethane:] | | | | | | | |

| Sales volume (MMcfe) (c) | [removed: 63,247 | | | | 74,060] [added: 44,082] | | | | [removed: 57,243] [added: 63,247] | | |

| Price ($/Bbl) | $ | [removed: 37.63 | | | $ | 31.59] [added: 23.63] | | | $ | [removed: 19.43] [added: 37.63] | |

| Cash settled derivatives (not designated as hedges) ($/Bbl) | [removed: (1.07] [added: 2.19] | | [removed: )] | | [removed: (0.69] [added: (1.07] | | ) | [removed: | — | | |]

| Average [removed: NGL] [added: NGLs] price, including cash settled derivatives ($/Bbl) | $ | [removed: 36.56 | | | $ | 30.90] [added: 25.82] | | | $ | [removed: 19.43] [added: 36.56] | |

| NGLs sales | $ | [removed: 385,364 | | | $ | 381,327] [added: 189,718] | | | $ | [removed: 185,405] [added: 385,364] | |

| [removed: Ethane: | | | |] [added: Ethane:] | | | | | | | |

| Sales volume (MMcfe) (c) | [removed: 33,645 | | | | 33,432] [added: 23,748] | | | | [removed: 13,856] [added: 33,645] | | |

| Price ($/Bbl) | $ | [removed: 8.09 | | | $ | 6.32] [added: 6.16] | | | $ | [removed: 5.08] [added: 8.09] | |

| Ethane sales | $ | [removed: 45,339 | | | $ | 35,241] [added: 28,414] | | | $ | [removed: 11,742] [added: 45,339] | |

| [removed: Oil: | | | |] [added: Oil:] | | | | | | | |

| Sales volume (MMcfe) (c) | [removed: 4,079 | | | | 5,952] [added: 4,932] | | | | [removed: 4,373] [added: 4,079] | | |

| Price ($/Bbl) | $ | [removed: 52.70 | | | $ | 40.70] [added: 40.90] | | | $ | [removed: 34.73] [added: 52.70] | |

| Oil sales | $ | [removed: 35,825 | | | $ | 40,376] [added: 33,620] | | | $ | [removed: 25,312] [added: 35,825] | |

| Total liquids sales volume (MMcfe) (c) | [removed: 100,971 | | | | 113,444] [added: 72,762] | | | | [removed: 75,472] [added: 100,971] | | |

| Total liquids sales volume [removed: (Mbbls) | 16,829 | | |] [added: (Mbbl)] | [removed: 18,907] [added: 12,127] | | | | [removed: 12,578] [added: 16,829] | | |

The Statements of Consolidated Operations for the years ended December 31, 2018 and 2017 have been recast to reflect discontinued operations and include certain transportation and processing expenses in continuing operations that had previously been eliminated in consolidation.

The variance was attributable primarily to lower impairments of long-lived assets and goodwill and higher dividends received on the Company's investment in Equitrans Midstream, partly offset by lower income tax benefit and higher impairment and expiration of leases, unrealized loss on the Company's investment in Equitrans Midstream and operating revenues.

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in the Company's Annual Report on [Form 10-K](http://www.sec.gov/Archives/edgar/data/33213/000003321319000006/eqt1231201810k.htm) for the year ended December 31, 2018, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2017.

See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures.

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| | 2019 | | | | 2018 | | |

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| Sales volume (Mbbl) | 7,348 | | | | 10,542 | | |

| Sales volume (Mbbl) | 3,957 | | | | 5,607 | | |

| Average Ethane price, including cash settled derivatives ($/Bbl) | $ | 7.18 | | | $ | 8.09 | |

| Sales volume (Mbbl) | 822 | | | | 680 | | |

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| Total liquids sales | $ | 251,752 | | | $ | 466,528 | |

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| | 2019 | | | | 2018 | | |

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| | 2019 | | | | 2018 | | | | % | |

| Marcellus (a) | 1,270,352 | | | | 1,229,934 | | | | 3.3 | |

| Ohio Utica | 231,545 | | | | 209,428 | | | | 10.6 | |

| Other | 5,999 | | | | 48,327 | | | | (87.6 | ) |

| Total sales volumes (b) | 1,507,896 | | | | 1,487,689 | | | | 1.4 | |

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| Operating revenues: | | | | | | | | | | |

| Total operating revenues | $ | 4,416,484 | | | $ | 4,557,868 | | | (3.1 | ) |

Excluding 2018 sales volumes related to the 2018 Divestitures (discussed in Note 7 to the

Consolidated Financial Statements), sales volumes increased by 4.2% in 2019.

Average realized price decreased due to lower NYMEX and liquids prices and lower Btu uplift, partly offset by higher cash settled derivatives.

The loss for 2018 was related primarily to settlements of NYMEX swaps and options and basis swaps, partly offset by decreases in NYMEX forward prices.

Prior periods have been recast to reflect this presentation.

This recast also includes presenting certain transportation and processing expenses in continuing operations for all periods presented which were previously eliminated in consolidation prior to the Separation and Distribution.

The cash flows related to Equitrans Midstream have not been segregated and are included within the Statements of Consolidated Cash Flows for all periods presented.

Key Events in 2018:

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| • | Completed the Separation and Distribution on November 12, 2018 |

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| • | Completed the 2018 Divestitures |

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| • | Achieved annual sales volumes of 1,488 Bcfe and average daily sales volumes of 4,076 MMcfe/d. Adjusted for the impact of the 2018 Divestitures, total annual sales volumes were 1,447 Bcfe or 3,964 MMcfe/d. |

See further discussion of the Separation, Distribution and the 2018 Divestitures as discussed in the "Key Events in 2018" section of Item 1, "Business."

The $3.8 billion decrease was primarily attributable to $3.5 billion of impairments and losses on the sale of long-lived assets including: $2.7 billion associated with the 2018 Divestitures, goodwill impairment and higher lease impairments.

Excluding these items, a $1.5 billion increase in operating revenues was offset by higher operating expenses including depreciation and depletion and transportation and processing expenses and higher interest expense as well as a lower tax benefit.

Income from continuing operations for 2017 was $1.4 billion, $7.39 per diluted share, compared with a loss from continuing operations of $0.5 billion, a loss of $3.18 per diluted share, in 2016.

The $1.9 billion increase in income from continuing operations was primarily attributable to higher sales of natural gas, oil and NGLs, an income tax benefit recorded as a result of the lower federal corporate tax rate beginning in 2018 and a gain on derivatives not designated as hedges in 2017 compared to a loss in 2016, partly offset by higher operating expenses, higher interest expense and a loss on debt extinguishment in 2017.

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| | 2018 (e) | | | | 2017 (e) | | | | 2016 | | |

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| Sales volume (Mbbls) | 10,542 | | | | 12,343 | | | | 9,540 | | |

| Sales volume (Mbbls) | 5,607 | | | | 5,572 | | | | 2,309 | | |

| Sales volume (Mbbls) | 680 | | | | 992 | | | | 729 | | |

| | | | | | | | | | | | |

| | | | | | | | | | | | |

| Liquids sales | $ | 466,528 | | | $ | 456,944 | | | $ | 222,459 | |

| | | | | | | | | | | | |

| | | | | | | | | | | | |

| (e) | For the year ended December 31, 2018, results include operations acquired in the Rice Merger (defined in Note 3 to the Consolidated Financial Statements). For the year ended December 31, 2017, results include operations acquired in the Rice Merger for the period of November 13, 2017 through December 31, 2017. |

| | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | | | | |

| | 2018 | | | | 2017 | | | | 2016 | | |

| | | | | | | | | | | | |

[removed: Commodity] [added: Commodity] Price Risk and Derivative [removed: Instruments][added: Instruments]

Due to the volatility of commodity prices, the Company is unable to predict future potential movements in the market prices for natural [removed: gas,] [added: gas] and NGLs at the Company's ultimate sales points [removed: and thus] [added: and, thus,] cannot predict the ultimate impact of prices on its operations.

Prolonged low, [removed: and/or significant] or [added: significant,] extended declines in, natural gas and NGLs prices could adversely affect, among other things, the [removed: Company’s] [added: Company's] development plans, which would decrease the pace of development and the level of the [removed: Company’s] [added: Company's] proved reserves.

The Company's use of derivatives is further described in [removed: Notes 1 and 5] [added: Note 4] to the Consolidated Financial Statements and [removed: under the caption “Commodity] [added: "Commodity] Risk [removed: Management” in the] [added: Management" of] "Capital Resources and Liquidity" [removed: section of] [added: in] Item [removed: 7, “Management’s] [added: 7., "Management's] Discussion and Analysis of Financial Condition and Results of [removed: Operations.”] [added: Operations."] The Company's OTC derivative commodity instruments are placed primarily with financial institutions and the creditworthiness of [removed: these] [added: those] institutions is regularly monitored.

The Company also enters into derivative instruments to hedge basis and exposure to [added: fluctuations in interest rates.]

The [removed: Company’s] [added: Company's] use of derivative instruments is implemented under a set of policies approved by the [removed: Company’s] [added: Company's] Hedge and Financial Risk Committee and reviewed by the [removed: Audit Committee of the Company’s] [added: Company's] Board of Directors.

For [removed: the] derivative commodity instruments used to hedge the [removed: Company’s] [added: Company's] forecasted sales of production, [removed: most of] which are [removed: hedged at] [added: at, for the most part,] NYMEX natural gas prices, the Company sets policy limits relative to the expected production and sales levels [removed: which] [added: that] are exposed to price risk.

[removed: The derivative commodity instruments currently utilized by the Company are primarily fixed price swap agreements, collar agreements and option] [added: These] agreements [removed: which] may require payments [removed: to] [added: to,] or receipt of payments [removed: from] [added: from,] counterparties based on the differential between two prices for the commodity.

The Company may also use other contractual agreements [removed: in] [added: when] implementing its commodity hedging strategy.

The [removed: Company’s] [added: Company's] overall objective in its hedging program is to protect [removed: a portion of] cash flows from undue exposure to the risk of changing commodity prices.

A hypothetical decrease of 10% in the market price of natural gas from [removed: the] December 31, [removed: 2018] [added: 2019] and [removed: 2017 levels] [added: 2018] would [removed: have increased] [added: increase] the fair value of these natural gas derivative instruments by approximately [removed: $432.5] [added: $389.4] million and [removed: $386.2] [added: $432.5] million, respectively.

A hypothetical increase of 10% in the market price of natural gas from [removed: the] December 31, [removed: 2018] [added: 2019] and [removed: 2017 levels] [added: 2018] would [removed: have decreased] [added: decrease] the fair value of these natural gas derivative instruments by approximately [removed: $443.4] [added: $394.5] million and [removed: $384.9] [added: $443.4] million, respectively.

The [removed: Company determined the] change in [removed: the] fair value [removed: of the derivative commodity instruments] [added: was determined] using a method similar to [removed: its] [added: the Company's] normal [removed: determination of] [added: process for determining derivative commodity instrument] fair value [removed: as] described in Note [removed: 1] [added: 5] to the Consolidated Financial Statements.

The above analysis of the [added: Company's] derivative commodity instruments [removed: held by the Company] does not include the offsetting impact that the same hypothetical price movement may have on the [removed: Company’s] [added: Company's] physical sales of natural gas.

[removed: Therefore,] [added: The portfolio of derivative commodity instruments held to hedge the Company's forecasted produced gas approximates a portion of the Company's expected physical sales of natural gas; therefore,] an adverse impact to the fair value of the portfolio of derivative commodity instruments held to hedge the [removed: Company’s] [added: Company's] forecasted production associated with the hypothetical changes in commodity prices referenced above should be offset by a favorable impact on the [removed: Company’s] [added: Company's] physical sales of natural gas, assuming [added: that] the derivative commodity instruments are not closed out in advance of their expected [removed: term,] [added: term] and the derivative commodity instruments continue to function effectively as hedges of the underlying risk.

[removed: Interest] [added: Interest] Rate [removed: Risk][added: Risk]

Changes in interest rates affect the amount of interest the Company earns on cash, cash equivalents and short-term investments and the interest [removed: rate] [added: rates] the Company pays on borrowings under its [removed: revolving] credit [removed: facility] [added: facility, Term Loan Facility] and [removed: the Company's Floating Rate Notes.][added: floating rate notes (which notes were fully redeemed on February 3, 2020).]

All of the [removed: Company’s Senior Notes,] [added: Company's senior notes,] other than the [removed: Floating Rate Notes, are] [added: floating rate notes, have a] fixed rate [removed: and thus] [added: and, thus,] do not expose the Company to fluctuations in [removed: its results of operations or liquidity from changes in] market interest rates.

See Note 10 to the Consolidated Financial Statements for further discussion of the [removed: Company’s borrowings, as applicable,] [added: Company's long-term debt] and Note [removed: 6] [added: 5] to the Consolidated Financial Statements for a discussion of fair value measurements, including the fair value of [added: the Company's] long-term debt.

[removed: Other] [added: Other] Market [removed: Risks][added: Risks]

The Company is exposed to credit loss in the event of nonperformance by counterparties to [added: its] derivative contracts.

The [removed: Company’s] [added: Company's] OTC derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those [added: companies individually as well as the financial industry as a whole.]

The Company [removed: utilizes] [added: uses] various processes and analyses to monitor and evaluate its credit risk [removed: exposures.][added: exposures, including monitoring current market conditions and counterparty credit fundamentals.]

To manage the level of credit risk, the Company enters into transactions [added: primarily] with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.

Approximately [removed: 63%,] [added: 75%,] or [removed: $242.0] [added: $718.0] million, of the [removed: Company’s] [added: Company's] OTC derivative contracts outstanding at December 31, [removed: 2017] [added: 2019] had a positive fair value.

As of December 31, [removed: 2018,] [added: 2019,] the Company was not in default under any derivative contracts and had no knowledge of default by any counterparty to its derivative contracts.

[removed: The] [added: During the year ended December 31, 2019, the] Company made no adjustments to the fair value of [added: its] derivative contracts due to [removed: credit related] [added: credit-related] concerns outside of the normal non-performance risk adjustment included in the [removed: Company’s] [added: Company's] established fair value procedure.

The Company monitors market conditions that may impact the fair value of [added: its] derivative [removed: contracts reported in the Consolidated Balance Sheets.][added: contracts.]

The Company is [removed: also] exposed to the risk of nonperformance by credit customers on physical sales of natural gas, NGLs and oil.

[removed: A significant amount of revenues] [added: Revenues] and related accounts receivable [added: from the Company's operations] are generated [added: primarily] from the sale of produced natural [removed: gas and] [added: gas,] NGLs [added: and oil] to [removed: certain] marketers, [removed: utility] [added: utilities] and industrial customers located in the Appalachian Basin and in markets [removed: available] [added: that are accessible] through the Company's [removed: current] transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States [removed: as well as] [added: and] Canada.

No one lender of the large group of financial institutions in the syndicate for the [removed: EQT] [added: Company's] credit facility [added: and the Term Loan Facility] holds more than 10% [added: and 15%, respectively,] of the [removed: respective facility.][added: financial commitments under such facilities.]

Derivative commodity instruments used by the Company are primarily swap, collar and option agreements.

The Company uses these agreements to hedge its NYMEX and basis exposure.

For purposes of this analysis, the Company applied the 10% change in the market price of natural gas from December 31, 2019 and 2018 to the Company's natural gas derivative commodity instruments to calculate the hypothetical change in fair value.

A 1% increase in interest rates on the Company's

borrowings under its credit facility, Term Loan Facility and floating rate notes during the year ended December 31, 2019 would have increased 2019 annual interest expense by approximately $14 million.

Interest rates on the Adjustable Rate Notes fluctuate based on changes to the credit ratings assigned to the Company's senior notes by Moody's, S&P and Fitch.

For a discussion of credit rating downgrade risk, see Item 1A., "Risk Factors – Our exploration and production operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms." Changes in interest rates affect the fair value of the Company's fixed rate debt.

The Company uses derivatives to reduce the effect of commodity price volatility.

fluctuations in interest rates.

For information on the quantity of derivative commodity instruments held by the Company, see Note 5 to the Consolidated Financial Statements and the “Commodity Risk Management” section in the “Capital Resources and Liquidity” section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

The Company assumed a 10% change in the price of natural gas from its levels at December 31, 2018 and December 31, 2017.

The price change was then applied to these natural gas derivative commodity instruments recorded on the Company’s Consolidated Balance Sheets, resulting in the hypothetical change in fair value.

The portfolio of derivative commodity instruments held to hedge the Company’s forecasted produced gas approximates a portion of the Company’s expected physical sales of natural gas.

Changes in interest rates do affect the fair value of the Company’s fixed rate debt.

companies individually as well as the financial industry as a whole.

These include closely monitoring current market conditions, counterparty credit fundamentals and credit default swap rates.

[removed: General][added: General]

EQT [removed: Corporation (EQT or the Company)] is a natural gas production company with [removed: emphasis] [added: operations focused] in the [removed: Appalachian Basin and operations throughout Pennsylvania, West Virginia] [added: Marcellus] and [removed: Ohio.][added: Utica shales of the Appalachian Basin.]

[removed: Strategy][added: Strategy]

[removed: Outlook][added: Outlook]

[removed: The] [added: During 2019, the] Company [removed: plans to spud approximately 134] [added: commenced drilling operations (spud) on 122] gross wells [removed: (126] [added: (114] net), including [removed: 91 Marcellus wells in Pennsylvania, 15] [added: 89 Pennsylvania] Marcellus [added: gross] wells [removed: in] [added: (87 net), 6] West Virginia [added: Marcellus gross wells (6 net)] and [removed: 28] [added: 27] Ohio Utica gross wells [removed: (20] [added: (21] net).

The [removed: Company’s] [added: Company's] revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the [removed: Company’s] [added: Company's] ability to develop its reserves of, natural gas, [removed: oil] [added: NGLs] and [removed: NGLs.][added: oil.]

Due to the volatility of commodity prices, the Company is unable to predict future potential movements in the market prices for natural gas, [removed: and] NGLs [added: and oil] at the Company's ultimate sales [removed: points and thus cannot predict the ultimate impact of prices on its operations.]

Lower prices [added: and changes in development plans] could also result in non-cash impairments in the book value of the [removed: Company’s] [added: Company's] oil and gas properties or other [removed: long lived] [added: long-lived] intangible assets or downward adjustments to the [removed: Company’s] [added: Company's] estimated proved reserves.

Any such [removed: impairment and/or] [added: impairments or] downward [removed: adjustment] [added: adjustments] to the [removed: Company’s] [added: Company's] estimated reserves could potentially be material to the Company.

See "Impairment of Oil and Gas [removed: Properties and Goodwill"] [added: Properties"] and [removed: “Critical] [added: "Critical] Accounting Policies and [removed: Estimates”] [added: Estimates"] included in Item [removed: 7, "Management’s] [added: 7., "Management's] Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of the [removed: Company’s] [added: Company's] accounting policies and significant assumptions related to accounting for oil and gas producing activities and the Company's [added: accounting] policies and processes [removed: with respect] [added: related] to impairment reviews for proved and unproved property and goodwill.

[removed: Segment] [added: Segment] and Geographical [removed: Information][added: Information]

[removed: Proved Reserves][added: | | Proved Undeveloped Reserves | |]

| [removed: (Bcfe)] | [removed: | Marcellus] [added: Marcellus] | | | [removed: Upper Devonian] [added: Upper Devonian] | | | [removed: Ohio Utica] [added: Ohio Utica] | | | [removed: Other] [added: Other] | | | [removed: Total] [added: Total] | |

| | [removed: | Years] [added: Years] Ended December [removed: 31,] [added: 31,] | | | | | | | | | | |

| | [removed: | 2018] [added: 2019] | | | | [removed: 2017] [added: 2018] | | | | [removed: 2016] [added: 2017] | | |

| | [removed: | (Millions)] [added: (Millions)] | | | | | | | | | | |

| [removed: Ohio] Utica | [removed: | 360] [added: 193] | | | | [removed: 50] [added: 360] | | | | [removed: 58] [added: 50] | | |

| Other | [removed: |] — | | | | [removed: 21] [added: —] | | | | [removed: 6] [added: 21] | | |

[removed: *] [added: | (a) |] Includes Upper Devonian formations. [added: |]

[removed: The] [added: In addition, the] Company [removed: has also] [added: is] committed to an initial 1.29 Bcf per day of firm capacity on the Mountain Valley Pipeline [removed: (MVP) which is expected to be placed] [added: upon its] in-service [removed: in the fourth quarter of 2019.][added: date.]

[removed: Markets] [added: Markets] and [removed: Customers][added: Customers]

No single customer accounted for more than 10% of [removed: EQT's] [added: the Company's] total operating revenues for [removed: 2018, 2017] [added: 2019, 2018] and [removed: 2016.][added: 2017.]

[removed: Natural Gas Sales:] [added: *Customers.*] The [removed: Company’s produced] [added: Company sells] natural gas [removed: is sold] [added: and NGLs] to marketers, utilities and industrial customers located in the Appalachian Basin and in [removed: the] markets that are accessible through the Company's [removed: current] transportation portfolio, [removed: which includes markets] [added: particularly where there is expected future demand growth, such as] in the Gulf Coast, Midwest and Northeast United States [removed: as well as] [added: and] Canada.

[added: *Natural Gas Sales.*] Natural gas is a commodity [removed: and therefore] [added: and, therefore,] the Company typically receives market-based pricing.

The market price for natural gas in the Appalachian Basin is [added: typically] lower relative to [removed: the price at] [added: NYMEX] Henry Hub, Louisiana (the location for pricing NYMEX natural gas futures) as a result of the [removed: increased] [added: significant increases in the] supply of natural gas in the [removed: Appalachian Basin.][added: Northeast United States in recent years.]

[removed: In order to] [added: To] protect cash flow from undue exposure to the risk of changing commodity prices, the Company hedges a portion of its forecasted natural gas [removed: production,] [added: production at, for the] most [removed: of which is hedged at] [added: part,] NYMEX natural gas prices.

[removed: The Company’s] [added: For information on the Company's] hedging strategy and [removed: information regarding] its derivative [removed: instruments is set forth under the heading “Commodity] [added: instruments, refer to "Commodity] Risk [removed: Management”] [added: Management"] in Item [removed: 7, “Management’s] [added: 7., "Management's] Discussion and Analysis of Financial Condition and Results of [removed: Operations,” in] [added: Operations,"] Item [removed: 7A, “Quantitative] [added: 7A., "Quantitative] and Qualitative Disclosures About Market [removed: Risk,” and in Notes 1] [added: Risk"] and [removed: 5] [added: Note 4] to the Consolidated Financial Statements.

[removed: NGLs Sales:] [added: *NGLs Sales.*] The Company primarily sells NGLs [removed: processed] [added: recovered] from its [removed: own] [added: natural] gas production.

[removed: In its Appalachian operations, the] [added: The] Company primarily contracts with MarkWest Energy Partners, L.P. (MarkWest) to process [added: its] natural gas [removed: in order to] [added: and] extract [added: from] the [added: produced natural gas] heavier hydrocarbon [removed: stream] [added: streams] (consisting predominately of ethane, propane, [removed: iso-butane,] [added: isobutane,] normal butane and natural [removed: gasoline) primarily from the Company’s produced gas.][added: gasoline).]

[removed: The] [added: In addition, the] Company [removed: also] has contractual arrangements with Williams Ohio Valley Midstream LLC to process [added: its] natural gas and market a portion of its [removed: NGLs on behalf of the Company in its Appalachian operations.][added: NGLs.]

[added: *Average Sales Price.*] The following table presents the [added: Company's] average sales price [removed: on a] per [removed: Mcfe basis to EQT for sales] [added: unit] of [removed: produced] natural gas, NGLs and oil, with and without [added: the effects of] cash settled [removed: derivatives.][added: derivatives as applicable.]

| | [removed: | For the Years] [added: Years] Ended December [removed: 31, | | |] [added: 31,] | | | | | | | |

| | [removed: | 2018 | | |] [added: 2019] | [removed: 2017] | | [added: 2018] | | [removed: 2016] | [added: 2017] | |

| Average sales [removed: price per Mcfe sold (excluding] [added: price, excluding] cash settled [removed: derivatives) |] [added: derivatives] | $ | [removed: 3.15] [added: 2.51] | | | $ | [removed: 2.98] [added: 3.15] | | | $ | [removed: 1.99] [added: 2.98] | |

| Average sales [removed: price per Mcfe sold (including] [added: price, including] cash settled [removed: derivatives) |] [added: derivatives] | [removed: $] [added: 2.69] | [removed: 3.01] | | | [removed: $] [added: 3.01] | [removed: 3.04] | | | [removed: $] [added: 3.04] | [removed: 2.47] | |

[removed: In addition, price] [added: For additional] information [removed: for all products is included] [added: on pricing, see "Average Realized Price Reconciliation"] in Item [removed: 7, “Management’s] [added: 7., "Management's] Discussion and Analysis of Financial Condition and Results of [removed: Operations,” under the caption “Average Realized Price Reconciliation,” and incorporated herein by reference.][added: Operations."]

[removed: Natural] [added: *Natural] Gas [removed: Marketing:] [added: Marketing.*] EQT Energy, [removed: LLC (EQT Energy),] [added: LLC,] the Company's [removed: indirect wholly owned] [added: indirect, wholly-owned] marketing subsidiary, provides marketing services and contractual pipeline capacity management [added: services] primarily for the benefit of the Company.

EQT [removed: Energy] [added: Energy, LLC] also engages in risk management and hedging activities on behalf of the [removed: Company, the objective of which is] [added: Company] to limit the [removed: Company’s] [added: Company's] exposure to shifts in market prices.

[removed: Competition][added: Competition]

Other natural gas producers compete with the Company in the acquisition of properties, the search [removed: for] [added: for,] and development [removed: of] [added: of,] reserves, the production and sale of natural gas and NGLs and the securing of services, labor, equipment and transportation required to conduct operations.

Based on average daily sales volumes, EQT is the largest producer of natural gas in the United States.

As of December 31, 2019, EQT had 17.5 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 1.3 million gross acres, including approximately 1.1 million gross acres in the Marcellus play.

The Company is dedicated to responsibly developing its world-class asset base in the core of the Appalachian Basin.

The Company believes its asset scale and contiguity of its acreage position differentiates it from its Appalachian Basin peers and that its evolution into a modern, digitally-enabled exploration and production business will continue to enhance its strategic advantage.

The Company's unique asset base supports a multi-year inventory of combo-development projects in its core acreage position, which consist of developing multiple wells and pads simultaneously.

Following a change in leadership in July 2019, the Company implemented an operational strategy designed to leverage this differentiation to become the lowest cost operator in the Appalachian Basin, primarily by focusing on combo-development projects to maximize operational efficiencies.

The Company believes that combo-development projects are key to delivering sustainably low well costs and higher returns on invested capital.

Beyond cost benefits, combo-development projects maximize reservoir recoveries, mitigate future curtailments and maximize the capital efficiency of the Company's midstream service providers.

The Company expects to drill approximately 13 to 25 wells per combo-development project, with average lateral lengths from 12,000 feet to 14,000 feet.

The Company's target Pennsylvania Marcellus well cost is $730 per foot, which the Company expects to achieve in the second half of 2020.

In an effort to further the Company's operational strategy and improve the Company's leverage ratio, in the fourth quarter of 2019, the Company announced a plan to reduce its absolute debt using free cash flow and targeted proceeds from the monetization of select, non-strategic exploration and production assets, core mineral assets and the Company's remaining retained equity interest in Equitrans Midstream (the Deleveraging Plan).

2019 Highlights

| • | Substantially reconstituted the Company's Board of Directors and senior leadership following the Company's July 2019 annual meeting of shareholders |

| • | Successfully implemented the 100-Day Transformation Plan, a management-led initiative designed to effect operational, organizational, cultural and other changes to the Company's business that will facilitate long-term planning and prioritize combo-development projects, which are expected to (i) lower well costs, selling, general and administrative costs, land and lease acquisitions capital expenditures and other production infrastructure capital expenditures; (ii) increase drilling efficiencies (measured in horizontal feet drilled per hour); and (iii) increase free cash flow generation |

| • | Reduced 2019 capital expenditures by $966 million, or 35.3%, compared to 2018 |

| • | Achieved 2019 sales volumes of 1,508 Bcfe and average daily sales volumes of 4,131 MMcfe per day, a year-over-year increase of 1.4%, or 4.2% excluding sales volumes related to the 2018 Divestitures (defined herein) |

In 2020, the Company expects to spend $1.15 billion to $1.25 billion in total capital expenditures.

Planned capital expenditures will be funded by cash generated from operations and allocated as follows: approximately $0.9 billion to reserve development, approximately $150 million to land and lease acquisitions, approximately $85 million to other production infrastructure and approximately $55 million to capitalized overhead.

Reserve development capital expenditures will be spent across the Company's three primary operating areas, with approximately 70% spent in Pennsylvania Marcellus, approximately 22% spent in Ohio Utica and approximately 8% spent in West Virginia Marcellus.

The Company's 2020 capital expenditure program is expected to deliver sales volumes of 1,450 Bcfe to 1,500 Bcfe, which is in line with 2019 sales volumes, using approximately $500 million less capital funding than the 2019 capital expenditure program.

points and, thus, cannot predict the ultimate impact of prices on its operations.

Reserves

The following tables summarize the Company's proved natural gas, NGLs and crude oil reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by product and play.

Substantially all of the Company's reserves reside in continuous accumulations.

| | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | |

| | December 31, 2019 | | | | | | | |

| | Natural Gas | | | NGLs and Crude Oil | | | Total | |

| | (Bcf) | | | (MMbbl) | | | (Bcfe) | |

| Proved developed reserves | 11,811 | | | 105 | | | 12,444 | |

| Proved undeveloped reserves | 4,866 | | | 27 | | | 5,025 | |

| Total proved reserves | 16,677 | | | 132 | | | 17,469 | |

| | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | | | | | | | |

| | December 31, 2019 | | | | | | | | | | | | | |

| | (Bcfe) | | | | | | | | | | | | | |

| Proved developed reserves | 10,513 | | | 880 | | | 947 | | | 104 | | | 12,444 | |

| Proved undeveloped reserves | 4,584 | | | — | | | 441 | | | — | | | 5,025 | |

EQT is the largest producer of natural gas in the United States, based on average daily sales volumes, with 21.8 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 1.4 million gross acres, including approximately 1.1 million gross acres in the Marcellus play, many of which have associated deep Utica or Upper Devonian drilling rights, and approximately 0.1 million gross acres in the Ohio Utica play as of December 31, 2018.

The Company seeks to be the premier producer of environmentally friendly, reliable, low-cost natural gas, while maximizing the long-term value of its assets through operational efficiency and a culture of sustainability.

To accomplish these objectives and deliver value to its stakeholders, the Company's strategic priorities include focusing on reducing costs, improving operational and capital efficiency, consistently delivering volumes and prioritizing the return of capital to shareholders while strengthening the Company's balance sheet.

The Company intends to achieve mid-single digit year-over-year production growth combined with substantial and sustainable free cash flow by executing on its plan, with a stable operating cadence which is expected to result in higher capital efficiency.

The Company believes the long-term outlook for its business is favorable due to the Company’s substantial resource base, financial strength, and its commitment to capital discipline and operational efficiencies.

The Company believes the combination of these factors provide it with an opportunity to exploit and develop its acreage and reserves and maximize efficiency through economies of scale.

The Company has a significant contiguous acreage position in the core of the Marcellus and Utica shales which the Company believes will allow it to realize operational efficiencies and improve overall returns.

The Company believes that it is a technology leader in horizontal drilling and completion activities in the Appalachian Basin and continues to improve its operations through the use of new technologies and a company-wide focus on efficiency.

Development of multi-well pads in conjunction with longer laterals, optimized well spacing, and completion techniques allow the Company to maximize development efficiencies while reducing the overall environmental surface footprint of its drilling operations.

Key Events in 2018

| • | The Company achieved annual sales volumes of 1,488 Bcfe and average daily sales volumes of 4,076 MMcfe/d. Adjusted for the impact of the 2018 Divestitures, as explained below, total annual sales volumes were 1,447 Bcfe or 3,964 MMcfe/d. |

| • | On June 19, 2018, the Company sold its non-core Permian Basin assets located in Texas for net proceeds of $56.9 million (the Permian Divestiture). The assets sold in the Permian Divestiture included approximately 970 productive wells with net production of approximately 20 MMcfe per day at the time of sale, approximately 350 miles of low-pressure gathering lines and 26 compressors. |

| • | On July 18, 2018, the Company sold approximately 2.5 million non-core, net acres in the Huron play for net proceeds of $523.6 million (the Huron Divestiture). The assets sold in the Huron Divestiture included approximately 12,000 productive wells with current net production of approximately 200 MMcfe per day, approximately 6,400 miles of low-pressure gathering lines and 59 compressor stations. The Company retained the deep drilling rights across the divested acreage. |

| • | On November 12, 2018, the Company completed the Separation and Distribution of Equitrans Midstream Corporation (Equitrans Midstream), as explained below under “Separation and Distribution.” |

In 2019, the Company expects to spend approximately $1.5 billion for reserve development, approximately $0.2 billion for land and lease acquisitions, approximately $0.1 billion for capitalized overhead and approximately $0.1 billion for other production infrastructure.

Estimated sales volumes are expected to be 1,470 to 1,510 Bcfe for 2019.

The 2019 drilling program is expected to support a 5% increase in sales volume in 2020 over

the Company's 2019 expected sales volumes.

The 2019 capital investment plan is expected to be funded by cash generated from operations.

Separation and Distribution

On November 12, 2018, EQT completed the previously announced separation of its midstream business, which was composed of the separately operated natural gas gathering, transmission and storage, and water services businesses of EQT, from its upstream business, which is composed of the natural gas, oil and natural gas liquids development, production and sales and commercial operations of the Company (the Separation).

The Separation was effected by the transfer of the midstream business from EQT to Equitrans Midstream and the distribution of 80.1% of the outstanding shares of Equitrans Midstream common stock to EQT's shareholders (the Distribution).

EQT's shareholders of record as of the close of business on November 1, 2018 (the Record Date) received 0.80 shares of Equitrans Midstream common stock for every one share of EQT common stock held as of the close of business on the Record Date.

EQT retained 19.9% of the outstanding shares of Equitrans Midstream common stock.

As a result of the Distribution, Equitrans Midstream is now an independent public company listed under the ticker symbol “ETRN” on the New York Stock Exchange (NYSE).

The Company’s common stock is listed under the symbol “EQT” on the NYSE.

The Company plans to dispose of all of its retained Equitrans Midstream common stock, which may include dispositions through one or more subsequent exchanges for debt or a sale of its shares for cash.

The Company expects to use the proceeds from any dispositions of its retained Equitrans Midstream common stock to reduce the Company's debt.

The Company’s proved reserves increased 2% in 2018, or 11% when adjusted for the impact of the Huron Divestiture and Permian Divestiture (collectively, the 2018 Divestitures).

The Company's Marcellus assets constituted approximately 19.1 Tcfe of the Company's total proved reserves as of December 31, 2018 and increased 13% as compared to December 31, 2017.

The Company’s Marcellus assets constituted approximately 87% of the Company's total proved reserves by volume as of December 31, 2018.

As of December 31, 2018, the Company’s proved reserves were as follows:

| | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | | | | | | | | |

| Proved Developed | | 9,625 | | | 915 | | | 898 | | | 112 | | | 11,550 | |

| Proved Undeveloped | | 9,464 | | | 92 | | | 711 | | | — | | | 10,267 | |

| Total Proved Reserves | | 19,089 | | | 1,007 | | | 1,609 | | | 112 | | | 21,817 | |

The Company’s natural gas wells generally have long reserve lives.

Assuming that future annual production from these reserves is consistent with 2019 production guidance, the remaining reserve life of the Company’s total proved reserves, as calculated by dividing total proved reserves by 2019 production volumes guidance, is approximately 15 years.

The Company has established reserves it believes to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial [removed: condition,] [added: position,] results of operations or liquidity of the Company.

[removed: Environmental Proceedings][added: Environmental Proceedings]

The payment of the civil penalty did not have a material impact on the financial [removed: condition,] [added: position,] results of operations or liquidity of the Company.

The Company cooperated [added: fully] with the [removed: PADEP] [added: WVDEP] to take appropriate actions to [removed: stop] [added: address] the [added: secondary containment issues and remediation of the] release.

[added: *Erosion and Sedimentation Release, Greene County, Pennsylvania.*] Between [removed: November 2017] [added: September 2018] and [removed: March] [added: December] 2018, the Company received multiple [removed: NOVs] [added: Notices of Violation (NOVs)] from the PADEP relating to [removed: four of] the [removed: Company’s well pads] [added: Don Flamenco Pad] in [removed: Allegheny] [added: Greene] County, Pennsylvania.

The NOVs alleged violations of the Oil and Gas [removed: Act,] [added: Act] and [added: The] Clean Streams Law in connection with [removed: the effects][added: erosion and sedimentation controls and an unstabilized fill slope.]

The Company cooperated fully with the PADEP to take appropriate actions to address the erosion and sedimentation control [removed: issues.][added: issues and the unstabilized fill slope.]

While the Company expects the [removed: PADEP’s] [added: WVDEP's] claims to result in penalties that exceed $100,000, the Company expects that the resolution of this matter will not have a material impact on the financial [removed: condition,] [added: position,] results of operations or liquidity of the Company.

[removed: Other] [added: Other] Legal [removed: Proceedings][added: Proceedings]

The [removed: suit] [added: complaint] alleged that EQT Production Company and a number of related companies, including the Company, EQT [removed: Energy,] [added: Gathering,] LLC, EQT [removed: Investments Holdings,] [added: Energy,] LLC, [removed: EQM (the Company’s former midstream affiliate)] and [removed: Equitrans Gathering Holdings,] [added: EQM Midstream Services,] LLC (formerly known as EQT [removed: Gathering Holdings,] [added: Midstream Services,] LLC, [removed: and a former subsidiary of] the [removed: Company), failed to pay royalties on the fair value] [added: general partner] of the [added: Company's former midstream affiliate), underpaid on royalties for] gas produced [removed: from] [added: under] the leases and took improper post-production deductions from the royalties paid.

The plaintiffs sought more than $100 million [removed: (according to expert reports)] in compensatory [removed: damages,] [added: damages for the trespass claim under the Stout Lease, and approximately $20 million for insufficient royalties under both the Stout Lease and the Cities Services Lease, in addition to] punitive [removed: damages,] [added: damages] and other relief.

The Company entered into a Consent Order and Agreement with the PADEP on January 10, 2020 and under the terms of the agreement, the Company paid a civil penalty of $151,415 in January 2020 to resolve this matter.

*Produced Water Release, Marshall County, West Virginia.* On November 12, 2019, the Company received an NOV from the West Virginia Department of Environmental Protection (the WVDEP) relating to the Goshorn Pad in Marshall County, West Virginia.

The NOV alleged violations of Water Pollution Control Rules in connection with a release of produced water from secondary containment at a Goshorn Pad tank battery.

*Mary Farr Secrist, et al.

EQT Production Company, et al., Circuit Court of Doddridge County, West Virginia.* On May 2, 2014, royalty owners whose predecessors had entered into a 960-acre lease (the Stout Lease) and several additional leases comprising 6,356-acres (the Cities Services Lease) with EQT Production Company's predecessor, each covering acreage in Doddridge County, West Virginia, filed a complaint in the Circuit Court of Doddridge County, West Virginia.

With respect to the Stout Lease, the plaintiffs also asserted that the Company committed a trespass by drilling on the leased property, claiming that the Company had no right under the lease to drill in the Marcellus shale formation.

The plaintiffs also asserted claims for fraud, slander of title, punitive damages, pre-judgment interest and attorneys' fees.

On June 27, 2018, the Court held that EQT Production Company and its marketing affiliate EQT Energy, LLC are alter egos of one another and that royalties paid under the leases should have been based on the price of gas produced under the leases when sold to unaffiliated third parties, and not on the price when the gas was sold from EQT Production Company to EQT Energy, LLC.

Further, on January 14, 2019, the Court entered an Order granting the plaintiffs' motion for summary judgment and declaring that the Company did not have the right to drill in the Marcellus shale formation under the Stout Lease.

The Court also ruled that seven of the Company's wells that have been producing gas under the Stout Lease are trespassing, and that a jury will determine whether the trespass was willful or innocent.

On February 27, 2019, the Company filed a motion seeking permission to immediately appeal the trespass Order to the West Virginia Supreme Court; however, the motion was denied on March 25, 2019, and the Court continued the trial to September 2019.

On May 28, 2019, the Court entered an Order excluding certain of the Company's costs that could have otherwise offset any damages for innocent trespass under the Stout Lease.

On August 8, 2019,

the Company reached a settlement with the plaintiffs to resolve all claims under the Stout Lease and the Cities Services Lease for $54 million plus lease modifications to address the trespass issue and the calculation of future royalty payments under the leases.

The Company paid $51 million of the settlement in October 2019 and the remaining $3 million of the settlement in January 2020.

Amendments to modify the terms of the Stout Lease are in process and, when finalized, an Order to dismiss the case will be filed with the Court to formally close this matter.

Phoenix S Impoundment, Tioga County, Pennsylvania

In June and August 2012, the Company received three Notices of Violation (NOVs) from the PADEP.

The NOVs alleged violations of the Pennsylvania Oil and Gas Act and Clean Streams Law in connection with the unintentional release in May 2012, by a Company vendor, of water from an impaired water pit at a Company well location in Tioga County, Pennsylvania.

Since confirming a release, the Company has cooperated with the PADEP in remediating the affected areas.

During the second quarter of 2014, the Company received a proposed consent assessment of civil penalty from the PADEP that proposed a civil penalty related to the NOVs.

On September 19, 2014, the Company filed a declaratory judgment action in the Commonwealth Court of Pennsylvania against the PADEP seeking a court ruling on the PADEP’s legal interpretation of the penalty provisions of the Clean Streams Law, which interpretation the Company believed was legally flawed and unsupportable.

On October 7, 2014, based on its interpretation of the penalty provisions, the PADEP filed a complaint against the Company before the Pennsylvania Environmental Hearing Board (the EHB) seeking $4.53 million in civil penalties.

In January 2017, the Commonwealth Court ruled in favor of the Company, finding the PADEP’s interpretation of the penalty provisions of the Clean Streams Law erroneous.

The PADEP appealed that decision to the Pennsylvania Supreme Court, and the parties made oral arguments in front of the Pennsylvania Supreme Court on November 28, 2017.

Following a July 2016 hearing before the EHB, in May 2017, the EHB ruled that the Company should pay $1.1 million in civil penalties.

In June 2017, both the Company and the PADEP appealed the EHB’s decision to the Commonwealth Court.

In September 2018, the Commonwealth Court upheld the $1.1 million civil penalty, which the Company paid in November 2018.

Fresh Water Pipeline Bore Release, Allegheny County, Pennsylvania

On February 24, 2017, the Company received an NOV from the PADEP.

The NOV alleged violations of the Pennsylvania Oil and Gas Act and Clean Streams Law related to an unintentional release, by a Company vendor, of mine water into the Monongahela River in January 2017 from a mine void that was pierced while boring under a road for the installation of a fresh water pipeline in Allegheny County, Pennsylvania.

On February 15, 2017, the Company entered into a civil penalty settlement related to the release with the Pennsylvania Fish and Boat Commission for $4,555 for alleged violations of the Pennsylvania Fish and Boat Code.

In November 2018, the Company and the PADEP entered into a settlement agreement related to the release.

Under the terms of the agreement, the Company paid a civil penalty of $294,000 and provided $100,000 in trust for future maintenance of a mine water drain.

The payments did not have a material impact on the financial condition, results of operations or liquidity of the Company.

Wilson Creek Water Withdrawals, Tioga County, Pennsylvania

On June 7, 2018, the Company received an NOV from the Susquehanna River Basin Commission (the SRBC).

The NOV alleged violations of the Company’s Water Management Plan and its Wilson Creek Docket related to the withdrawal of water from Wilson Creek between March 14, 2018 and April 3, 2018, when the stream flow was below the required flow protection threshold.

The Company cooperated fully with the SRBC to address the matter.

On December 18, 2018, the Company and the SRBC agreed to settle this matter and the Company paid a civil penalty of $120,000.

The payment of the civil penalty did not have a material impact on the financial condition, results of operations or liquidity of the Company.

Erosion and Sedimentation Releases, Allegheny County, Pennsylvania

During this time period, Pennsylvania experienced unprecedented amounts of rainfall.

of the rainfall on erosion and sedimentation controls at the Prentice, Fetchen, Oliver East, and Oliver West well pads.

The Company and the PADEP are currently negotiating a civil penalty settlement.

Phoenix S Pad Well Control Incident, Tioga County, Pennsylvania

On December 1, 2017 and May 1, 2018, the Company received NOVs from the PADEP relating to a well control incident that occurred at a Phoenix S well on November 12, 2017.

The well was brought back under control, but in the interim natural gas was vented to the atmosphere and flowback water was released to the ground water and a stream.

The Company fully cooperated with the PADEP and took appropriate actions to address the environmental impacts from the incident.

On January 22, 2019, the Company and the PADEP agreed to settle this matter and the Company agreed to pay a civil penalty of $138,000 to resolve the matter.

The payment of the civil penalty did not have a material impact on the financial condition, results of operations or liquidity of the Company.

Kay Company, LLC, et al.

EQT Production Company, et al., United States District Court for the Northern District of West Virginia

On January 16, 2013, several royalty owners who had entered into leases with EQT Production Company, a subsidiary of the Company, filed a gas royalty class action lawsuit in the Circuit Court of Doddridge County, West Virginia.

On May 31, 2013, the defendants removed the lawsuit to federal court.

On September 6, 2017, the district court granted the plaintiffs’ motion to certify the class and granted the plaintiffs’ motion for summary judgment, finding that EQT Production Company and its marketing affiliate EQT Energy, LLC are alter egos of one another.

[removed: UNITED STATES][added: UNITED STATES]

[removed: SECURITIES] [added: SECURITIES] AND EXCHANGE [removed: COMMISSION][added: COMMISSION]

[removed: Washington,] [added: Washington,] D.C. [removed: 20549][added: 20549]

[removed: FORM 10-K][added: FORM 10-K]

| [removed: \[X\]] [added: ☒] | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | [removed: | | |]

[removed: FOR] [added: FOR] THE FISCAL YEAR [removed: ENDED DECEMBER] [added: ENDED DECEMBER] 31, [removed: 2018][added: 2019]

| [removed: \[ \]] [added: ☐] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | [removed: | | |]

[removed: EQT CORPORATION][added: EQT CORPORATION]

| [removed: PENNSYLVANIA] (State or other jurisdiction of incorporation or organization) | | [removed: 25-0464690] (IRS Employer Identification No.) |

| [removed: 625 Liberty Avenue, Suite 1700 Pittsburgh, Pennsylvania] (Address of principal executive offices) | | [removed: 15222] [added: |] (Zip Code) |

| [removed: Title] [added: Title] of each [removed: class] [added: class] | | [removed: Name] [added: Trading symbol(s) | | Name] of each exchange on which [removed: registered] [added: registered] |

| Common Stock, no par value | | [added: EQT | |] New York Stock Exchange |

Securities registered pursuant to Section 12(g) of the Act: [removed: None][added: None]

Yes [removed: X] [added: ☒] No [removed: ___][added: ☐]

Yes [removed: ___] [added: ☐] No [removed: X][added: ☒]

Yes [removed: X] [added: ☒] No [removed: ___][added: ☐]

Yes [removed: X] [added: ☒] No [removed: ___][added: ☐]

| Large accelerated filer [removed: X] | [added: ☒ |] Accelerated filer [removed: ___] | [added: ☐ |]

| Non-accelerated filer [removed: ___ (Do not check if a smaller reporting company)] | [added: ☐ |] Smaller reporting company [removed: ___] | [added: ☐ |]

| | [added: |] Emerging growth company [removed: ___] | [added: ☐ |]

Yes [removed: ___] [added: ☐] No [removed: X][added: ☒]

The aggregate market value of [removed: voting] [added: common] stock held by non-affiliates of the registrant as of June 30, [removed: 2018: $14.5] [added: 2019: $4.0] billion

The number of shares (in thousands) of common stock outstanding as of [removed: January 31, 2019: 254,762][added: February 18, 2020: 255,454]

[removed: DOCUMENTS] [added: DOCUMENTS] INCORPORATED BY [removed: REFERENCE][added: REFERENCE]

The [removed: Company’s] [added: Company's] definitive proxy statement relating to the [removed: 2019] [added: 2020] annual meeting of shareholders will be filed with the Securities and Exchange Commission within 120 days after the close of the [removed: Company’s] [added: Company's] fiscal year ended December 31, [removed: 2018] [added: 2019] and is incorporated by reference in Part III to the extent described therein.

[removed: TABLE OF CONTENTS][added: Table of Contents]

[removed: | | Glossary] [added: Glossary] of Commonly Used Terms, Abbreviations and [removed: Measurements | [3](#s574BE37DFA285CD7B8B75D69C6275ABC) |][added: Measurements]

[removed: | | Cautionary Statements | [6](#s3B16A0BF70CB5894A634539E8923559D) |][added: CAUTIONARY STATEMENTS]

| [removed: PART I] [added: PART I] | | |

| Item [removed: 1] [added: 1.] | Business | [removed: [7](#sC7C17749F35D55C8BAEFF68327362465)] [added: [7](#s05D45CF3B2055042AE5583BE4ED1391B)] |

| Item [removed: 1A] [added: 1A.] | Risk Factors | [removed: [18](#s415CD40D2FE25A7AABDE1D13EEC31E4B)] [added: [20](#s7178977F6D1450BAAC63A5B5B66AC51A)] |

| Item [removed: 1B] [added: 1B.] | Unresolved Staff Comments | [removed: [32](#sA4F69CBC657A5F7C9A2A593D30AA4DC4)] [added: [36](#sA91A80DB56745D4BA8A25B58ABBD20CA)] |

| Item [removed: 2] [added: 2.] | Properties | [removed: [33](#s93230617ABC85B6096E5F20FCAE823A8)] [added: [37](#s6F7A11B953865965B209F69108F2A838)] |

| Item [removed: 3] [added: 3.] | Legal Proceedings | [removed: [38](#s071C50B280B859F8A7A0AE6496A957C0)] [added: [37](#s243157AD28F3514EA2D023BE12FA6A3E)] |

| Item [removed: 4] [added: 4.] | Mine Safety Disclosures | [removed: [39](#s07A362EBC7715049B3687E14F5EAD67B)] [added: [38](#sFB43E1037C3F5BD1B76AE09C6A873A73)] |

| | Executive Officers of the Registrant | [removed: [40](#s2ACF4A1E17D15A9B90859FAB3FBF79D4)] [added: [39](#s97DD8103892550DA897E71817E70BE7F)] |

| [removed: PART II] [added: PART II] | | |

| Item [removed: 5] [added: 5.] | Market for [removed: Registrant’s] [added: Registrant's] Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | [removed: [41](#sEB9F4C2AA11D5CEDB4BE6AC3C088A862)] [added: [40](#sF848B35C295E509BA378A3AA3BB6C7C8)] |

| Item [removed: 6] [added: 6.] | Selected Financial Data | [removed: [43](#s24D76436418652799A6F17221011D0CE)] [added: [42](#s0B379B4666655C0F8EDE72D27A6DCA76)] |

| Item [removed: 7] [added: 7.] | [removed: Management’s] [added: Management's] Discussion and Analysis of Financial Condition and Results of Operations | [removed: [44](#s51488DFF5A3A54369017EA9D9827FC23)] [added: [43](#sA2BB0BB64E8458C88F6C5744F63415E2)] |

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| Pennsylvania | | 25-0464690 |

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| 625 Liberty Avenue, Suite 1700 | | | |

| Pittsburgh, | Pennsylvania | | 15222 |

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| Item 9B. | Other Information | [107](#s10329B5F1F525D61AE126712753DE601) |

| Item 11. | Executive Compensation | [108](#s0990DD39E95D5791928AFBE6F1088649) |

| Item 16. | Form 10-K Summary | [119](#sfa03a3c1e31542f79ef07052685db0a8) |

| Signatures | | [120](#s28BC2536E542503BA6E2C9038E825691) |

stratigraphic test well – a hole drilled for the sole purpose of gaining structural or stratigraphic information to aid in exploring for oil and gas.

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| MMbbl \= million barrels |

10-K 1 eqt1231201810k.htm 10-K

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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

\[ \]

(Check one):

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| Item 9B | Other Information | [114](#sceb8b44519b940d08590e511dc256640) |

| Item 11 | Executive Compensation | [115](#s470A2200D49E540CBDB7A64E1A8C1307) |

| | Signatures | [125](#s824E86B413F3541D90752B63B2E9966E) |

multiple completion well – a well equipped to produce oil and/or gas separately from more than one reservoir.

Such wells contain multiple strings of tubing or other equipment that permit production from the various completions to be measured and accounted for separately.

multi-well pad – a well pad designed to enable the development of multiple horizontal wells from a single compact surface location.

Glossary of Commonly Used Terms, Abbreviations and Measurements

Glossary of Commonly Used Terms, Abbreviations and Measurements

ASC – Accounting Standards Codification

FASB – Financial Accounting Standards Board

IPO – initial public offering

Bcfe = billion cubic feet of natural gas

Mcfe = thousand cubic feet of natural gas

MMcfe = million cubic feet of natural gas

equivalents, with one barrel of NGLs and crude oil

being equivalent to 6,000 cubic feet of natural gas

Tcfe = trillion cubic feet of natural gas

equivalents, with one barrel of NGLs and crude oil

being equivalent to 6,000 cubic feet of natural gas

The Company also owns or leases office space in Pennsylvania, West [removed: Virginia] [added: Virginia, Ohio] and [removed: Ohio.][added: Texas.]

See Item 1., "Business" for a description of the Company's properties.

Principal facilities are owned or, in the case of certain office locations, warehouse buildings and equipment, leased, by the Company and its subsidiaries.

The majority of the Company’s properties are located on or under (i) private properties owned in fee, held by lease or occupied under perpetual easements or other rights acquired for the most part without warranty of underlying land titles or (ii) public highways under franchises or permits from various governmental authorities.

The Company’s facilities are generally well maintained and, where appropriate, are replaced or expanded to meet operating requirements.

The Company’s properties are located primarily in Pennsylvania, West Virginia and Ohio.

The Company has approximately 1.4 million gross acres (approximately 74% of which are considered undeveloped), which encompass substantially all of the Company’s acreage of proved developed and undeveloped natural gas and oil producing properties.

Of these gross acres, approximately 1.1 million are in the Marcellus play, much of which has associated deep Utica or Upper Devonian drilling rights, and approximately 0.1 million are in the Ohio Utica play.

Although most of the Company's wells are drilled to relatively shallow depths (5,000 to 8,500 feet below the surface), the Company retains what are normally considered “deep rights” on the majority of its acreage.

As of December 31, 2018, the Company estimated its total proved reserves to be 21.8 Tcfe, consisting of proved developed producing reserves of 11.3 Tcfe, proved developed non-producing reserves of 0.2 Tcfe and proved undeveloped reserves of 10.3 Tcfe.

Substantially all of the Company’s reserves reside in continuous accumulations.

The Company’s estimate of proved natural gas, NGLs and oil reserves is prepared by Company engineers.

The engineer primarily responsible for preparing the reserve report and the technical aspects of the reserves audit received a bachelor’s degree

in Chemical Engineering from the Pennsylvania State University and has 21 years of experience in the oil and gas industry.

To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves.

Additionally, division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems, and the reserve reconciliation between prior year reserves and current year reserves is reviewed by senior management.

The Company’s estimate of proved natural gas, NGLs and oil reserves is audited by the independent consulting firm of Ryder Scott Company, L.P. (Ryder Scott), which is hired by the Company’s management.

Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.

In the course of its audit, Ryder Scott reviewed 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company’s interests as of December 31, 2018.

Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties.

This audit covered 81% of the Company’s proved developed reserves.

Ryder Scott’s audit of the remaining approximately 19% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 115 wells per case for non-operated wells.

For undeveloped locations, the Company determined, and Ryder Scott reviewed and approved, the areas within the Company’s acreage considered to be proven.

Reserves were assigned and projected by the Company’s reserves engineers for locations within these proven areas and approved by Ryder Scott based on analogous type curves and offset production information.

Ryder Scott’s audit report has been filed herewith as Exhibit 99.

No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Company’s estimated total reserves.

Additional information relating to the Company’s estimates of natural gas, NGLs and crude oil reserves and future net cash flows is provided in Note 18 (unaudited) to the Consolidated Financial Statements.

In 2018, the Company commenced drilling operations (spud or drilled) on 117 gross horizontal Marcellus wells, 5 gross horizontal Upper Devonian wells and 31 gross horizontal Ohio Utica wells.

Sales volumes in 2018 from the Marcellus play, including the Upper Devonian play, was 1,230 Bcfe.

Over the past five years, the Company has experienced a 97% developmental drilling success rate.

Natural gas, NGLs and crude oil pricing:

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| | | | | | | | | | | | | |

| | | For the Years Ended December 31, | | | | | | | | | | |

| | | 2018 | | | | 2017 | | | | 2016 | | |

| Natural Gas: | | | | | | | | | | | | |

| Average sales price (excluding cash settled derivatives) ($/Mcf) | | $ | 3.04 | | | $ | 2.82 | | | $ | 1.88 | |

| Average sales price (including cash settled derivatives) ($/Mcf) | | $ | 2.89 | | | $ | 2.89 | | | $ | 2.41 | |

| NGLs (excluding ethane): | | | | | | | | | | | | |

| Average sales price (excluding cash settled derivatives) ($/Bbl) | | $ | 37.63 | | | $ | 31.59 | | | $ | 19.43 | |

| Average sales price (including cash settled derivatives) ($/Bbl) | | $ | 36.56 | | | $ | 30.90 | | | $ | 19.43 | |

| [removed: Name] [added: Name] and [removed: Age] [added: Age] | | [removed: Current] [added: Current] Title (Year Initially Elected an Executive [removed: Officer)] [added: Officer)] | | [removed: Business Experience] [added: Business Experience] |

All executive officers [added: other than Mr. Rice] have executed [added: non-compete] agreements with the Company and serve at the pleasure of the [removed: Company’s] [added: Company's] Board of Directors.

[removed: PART II][added: PART II]

Information about our Executive Officers (as of February 27, 2020)

| Tony Duran (41) | | Chief Information Officer (2019) | | Mr. Duran was appointed as the Chief Information Officer of the Company in July 2019. Prior to joining the Company, Mr. Duran ran PH6 Labs, a technology incubator he founded, from December 2017 to July 2019. Prior to that, he served as the Chief Information Officer of Rice Energy Inc. (independent natural gas and oil company acquired by the Company in November 2017) from January 2016 to November 2017; and as the Interim Chief Information Officer of Express Energy Services (oilfield services company for well construction and well testing services) from September 2015 to December 2015. Additionally, Mr. Duran held various positions at National Oilwell Varco (multinational corporation that provides equipment and components used in oil and gas drilling and production operations, oilfield services, and supply chain integration services to the upstream oil and gas industry) from May 2002 to August 2015, where he last held the role of Assistant Chief Information Officer. |

| Lesley Evancho (42) | | Chief Human Resources Officer (2019) | | Ms. Evancho was appointed as the Chief Human Resources Officer of the Company in July 2019. Prior to joining the Company, Ms. Evancho served as Vice President, Global Talent Management at Westinghouse Electric Company, LLC (nuclear power, fuel and services company) from April 2019 to July 2019; Senior Director, Human Resources at Thermo Fisher Scientific, Inc. (biotechnology product development company) from August 2018 to March 2019; Vice President, Human Resources at Edward Marc Brands (food services company) from March 2018 to August 2018; and Vice President, Human Resources at Rice Energy Inc. from April 2017 to November 2017. Additionally, Ms. Evancho served as Global Director, Talent Management at MSA Safety, Inc. (manufacturer of industrial safety equipment) from November 2011 to April 2017. |

| Todd M. James (37) | | Chief Accounting Officer (2019) | | Mr. James was appointed as the Chief Accounting Officer of the Company in November 2019. Previously, Mr. James served as the Corporate Controller and Chief Accounting Officer of L.B. Foster Company (manufacturer and distributor of products and services for transportation and energy infrastructure) from April 2018 to October 2019. Prior to that he served as the Senior Director, Technical Accounting and Financial Reporting at Rice Energy Inc. from December 2014 through its acquisition by the Company in November 2017 and until February 2018. Prior to joining Rice Energy, Mr. James was a Senior Manager, Assurance at PricewaterhouseCoopers LLP (public accounting firm), where he worked from August 2005 to November 2014. |

| William E. Jordan (39) | | Executive Vice President and General Counsel (2019) | | Mr. Jordan was appointed as the Executive Vice President and General Counsel of the Company in July 2019. Mr. Jordan served as an advisor to the Rice Investment Group (multi-strategy investment fund investing in all verticals of the oil and gas sectors) from May 2018 until July 2019. Prior to that, he served as the Senior Vice President, General Counsel and Corporate Secretary of Rice Energy Inc. and Senior Vice President, General Counsel and Corporate Secretary of Rice Midstream Partners LP (former midstream services affiliate of Rice Energy Inc.), in each case from January 2014 until their acquisition by the Company in November 2017. From September 2005 to December 2013, Mr. Jordan was an associate at Vinson & Elkins LLP (an international law firm) representing public and private companies in capital markets offerings and mergers and acquisitions, primarily in the oil and natural gas industry. |

| David M. Khani (56) | | Chief Financial Officer (2020) | | Mr. Khani was appointed as the Chief Financial Officer of the Company in January 2020. Prior to joining the Company, Mr. Khani served as the Executive Vice President and Chief Financial Officer of CONSOL Energy (energy company primarily focused on developing coal interests), from March 2013 to December 2019; and as Vice President, Finance at CONSOL Energy from September 2011 to March 2013. In addition, Mr. Khani served as Chief Financial Officer and as a member of the Board of Directors of CONE Midstream LLC (midstream services affiliate of CONSOL Energy) from September 2014 to January 2018; as a member of the Board of Directors of CNX Coal Resources (coal mining affiliate of CONSOL Energy) from July 2015 to August 2017; and as Chief Financial Officer and as a member of the Board of Directors of CONSOL Coal Resources (coal mining affiliate of CONSOL Energy) from August 2017 to December 2019. |

| Toby Z. Rice (38) | | President and Chief Executive Officer (2019) | | Mr. Rice was appointed as President and Chief Executive Officer of the Company in July 2019, when he also was elected to the Company's Board of Directors. Mr. Rice has served as a Partner at the Rice Investment Group, a multi-strategy fund investing in all verticals of the oil and gas sector, since May 2018. From October 2014 until its acquisition by the Company in November 2017, Mr. Rice was President and Chief Operating Officer of Rice Energy Inc. and served on the Board of Directors of Rice Energy Inc. from October 2013 to November 2017. Prior to that, he served in a number of positions with Rice Energy, its affiliates and predecessor entities beginning in February 2007, including as President and Chief Executive Officer of a predecessor entity from February 2008 through September 2013. Mr. Rice is the brother of Daniel J. Rice IV, a member of the Company's Board of Directors since November 2017. |

Executive Officers of the Registrant (as of February 14, 2019)

| Erin R. Centofanti (43) | | Executive Vice President, Production (2018) | | Elected to present position October 2018. Ms. Centofanti served as Senior Vice President, Asset Development, EQT Production Company, from March 2017 to October 2018; Senior Vice President, Engineering, EQT Production Company, from November 2014 to March 2017; Vice President, Commercial Operations, EQT Energy, LLC, from February 2014 to November 2014; and Vice President, Business Development, EQT Production Company, from July 2011 to February 2014. |

| Donald M. Jenkins (46) | | Executive Vice President, Commercial Business Development, Information Technology and Safety (2017) | | Elected to present position November 2018. Mr. Jenkins served as the Company’s Chief Commercial Officer from March 2017 to November 2018; Executive Vice President, Commercial, EQT Energy, LLC, from May 2014 to February 2017; and Senior Vice President, Trading and Origination, EQT Energy, LLC, from December 2012 to May 2014. |

| Jonathan M. Lushko (43) | | General Counsel and Senior Vice President, Government Affairs (2018) | | Elected to present position October 2018. Mr. Lushko served as the Company’s Deputy General Counsel, Governance & Enterprise Risk, from May 2017 to October 2018. Mr. Lushko joined the Company in 2006 as Counsel, and later served as Senior Counsel prior to assuming the role of Deputy General Counsel, Governance & Enterprise Risk in May 2017. |

| Robert J. McNally (48) | | President and Chief Executive Officer (2016) | | Elected to present position November 2018. Mr. McNally served as Senior Vice President and Chief Financial Officer of the Company from March 2016 to November 2018, and in March 2017 he assumed additional management responsibilities for the Business Development, Facilities, Information Technology, Innovation, and Procurement functions. Mr. McNally served as a Director and Senior Vice President and Chief Financial Officer of the general partners of EQM Midstream Partners, LP and EQGP Holdings, LP (master limited partnerships formed by the Company and divested by the Company as part of the Separation, from March 2016 to October 2018. He also served as a Director and Senior Vice President and Chief Financial Officer of the general partner of Rice Midstream Partners LP (former master limited partnership acquired by the Company through its acquisition of Rice Energy Inc.) from November 2017 to July 2018. Prior to joining the Company, Mr. McNally served as Executive Vice President and Chief Financial Officer of Precision Drilling Corporation, a publicly traded drilling services company, from July 2010 to March 2016. Mr. McNally is also a Director of the Company, having served on the Company’s Board of Directors since November 2018. |

| Jeffery C. Mitchell (46) | | Vice President and Principal Accounting Officer (2018) | | Elected to present position November 2018. Mr. Mitchell served as Vice President and Controller of the Company’s production business from March 2015 to November 2018; Corporate Director, Internal Audit, from March 2013 to March 2015; and Corporate Director, Internal Audit and Financial Risk, from October 2011 to March 2013. |

| David J. Smith (60) | | Senior Vice President, Human Resources (2018) | | Elected to present position November 2018. Mr. Smith served as Corporate Director, Compensation and Benefits, of the Company from February 1995 to November 2018. |

| Jimmi Sue Smith (46) | | Senior Vice President and Chief Financial Officer (2016) | | Elected to present position November 2018. Ms. Smith served as the Company’s Chief Accounting Officer from September 2016 to November 2018; Vice President and Controller of the Company’s midstream and commercial businesses from March 2013 to September 2016; and Vice President and Controller of the Company’s midstream business from January 2013 through March 2013. Ms. Smith also served as Chief Accounting Officer of the general partners of EQM Midstream Partners, LP and EQGP Holdings, LP from September 2016 to October 2018, and served as the Chief Accounting Officer of the general partner of Rice Midstream Partners LP, from November 2017 to July 2018. |

The [removed: Company’s] [added: Company's] common stock is [removed: listed] [added: traded] on the New York Stock Exchange [removed: trading] under the [removed: ticker] symbol "EQT."

As of [removed: January 31, 2019,] [added: February 25, 2020,] there were [removed: 2,188] [added: 2,059] shareholders of record of the [removed: Company’s] [added: Company's] common stock.

The amount and timing of dividends declared and paid by the Company, if any, is subject to the discretion of the Company's Board of Directors and depends [removed: upon] [added: on] business conditions, such as the [removed: Company’s] [added: Company's] results of operations and financial condition, strategic direction and other factors.

[removed: Recent] [added: Recent] Sales of Unregistered [removed: Securities][added: Securities]

[removed: Market Repurchases][added: Market Repurchases]

The [removed: following table sets forth the Company’s repurchases of] [added: Company did not repurchase any] equity securities registered under Section 12 of the Securities Exchange Act of 1934, as amended, [removed: that occurred] during the three months ended December 31, [removed: 2018:][added: 2019.]

[removed: Stock] [added: Stock] Performance [removed: Graph][added: Graph]

The following graph compares the most recent [removed: five-year] cumulative [added: five-year] total return [removed: attained by holders] [added: provided to shareholders] of the [removed: Company’s] [added: Company's] common stock with the cumulative [added: five-year] total returns of the S&P 500 Index and two customized peer [removed: groups.][added: groups, the 2018 Self-Constructed Peer Group and 2019 Self-Constructed Peer Group, whose company composition is discussed in footnotes (a) and (b), respectively, below.]

Historical prices prior to the Separation and Distribution [removed: in November 2018] have been adjusted to reflect the value of the Separation and [removed: Distribution transactions.][added: Distribution.]

[removed: ][added: ]

[removed: *The] [added: The] stock price performance [removed: included] [added: shown] in [removed: this] [added: the] graph [added: below] is not necessarily indicative of future stock price performance.

| (a) | The [removed: 2017] [added: 2018] Self-Constructed Peer Group includes the following [removed: twenty-one] [added: seventeen] companies: Antero Resources [removed: Corp,] [added: Corp., Apache Corp.,] Cabot Oil & Gas [removed: Corp,] [added: Corp.,] Chesapeake Energy [removed: Corp,] [added: Corp.,] Cimarex Energy [removed: Co,] [added: Co.,] CNX Resources [removed: Corp,] [added: Corp.,] Concho Resources Inc., Continental Resources, Inc., Devon Energy [removed: Corp, EOG Resources,] [added: Corp., Diamondback Energy,] Inc., [removed: EXCO] [added: Encana Corp., EOG] Resources, Inc., [added: Hess Corp.,] Marathon Oil [removed: Corp, National Fuel Gas Co, Newfield Exploration Co,] [added: Corp.,] Noble Energy, Inc., [removed: ONEOK, Inc.,] Pioneer Natural Resources [removed: Co, QEP Resources, Inc.,] [added: Co. and] Range Resources [removed: Corp, SM Energy Co, Southwestern Energy Co and Whiting] [added: Corp. Anadarko] Petroleum Corp. [removed: Energen Corp was] [added: and Newfield Exploration Co. were] included in the self-constructed peer group that served as the basis for the stock performance graph in the [removed: Company’s] [added: Company's] Annual Report on Form 10-K for the year ended December 31, [removed: 2017] [added: 2018,] but [removed: has] [added: both entities have] been excluded from the [removed: 2017] [added: 2018] Self-Constructed Peer Group because [removed: it was acquired.] [added: they were acquired during 2019.] |

An investment of $100, with reinvestment of all dividends, is assumed to have been made on December 31, 2014 and its relative performance is tracked through December 31, 2019.

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| | 12/14 | | | | 12/15 | | | | 12/16 | | | | 12/17 | | | | 12/18 | | | | 12/19 | | |

| EQT Corporation | $ | 100.00 | | | $ | 68.97 | | | $ | 86.69 | | | $ | 75.59 | | | $ | 46.25 | | | $ | 26.91 | |

| S&P 500 | 100.00 | | | | 101.38 | | | | 113.51 | | | | 138.29 | | | | 132.23 | | | | 173.86 | | |

| 2018 Self-Constructed Peer Group (a) | 100.00 | | | | 63.86 | | | | 95.16 | | | | 91.24 | | | | 65.24 | | | | 64.55 | | |

| 2019 Self-Constructed Peer Group (b) | 100.00 | | | | 46.11 | | | | 70.23 | | | | 59.90 | | | | 36.78 | | | | 29.68 | | |

| (b) | The 2019 Self-Constructed Peer Group includes the following thirteen companies: Antero Resources Corp., Cabot Oil & Gas Corp., Chesapeake Energy Corp., Cimarex Energy Co., CNX Resources Corp., Encana Corp., Gulfport Energy Corp., Murphy Oil Corp., QEP Resources, Inc., Range Resources Corp., SM Energy Co., Southwestern Energy Co. and WPX Energy Inc. Based on recommendations and advice from Pay Governance LLC (Pay Governance), an independent compensation consultant, and in light of the Company's transformation into a pure-play upstream company following the Separation, the Management Development and Compensation Committee of the Company's Board of Directors (the Compensation Committee) refined the 2019 Self-Constructed Peer Group to include only companies whose natural gas production accounts for greater than 30% of their total production volume. In addition, the Compensation Committee considered the reduction in the Company's market capitalization that resulted from the Separation and Distribution and ultimately decided to exclude from the 2019 Self-Constructed Peer Group companies that fell outside a relative range of market capitalization size when compared to the Company post-Separation. |

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| Period | | Total number of shares purchased (a) | | | Average price paid per share | | | | Total number of shares purchased as part of publicly announced plans or programs | | | Approximate dollar value of shares that may yet be purchased under plans or programs | | |

| October 2018 (October 1 – October 31) | | 424 | | | $ | 46.78 | | | — | | | $ | — | |

| November 2018 (November 1 – November 30) | | 25,332 | | | 31.35 | | | | — | | | — | | |

| December 2018 (December 1 – December 31) | | 242 | | | 17.20 | | | | — | | | — | | |

| Total | | 25,998 | | | $ | 31.47 | | | — | | | — | | |

(a) Reflects the number of shares withheld by the Company to pay taxes upon vesting of restricted stock plus the number of shares purchased as part of publicly announced plans or programs.

The individual companies of the 2017 customized peer group (the 2017 Self-Constructed Peer Group) and the 2018 customized peer group (the 2018 Self-Constructed Peer Group) are listed in footnotes (a) and (b) below, respectively.

An investment of $100 (with reinvestment of all dividends) is assumed to have been made at the close of business on December 31, 2013 in the Company’s common stock, in the S&P 500 Index and in each of the customized peer groups.

Relative performance is tracked through December 31, 2018.

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| | | 12/13 | | | | 12/14 | | | | 12/15 | | | | 12/16 | | | | 12/17 | | | | 12/18 | | |

| EQT Corporation | | $ | 100.00 | | | $ | 84.42 | | | $ | 58.23 | | | $ | 73.18 | | | $ | 63.82 | | | $ | 39.05 | |

| S&P 500 | | 100.00 | | | | 113.69 | | | | 115.26 | | | | 129.05 | | | | 157.22 | | | | 150.33 | | |

| 2017 Self-Constructed Peer Group (a) | | 100.00 | | | | 83.34 | | | | 51.53 | | | | 76.10 | | | | 71.46 | | | | 53.20 | | |

| 2018 Self-Constructed Peer Group (b) | | 100.00 | | | | 86.64 | | | | 55.75 | | | | 81.24 | | | | 75.12 | | | | 53.95 | | |

| (b) | The 2018 Self-Constructed Peer Group includes the following nineteen companies: Anadarko Petroleum Corp, Antero Resources Corp, Apache Corp, Cabot Oil & Gas Corp, Chesapeake Energy Corp, Cimarex Energy Co, CNX Resources Corp, Concho Resources Inc., Continental Resources, Inc., Devon Energy Corp, Diamondback Energy, Inc., Encana Corp, EOG Resources, Inc., Hess Corp, Marathon Oil Corp, Newfield Exploration Co, Noble Energy, Inc., Pioneer Natural Resources Co and Range Resources Corp. The 2018 Self-Constructed Peer Group is the peer group that is used for the Company’s 2018 Incentive Performance Share Unit Program, which utilizes three-year total shareholder return against the peer group as one performance metric. Changes in the 2018 Self-Constructed Peer Group compared to the 2017 Self-Constructed Peer Group were made to reflect the change in size and business operations of the Company. |

Equity Compensation Plans

See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” for information relating to compensation plans under which the Company’s securities are authorized for issuance.

The [removed: Following] [added: following] selected financial data should be read in conjunction with Item [removed: 7,] [added: 7.,] "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Item [removed: 8] [added: 8.,] "Financial Statements and Supplementary [removed: Data," both contained herein.][added: Data." The following summary of operating results reflects variations from various factors, including the volatility of natural gas commodity prices, impairments, the Separation and Distribution and the 2018 Divestitures.]

| | [removed: | As] [added: As] of and for the Years Ended December [removed: 31,] [added: 31,] | | | | | | | | | | | | | | | | | | |

| | [removed: | 2018] [added: 2019] | | | | [removed: 2017] [added: 2018] | | | | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | |

| | [removed: | (Thousands,] [added: (Thousands,] except per share [removed: amounts)] [added: amounts)] | | | | | | | | | | | | | | | | | | |

| Total operating revenues | [removed: |] $ | [removed: 4,557,868] [added: 4,416,484] | | | $ | [removed: 3,091,020] [added: 4,557,868] | | | $ | [removed: 1,387,054] [added: 3,091,020] | | | $ | [removed: 2,131,664] [added: 1,387,054] | | | $ | [removed: 2,285,138] [added: 2,131,664] | |

| Amounts attributable to EQT Corporation: | | | | | | | | | | | | | | | | | | | | [removed: |]

| (Loss) income from continuing operations | [added: $] | [added: (1,221,695 | ) | |] $ | (2,380,920 | ) | | $ | 1,387,029 | | | $ | (531,493 | ) | | $ | (87,274 | ) | [removed: | $ | 256,791 | |]

| Income from discontinued operations, net of tax | [added: —] | [added: | | |] 136,352 | | | | 121,500 | | | | 78,510 | | | | 172,445 | | | [removed: | 130,174 | | |]

| Net (loss) income | [added: $] | [added: (1,221,695 | ) | |] $ | (2,244,568 | ) | | $ | 1,508,529 | | | $ | (452,983 | ) | | $ | 85,171 | | [removed: | $ | 386,965 | |]

| Earnings per share of common stock attributable to EQT Corporation: | | | | | | | | | | | | | | | | | | | | [removed: |]

| Basic: | | | | | | | | | | | | | | | | | | | | [removed: |]

| (Loss) income from continuing operations | [added: $] | [added: (4.79 | ) | |] $ | (9.12 | ) | | $ | 7.40 | | | $ | (3.18 | ) | | $ | (0.57 | ) | [removed: | $ | 1.69 | |]

| Income from discontinued operations | [added: —] | [added: | | |] 0.52 | | | | 0.65 | | | | 0.47 | | | | 1.13 | | | [removed: | 0.86 | | |]

| Net (loss) income | [added: $] | [added: (4.79 | ) | |] $ | (8.60 | ) | | $ | 8.05 | | | $ | (2.71 | ) | | $ | 0.56 | | [removed: | $ | 2.55 | |]

| Diluted: | | | | | | | | | | | | | | | | | | | | [removed: |]

| (Loss) income from continuing operations | [added: $] | [added: (4.79 | ) | |] $ | (9.12 | ) | | $ | 7.39 | | | $ | (3.18 | ) | | $ | (0.57 | ) | [removed: | $ | 1.68 | |]

| Income from discontinued operations | [added: —] | [added: | | |] 0.52 | | | | 0.65 | | | | 0.47 | | | | 1.13 | | | [removed: | 0.86 | | |]

| Net (loss) income | [added: $] | [added: (4.79 | ) | |] $ | (8.60 | ) | | $ | 8.04 | | | $ | (2.71 | ) | | $ | 0.56 | | [removed: | $ | 2.54 | |]

| Total assets | [removed: |] $ | [removed: 20,721,344] [added: 18,809,227] | | | $ | [removed: 29,522,604] [added: 20,721,344] | | | $ | [removed: 15,472,922] [added: 29,522,604] | | | $ | [removed: 13,976,172] [added: 15,472,922] | | | $ | [removed: 12,035,353] [added: 13,976,172] | |

| Total long-term [removed: debt (including] [added: debt, including] current [removed: portion) |] [added: portion] | $ | [removed: 5,497,381] [added: 5,292,979] | | | $ | [removed: 5,997,329] [added: 5,497,381] | | | $ | [removed: 2,427,020] [added: 5,997,329] | | | $ | [removed: 2,299,942] [added: 2,427,020] | | | $ | [removed: 2,466,720] [added: 2,299,942] | |

| Cash dividends declared per share of common stock | [removed: |] $ | 0.12 | | | $ | 0.12 | | | $ | 0.12 | | | $ | 0.12 | | | $ | 0.12 | |

Operating results for the years ended December 31, 2018, 2017, 2016 and 2015 have been recast to reflect the presentation of discontinued operations described in Note 2 to the Consolidated Financial Statements.

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| | | [removed: Page Reference] [added: Page Reference] |

| [Reports of Independent Registered Public Accounting [removed: Firm](#s97B084A36A1551D5990BF64029382976)] [added: Firm](#sF419DD36B4365FC59DFBECBD1DD00142)] | | [removed: [63](#s97B084A36A1551D5990BF64029382976)] [added: [59](#sF419DD36B4365FC59DFBECBD1DD00142)] |

| [Statements of Consolidated Operations for each of the three years in the period ended December 31, [removed: 2018](#s8FF1A425DC475F0DB11AEA69AD4707E4)] [added: 2019](#sD5E5A58C678E5DABB69430E6134F852D)] | | [removed: [65](#s8FF1A425DC475F0DB11AEA69AD4707E4)] [added: [63](#sD5E5A58C678E5DABB69430E6134F852D)] |

| [Statements of Consolidated Comprehensive Income for each of the three years in the period ended December 31, [removed: 2018](#sCE08E995FC7957C5BD912E29B9EBADEB)] [added: 2019](#s2DADF6C3014155E69AB5183A0AE12939)] | | [removed: [66](#sCE08E995FC7957C5BD912E29B9EBADEB)] [added: [64](#s2DADF6C3014155E69AB5183A0AE12939)] |