EQT Reports Fourth Quarter And Year-End 2019 Results, Execution Of Midstream Rate Renegotiation And Exchange Of Half Its Equity Stake In ETRN

PITTSBURGH, Feb. 27, 2020 /PRNewswire/ -- EQT Corporation (NYSE: EQT) today announced financial and operational performance results for the fourth quarter and year-end 2019, as well as the successful renegotiation of its contractual midstream rates with EQM Midstream Partners, LP (EQM) and the exchange of 50% of its equity stake in Equitrans Midstream Corporation (ETRN).

Fourth Quarter Highlights:

• Achieved sales volumes of 373 Bcfe or 4.06 Bcfe/d, at the high-end of guidance
• Total operating revenues of $1.0 billion; received average realized price of $2.54 per Mcfe
• Capital expenditures of $355 million; well costs of $800 per foot in Pennsylvania Marcellus, on track to hit target well costs
• Net cash provided by operating activities of $218 million; adjusted free cash flow⁽¹⁾ of $148 million

Post Quarter Highlights:

• Executed gas gathering agreement with EQM and exchanged half of equity stake in ETRN, substantially reducing fee structure
• Signed Letter Agreement with EQM for water services
• Reduced 2020 capital expenditure guidance by $150 million – $50 million due to base volume enhancement initiative and continued operational efficiencies, $100 million due to optimization of operations schedule
• Refined hedging strategy adopted and in process
• Maintained a strong current liquidity position of $1.9 billion, reflecting our collateral mitigation strategy
• Hired energy and Appalachian Basin veteran David Khani as CFO on January 3rd
• Successfully issued $1.75 billion in debt to address near-term maturities, the first step in liquidity and debt maturity management strategy
• Signed electric frac fleet contract, improving efficiencies and reducing environmental impact

President and CEO Toby Rice stated: "Since July, we have been preparing to tactically enhance EQT's financial footing and operational execution. We've repositioned our hedge book to protect the 2020 commodity price slide, refinanced our near-term maturities to create financial flexibility and are realizing the tangible benefits of our operational transformation.  These decisive strategic actions have positioned us to successfully navigate this challenging commodity price environment."

Rice continued, "I am excited to announce that we have executed a mutually beneficial gas gathering agreement with EQM, which significantly improves our EBITDA and leverage outlook for 2021 and beyond. This agreement will enable EQT to optimize the development of our long-lived core Marcellus asset in the most capital-efficient manner, driving value accretion for EQT and its stakeholders. This agreement is just one of many strategic steps we are taking to create a long-term, durable and sustainable business model."

STRATEGIC UPDATE

Execution of Gas Gathering Agreement and Exchange of Half ETRN Equity Stake

On February 26, 2020, EQT (and certain of its affiliates) and EQM executed a gas gathering agreement, consolidating nearly all of EQT's existing Pennsylvania and West Virginia gathering contracts with EQM into one new consolidated agreement (New Gathering Agreement). The New Gathering Agreement will provide EQT with gathering and compression fee relief, effective upon the Mountain Valley Pipeline's in-service date, which is currently expected to be January 1, 2021. As part of the New Gathering Agreement, EQT increased its minimum volume commitments (MVC) with EQM, dedicated over 100,000 additional acres in West Virginia to EQM and extended its contractual obligations with EQM to 2035. EQM has also agreed to defer approximately $250 million in current credit assurance posting requirements.

In addition, EQT exchanged half of its equity stake in ETRN for a combination of $52 million in cash proceeds and substantial incremental fee relief. The EBITDA impact of the fee relief is meaningfully more accretive to future leverage than applying the associated value toward debt reduction. The value of the equity stake was determined using ETRN's 20-day volume-weighted average price as of the day prior to execution date.

These transactions will result in approximately $535 million in total fee relief over a three-year period starting in 2021, substantially lowering the profile of EQT's gathering and compression fee structure. The extended contract duration provides EQT visibility into its long-term gathering fee structure, which is expected to decrease by approximately 35% for the period of 2024 through 2035 compared to expected 2020 levels. The economic benefits of these transactions could be enhanced with volume deliveries in excess of MVC's, driven by a beneficial overrun fee structure. These cost savings will significantly improve EQT's EBITDA and leverage metrics in 2021 and beyond, and solidify a peer-leading long-term gathering cost structure.

Water Services Agreement

EQT has signed a letter agreement with EQM to award a minimum of $60 million of water services to EQM for a period of five years commencing with the Mountain Valley Pipeline's in-service date. EQT and EQM expect to finalize the terms of a water services agreement in the coming months.

Asset Monetization Plans

EQT continues to pursue multiple asset monetization opportunities in conjunction with its previously-announced deleveraging plan. Despite weakened commodity prices, the aggregate potential value of these opportunities is substantially greater than EQT's stated debt reduction target. Further, EQT does not believe lower gas prices will impede on its ability to execute multiple transactions. Transaction processes are progressing as planned, market interest is strong and EQT continues to target execution by mid-year 2020.

OPERATIONAL UPDATE

EQT continued to make substantial progress toward its operational transformation during fourth quarter 2019. The infusion of new leadership and a streamlined organizational structure is driving cultural improvements and boosting operational performance. The business connectivity and transparency established through implementation of a digital work environment is driving enhanced performance and efficiencies across the organization. During the fourth quarter, well costs in EQT's Pennsylvania Marcellus operations averaged $800 per foot, a 6% improvement over prior quarter well costs of $850 per foot and an 18% improvement over well costs planned by EQT's legacy management team of $970 per foot. EQT is primed to deliver large-scale combo-development projects and is confident in its ability to deliver on its 2020 operational plan and achieve its Pennsylvania Marcellus well cost target of $730 per foot by second half 2020.

Since July, EQT has seen a step-change in operational performance across the well development cycle. Top-hole drilling days have been reduced by 28%, while horizontal drilling speeds have improved by 38%, driving down total drilling days per well by 16%. Completion operations continue to see efficiency gains, with multiple pads averaging 15% more stages per day than internal target forecasts. These efficiency gains, coupled with EQT's transition from conventional frac fleets to next generation electric frac fleets, set the stage for EQT to not only incrementally improve operations, but to also significantly reduce its carbon footprint, improve safety in its operations and reduce the impact on the communities where it operates. Additionally, EQT's base volume enhancement initiative has increased well performance and uptime, leading to a more robust production profile. The impact of this enhanced operational performance, coupled with the refinement of EQT's operations schedule, will now require $150 million less capital in 2020 to deliver the same production volumes.

With the business analytics and insights in place to optimize our assets, an operations schedule that provides transparency into future development and real-time visibility into key business drivers across the organization, EQT is positioned to become the low-cost leader in the Appalachian Basin. As EQT continues to expand on its digital work environment and moves toward a fully-integrated procure-to-pay enterprise resource planning system, the business will become more efficient and better horizontally integrated. This will enable EQT to better identify opportunities, have a granular understanding of impacts to the business and take decisive action to capitalize on those opportunities. EQT plans to continue driving incremental financial and operational efficiencies.

Net Wells Drilled (Spud)

During fourth quarter 2019, EQT ran two top-hole rigs to spud 24 net Pennsylvania Marcellus wells with average expected lateral lengths of 12,750' and six net Ohio Utica wells with average expected lateral lengths of 11,540'.  During 2019, EQT spud 87 net Pennsylvania Marcellus wells with average expected lateral lengths of 11,510', six net West Virginia Marcellus wells with average expected lateral lengths of 5,890' and 21 net Ohio Utica wells with average expected lateral lengths of 10,240'.

During first quarter 2020, EQT plans to spud 18 net Pennsylvania Marcellus wells with average expected lateral lengths of 14,410' and one net Ohio Utica well with average expected lateral lengths of 14,650'. EQT plans to run two-to-three top-hole rigs in 2020.

Net Wells Horizontally Drilled

During fourth quarter 2019, EQT ran three horizontal drilling rigs to drill 11 net Pennsylvania Marcellus wells with average lateral lengths of 11,590' and eight net Ohio Utica wells with average lateral lengths of 10,530'. During 2019, EQT horizontally drilled 102 net Pennsylvania Marcellus wells with average lateral lengths of 10,900', 20 net West Virginia Marcellus wells with average lateral lengths of 6,310' and 16 net Ohio Utica wells with average lateral lengths of 10,040'.

During first quarter 2020, EQT plans to horizontally drill 17 net Pennsylvania Marcellus wells with average lateral lengths of 12,400' and three net Ohio Utica wells with average lateral lengths of 12,260'. EQT plans to run three-to-four horizontal rigs in 2020.

Net Wells Completed (Frac)

During fourth quarter 2019, EQT used three frac crews to complete 36 net Pennsylvania Marcellus wells with average lateral lengths of 9,990' and four net West Virginia Marcellus wells with average lateral lengths of 9,160'. During 2019, EQT completed 115 net Pennsylvania Marcellus wells with average lateral lengths of 10,590', 15 net West Virginia Marcellus wells with average lateral lengths of 5,770' and 15 net Ohio Utica wells with average lateral lengths of 8,620'.

During first quarter 2020, EQT plans to complete 16 net Pennsylvania Marcellus wells with average lateral lengths of 10,920' and six net Ohio Utica wells with average lateral lengths of 8,960'. EQT plans to run three-to-four frac crews in 2020, including at least one electric frac crew.

Net Wells Turned-in-line (TIL)

During fourth quarter 2019, EQT turned-in-line 25 net Pennsylvania Marcellus wells with average lateral lengths of 9,870' and one net Ohio Utica well with average lateral lengths of 7,490'. During 2019, EQT turned-in-line 105 net Pennsylvania Marcellus wells with average lateral lengths of 10,300', 12 net West Virginia Marcellus wells with average lateral lengths of 4,950' and 20 net Ohio Utica wells with average lateral lengths of 8,540'.

During first quarter 2020, EQT plans to turn-in-line 26 net Pennsylvania Marcellus wells with average lateral lengths of 11,720' and four net West Virginia Marcellus wells with average lateral lengths of 10,390'.

Loss from continuing operations for 2019 was $1.2 billion, or $4.79 per diluted share, an improvement compared to loss from continuing operations for 2018 of $2.4 billion, or $9.12 per diluted share. The variance was attributable primarily to lower impairments of long-lived assets and goodwill and dividends received on the Company's investment in ETRN, partly offset by lower income tax benefit and higher impairment and expiration of leases, unrealized loss on the Company's investment in ETRN and lower operating revenues.

Compared to last year, average realized price was 11% lower at $2.69 per Mcfe, due primarily to lower NYMEX and liquids prices and lower Btu uplift, partly offset by higher cash settled derivatives. Excluding sales volumes related to the Company's divestitures of its Permian and Huron assets in 2018 (2018 Divestitures), sales volumes of natural gas, oil and NGLs increased 4.2% in 2019.

Net cash provided by operating activities decreased by $1,124 million and adjusted free cash flow increased $323 million. Adjusted free cash flow was positively impacted by lower capital expenditures of $966 million. In addition, adjusted free cash flow for the year ended December 31, 2019 of $60 million included the impacts of litigation expense of $82 million and proxy, transaction and reorganization costs of $117 million.

For the year ended December 31, 2019, per Mcfe processing expense and production taxes were lower due to the 2018 Divestitures. For the year ended December 31, 2019, excluding the sales volumes related to the 2018 Divestitures, gathering and transmission expense per Mcfe were $0.55 and $0.50, respectively, in 2018.

Liquidity

As of December 31, 2019, the Company had credit facility borrowings of $294 million and no letters of credit outstanding under its $2.5 billion credit facility and $1 billion in borrowings under its unsecured term loan facility. Net debt⁽¹⁾ was $5,288 million as of December 31, 2019 compared to $5,494 million as of December 31, 2018.

As of February 26, 2020, the Company had sufficient unused borrowing capacity under its credit facility, net of letters of credit, to satisfy any collateral requests that its counterparties would be permitted to seek. As of February 26, 2020, such amounts could be up to approximately $1.4 billion, inclusive of assurances posted of approximately $0.6 billion in the aggregate.  As of February 26, 2020, the Company had no borrowings under it credit facility.  Additional information related to financing activities and liquidity will be contained in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, to be filed with the SEC.

Year-End Proved Reserves

EQT reported year-end 2019 total proved reserves of 17.5 Tcfe, a 20% decrease from 2018 due to a downward revision of previously proved reserves. The implementation of EQT's combo-development strategy has resulted in removing previously booked proved undeveloped reserves that are outside of the revised five-year capital allocation program. EQT's future development strategy is planned on high-quality core acreage with a high degree of confidence in well performance, but, due to SEC reporting requirements, these locations have been classified as probable reserves.

EQT increased its proved developed reserves by 7%, or 0.8 Tcfe, to 12.4 Tcfe from 11.6 Tcfe last year. This increase was driven by proved undeveloped conversions to proved developed reserves.

Proved undeveloped reserves decreased by 50%, or 5.3 Tcfe, to 5.0 Tcfe from 10.3 Tcfe last year, as a result of the Company's strategic shift toward large-scale combo-development projects. Legacy development plans contained a prevalence of return-to-pad drilling, one-off wells and inefficient reservoir development, which resulted in poor operational performance and capital inefficiencies that lead to approximately 25% higher well costs and under-performing wells due to parent-child well interactions as compared to EQT's new combo-development strategy.

Year-end 2019 reserves are based on a $2.58 per MMBtu natural gas price (NYMEX), which is $0.52 lower than the price used to estimate the 2018 reserves. Prices are determined in accordance with the SEC requirement to use the unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions.

Ryder Scott Company, L.P., an independent consulting firm hired by management, reviewed 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company's interests as of December 31, 2019.

Year-End and Fourth Quarter 2019 Webcast Information
The Company's conference call with securities analysts begins at 9:30 a.m. ET today and will be broadcast live via the Company's web site at www.eqt.com and on the investor information page of the Company's web site at ir.eqt.com, with a replay available for seven days following the call.

2020 GUIDANCE

For 2020, 2021, 2022, 2023 and 2024, the Company has natural gas sales agreements for approximately 13 MMDth, 18 MMDth, 18 MMDth, 79 MMDth and 11 MMDth, respectively, that include average NYMEX ceiling prices of $3.68, $3.17, $3.17, $2.84 and $3.21, respectively. The Company also has derivative instruments to hedge basis. The Company may use other contractual agreements to implement its commodity hedging strategy.

NON-GAAP DISCLOSURES

Adjusted Net (Loss) Income from Continuing Operations and Adjusted Earnings per Diluted Share (Adjusted EPS) from Continuing Operations
Adjusted net (loss) income from continuing operations and adjusted EPS from continuing operations are non-GAAP supplemental financial measures that are presented because they are important measures used by the Company's management to evaluate period-to-period comparisons of earnings trends. Adjusted net (loss) income from continuing operations and adjusted EPS from continuing operations should not be considered as alternatives to loss from continuing operations or diluted EPS from continuing operations presented in accordance with GAAP. Adjusted net (loss) income from continuing operations as presented excludes impairments, proxy, transaction and reorganization costs, the revenue impact of changes in the fair value of derivative instruments prior to settlement and certain other items that impact comparability between periods. Management utilizes adjusted net (loss) income from continuing operations to evaluate earnings trends because the measure reflects only the impact of settled derivative contracts; thus, the income from natural gas sales is not impacted by the often-volatile fluctuations in the fair value of derivatives prior to settlement. The measure also excludes other items that affect the comparability of results or that are not indicative of trends in the ongoing business. Management believes that adjusted net (loss) income from continuing operations as presented provides useful information for investors for evaluating period-over-period earnings.

The table below reconciles adjusted net (loss) income from continuing operations and adjusted EPS from continuing operations with loss from continuing operations and diluted EPS from continuing operations, respectively, the most comparable financial measures calculated in accordance with GAAP, each as derived from the Statements of Consolidated Operations to be included in the Company's Annual Report on Form 10-K for the year ended December 31, 2019.

Adjusted EBITDA

Adjusted EBITDA is defined as loss from continuing operations, plus interest expense, income tax benefit, depreciation and depletion, amortization of intangible assets, impairments, proxy, transaction and reorganization costs, the revenue impact of changes in the fair value of derivative instruments prior to settlement and certain other items that impact comparability between periods. Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of the Company's consolidated financial statements, such as industry analysts, lenders and ratings agencies use to assess the Company's earnings trends. The Company believes that adjusted EBITDA is an important measure used by investors in evaluating period-over-period comparisons of earnings trends. Adjusted EBITDA should not be considered as an alternative to the Company's net (loss) income presented in accordance with GAAP. Adjusted EBITDA excludes the revenue impact of changes in the fair value of derivative instruments prior to settlement and other items that affect the comparability of results and are not trends in the ongoing business. Management utilizes adjusted EBITDA to evaluate earnings trends because the measure reflects only the impact of settled derivative contracts and thus the income from natural gas is not impacted by the often-volatile fluctuations in fair value of derivatives prior to settlement.

The table below reconciles adjusted EBITDA with loss from continuing operations, the most comparable financial measure as calculated in accordance with GAAP, as reported in the Statements of Consolidated Operations to be included in the Company's Annual Report on Form 10-K for the year ended December 31, 2019.

The Company has not provided projected net (loss) income or a reconciliation of projected adjusted EBITDA to projected net (loss) income, the most comparable financial measure calculated in accordance with GAAP. Net (loss) income includes the impact of interest expense, income tax benefit or expense, depreciation and depletion expense, the revenue impact of changes in the projected fair value of derivative instruments prior to settlement and certain other items that impact comparability between periods and the tax effect of such items, which may be significant and difficult to project with a reasonable degree of accuracy. Therefore, projected net (loss) income, and a reconciliation of projected adjusted EBITDA to projected net (loss) income, are not available without unreasonable effort.

Adjusted Operating Cash Flow and Adjusted Free Cash Flow
Adjusted operating cash flow is defined as the Company's net cash provided by operating activities less changes in other assets and liabilities, less EBITDA attributable to discontinued operations (a non-GAAP supplemental financial measure defined below), plus interest expense attributable to discontinued operations and cash distributions from discontinued operations. Adjusted free cash flow is defined as adjusted operating cash flow less accrual-based capital expenditures attributable to continuing operations. Adjusted operating cash flow and adjusted free cash flow are non-GAAP supplemental financial measures that the Company's management and external users of its consolidated financial statements, such as industry analysts, lenders and ratings agencies use to assess the Company's liquidity. The Company believes that adjusted operating cash flow and adjusted free cash flow provide useful information to management and investors in assessing the Company's ability to generate cash flow in excess of capital requirements and return cash to shareholders. Adjusted operating cash flow and adjusted free cash flow should not be considered as alternatives to net cash provided by operating activities or any other measure of liquidity presented in accordance with GAAP.

The table below reconciles adjusted operating cash flow and adjusted free cash flow with net cash provided by operating activities, the most comparable financial measure calculated in accordance with GAAP, as derived from the Statements of Consolidated Cash Flows to be included in the Company's Annual Report on Form 10-K for the year ended December 31, 2019.

The Company has not provided projected net cash provided by operating activities or reconciliations of projected adjusted operating cash flow and adjusted free cash flow to projected net cash provided by operating activities, the most comparable financial measure calculated in accordance with GAAP. The Company is unable to project net cash provided by operating activities for any future period because this metric includes the impact of changes in operating assets and liabilities related to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. The Company is unable to project these timing differences with any reasonable degree of accuracy without unreasonable efforts such as predicting the timing of its and customers' payments, with accuracy to a specific day, months in advance. Furthermore, the Company does not provide guidance with respect to its average realized price, among other items, that impact reconciling items between net cash provided by operating activities and adjusted operating cash flow and adjusted free cash flow, as applicable. Natural gas prices are volatile and out of the Company's control, and the timing of transactions and the income tax effects of future transactions and other items are difficult to accurately predict. Therefore, the Company is unable to provide projected net cash provided by operating activities, or the related reconciliations of projected adjusted operating cash flow and adjusted free cash flow to projected net cash provided by operating activities, without unreasonable effort.

EBITDA Attributable to Discontinued Operations
EBITDA attributable to discontinued operations is a non-GAAP supplemental financial measure defined as (loss) income from discontinued operations, net of tax plus interest expense, income tax (benefit) expense, depreciation, amortization of intangible assets and impairment of goodwill attributable to discontinued operations for the three months and year ended December 31, 2018.

The table below reconciles EBITDA attributable to discontinued operations with (loss) income from discontinued operations, net of tax, the most comparable financial measure calculated in accordance with GAAP, as reported in the Statements of Consolidated Operations to be included in the Company's Annual Report on Form 10-K for the year ended December 31, 2019.

Adjusted Operating Revenue
Adjusted operating revenue (also referred to as total natural gas & liquids sales, including cash settled derivatives) is a non-GAAP supplemental financial measure that is presented because it is an important measure used by the Company's management to evaluate period-over-period comparisons of earnings trends. Adjusted operating revenue as presented excludes the revenue impact of changes in the fair value of derivative instruments prior to settlement and the revenue impact of net marketing services and other revenues. Management utilizes adjusted operating revenue to evaluate earnings trends because the measure reflects only the impact of settled derivative contracts and thus does not impact the revenue from natural gas sales with the often-volatile fluctuations in the fair value of derivatives prior to settlement. Adjusted operating revenue also excludes "net marketing services and other" because management considers this revenue to be unrelated to the revenue for its natural gas and liquids production. "Net marketing services and other" includes both the cost of and recoveries on third-party pipeline capacity released as well as revenue for gathering services. Management further believes that adjusted operating revenue, as presented, provides useful information to investors for evaluating period-over-period earnings trends.

The table below reconciles adjusted operating revenue to total operating revenue, the most comparable financial measure calculated in accordance with GAAP, as reported in the Statements of Consolidated Operations to be included in the Company's Annual Report on Form 10-K for the year ended December 31, 2019.

Adjusted SG&A Per Unit
Adjusted SG&A per unit is a non-GAAP supplemental financial measure that is presented because it is an important measure used by the Company's management to evaluate period-to-period comparisons of earnings trends. Adjusted SG&A per unit is defined as SG&A less litigation expense and indirect costs allocated to the midstream business prior to separation that are not permitted to be allocated to discontinued operations under the accounting rules, divided by total sales volumes. The measure excludes items that affect the comparability of results or that are not indicative of trends in the ongoing business. Management believes that adjusted SG&A per unit as presented provides useful information for investors for evaluating period-over-period earnings.

The table below reconciles adjusted SG&A per unit with SG&A, the most comparable financial measure calculated in accordance with GAAP, as derived from the Statements of Consolidated Operations to be included in the Company's Annual Report on Form 10-K for the year ended December 31, 2019.

Net Debt
Net debt is a non-GAAP supplemental financial measure that is presented because it is an important measure used by the Company's management to determine the Company's outstanding debt obligations that would not be readily satisfied by cash and cash equivalents on hand. Net debt is defined as total debt less cash and cash equivalents. Total debt includes the current portion of debt plus, credit facility borrowings, term loan borrowings, senior notes and note payable to EQM. Management believes that net debt as presented provides useful information for investors for evaluating the Company's leverage since the Company could choose to use its cash and cash equivalents to retire debt.

The table below reconciles net debt with total debt, the most comparable financial measure calculated in accordance with GAAP, as derived from the Statements of Consolidated Balance Sheets to be included in the Company's Annual Report on Form 10-K for the year ended December 31, 2019.

About EQT Corporation:
EQT Corporation is a natural gas production company with emphasis in the Appalachian Basin and operations throughout Pennsylvania, West Virginia and Ohio. With 130 years of experience and a long-standing history of good corporate citizenship, EQT is the largest producer of natural gas in the United States. As a leader in the use of advanced horizontal drilling technology, EQT is committed to minimizing the impact of drilling-related activities and reducing its overall environmental footprint. Through safe and responsible operations, EQT is helping to meet our nation's demand for clean-burning energy, while continuing to provide a rewarding workplace and support for activities that enrich the communities where its employees live and work. Visit EQT Corporation at https://www.EQT.com; and to learn more about EQT's sustainability efforts, please visit https://csr.eqt.com.

EQT Management speaks to investors from time to time and the analyst presentation for these discussions, which is updated periodically, is available via the Company's investor relationship website at https://ir.eqt.com.

Cautionary Statements
Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development program. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

This news release contains certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this news release specifically include the expectations of plans, strategies, objectives and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company's strategy to develop its reserves; drilling plans and programs (including the number, type, depth, spacing, lateral length and the number and location of wells to be drilled, spud or turned-in-line, the number and type of drilling rigs, the number and type of frac crews, and the availability of capital to complete these plans and programs); estimated reserves; projected production and sales volumes and growth rates (including liquids production and sales volumes and growth rates); natural gas prices, changes in basis and the impact of commodity prices on the Company's business; the Company's ability to reduce its drilling and completions costs, other costs and expenses, and capital expenditures, and the timing of achieving any such reductions; the Company's ability to successfully implement and execute the executive management team's operational, organizational and technological initiatives, and achieve the anticipated results of such initiatives; the projected reduction of the Company's gathering and compression rates resulting from the Company's new gathering agreement with EQM, and the anticipated cost savings and effects on the Company's EBITDA and financial profile associated with such anticipated rate changes; monetization transactions, including asset sales, joint ventures or other transactions involving the Company's assets, and the Company's planned use of the proceeds from any such monetization transactions; acquisition transactions; the projected capital efficiency savings and other operating efficiencies and synergies resulting from the Company's monetization transactions and acquisition transactions; the timing and structure of any additional dispositions of the Company's retained equity interest in ETRN, and the planned use of the proceeds from any such dispositions; the amount and timing of any repurchases of the Company's common stock or outstanding debt securities; projected dividend amounts and rates; projected cash flows, adjusted operating cash flow and free cash flow; projected capital expenditures; projected adjusted EBITDA; liquidity and financing requirements, including funding sources and availability; the Company's ability to maintain or improve its credit ratings, leverage levels and financial profile; the Company's hedging strategy; and the effects of litigation, government regulation and tax position.

The forward-looking statements included in this new release involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements on current expectations and assumptions about future events, taking into account all information currently available to the Company. While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond the Company's control and which include, but are not limited to, volatility of commodity prices; the costs and results of drilling and operations; access to and cost of capital; uncertainties about estimates of reserves, identification of drilling locations and the ability to add proved reserves in the future; the assumptions underlying production forecasts; the quality of technical data; the Company's ability to appropriately allocate capital and resources among its strategic opportunities; inherent hazards and risks normally incidental to drilling for, producing, transporting and storing natural gas, natural gas liquids and oil; cyber security risks; availability and cost of drilling rigs, completion services, equipment, supplies, personnel, oilfield services and water required to execute the Company's exploration and development plans; the ability to obtain environmental and other permits and the timing thereof; government regulation or action; environmental and weather risks, including the possible impacts of climate change; and disruptions to the Company's business due to acquisitions and other significant transaction. These and other risks and uncertainties are described under Item 1A, "Risk Factors," of the Company's Annual Report on Form 10-K for the year ended December 31, 2018 as filed with the SEC and the Company's Annual Report on Form 10-K for the year ended December 31, 2019 to be filed with the SEC, as updated by any subsequent Form 10-Qs, and those set forth in the other documents the Company files from time to time with the SEC.

Any forward-looking statement speaks only as of the date on which such statement is made, and the Company does not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.

Analyst inquiries please contact:
Andrew Breese - Director, Investor Relations
[email protected]
412.395.2555

SOURCE EQT Corporation

Related Links

https://www.EQT.com