销售天然气、天然气液体（NGLs）和石油。根据公司的天然气、天然气液体（NGLs）和石油销售合同，公司通常认为每单位（百万英热单位（MMBtu）或桶（Bbl））的交付是一个单独的履约义务，在交付时得到满足。这些合同通常要求在商品交付的日历月结束后 days 内付款。许多这些合同包含可变报酬，因为支付条款参照未来交付日期的市场价格。在这些情况下，公司未确定独立的销售价格，因为可变支付的条款与公司履行履约义务的努力相关。其他合同，如固定价格合同或与纽约商品交易所（NYMEX）或指数价格存在固定差价的合同，包含固定报酬。固定报酬按照相对独立销售价格的原则分配给每个履约义务，这需要管理层的判断。对于这些合同，公司通常认为合同中的固定价格或固定差价代表了独立销售价格。 25 天然气、天然气液体（NGLs）和石油销售合同。日历月结束后 days 应付款。许多合同包含可变报酬，因为支付条件与未来交付日期时的市场价格有关。在这种情况下，公司未确定独立销售价格，因为可变付款条款与公司履行业务的努力有关。其他合同，如固定价格合同或与纽约商品交易所（NYMEX）或指数价格有固定差价的合同，包含固定报酬。固定报酬按相对独立销售价格的比例分配给每个履约义务，这需要管理层的判断。对于这些合同，公司通常认为合同中的固定价格或差价是独立销售价格的代表。
当公司场外衍生工具合同的任何一项净公允价值代表对公司构成的债务，且超过公司当时适用的信用评级的约定美元阈值时，交易对手有权要求公司存入资金作为按照超过美元阈值金额计算的衍生工具债务部分的保证金存款。公司将这些存款记录为当前资产，在简化合并资产负债表中。截至2024年9月30日， 无 公司具有与信用评级风险相关的有条件特征的场外衍生工具处于净负债位置。截至2023年12月31日，公司具有信用评级风险相关的有条件特征的场外衍生工具处于净负债位置的合计公允价值为6.4 百万美元，其中 no 记录在简化合并资产负债表中需要或记录的存款。
当公司的场外衍生工具合同中任何一种合同的净公允价值代表公司资产超过交易对手当时适用的信用评级的约定美元阈值时，公司有权要求交易对手作为存入保证金的资金，金额等于衍生工具超过美元阈值金额部分。公司将这些存款记录为当前负债在简明合并资产负债表中。截至2024年9月30日和2023年12月31日，简明合并资产负债表中均记录有这样的存款。 no 简明合并资产负债表中记录了这样的存款。
截至2024年9月30日，公司账上大约有未确认税收优惠金额。1 在EQT的循环信贷额度下，尚有百万张信用证未结清和 no 在Eureka的循环信贷额度下，尚有信用证未结清。截止到2023年12月31日，公司大约有$15 在EQT的循环信贷额度下，尚有百万张信用证未结清。
During the three months ended September 30, 2024 and 2023, under EQT's revolving credit facility, the maximum amount of outstanding borrowings was $2,301 million and $158 million, respectively, and the average daily balance was approximately $1,608 million and $28 million, respectively. During the nine months ended September 30, 2024 and 2023, under EQT's revolving credit facility, the maximum amount of outstanding borrowings was $2,301 million and $158 million, respectively, and the average daily balance was approximately $551 million and $9 million, respectively. For each of the three and nine month periods ended September 30, 2024 and 2023, interest under EQT's revolving credit facility was incurred at a weighted average annual interest rate of 6.9%.
Eureka's Revolving Credit Facility. Upon the closing of the Equitrans Midstream Merger, the Company acquired a controlling interest in Eureka Midstream Holdings. See Notes 1 and 12. Eureka, a wholly-owned subsidiary of Eureka Midstream Holdings, has a $400 million senior secured revolving credit facility with Sumitomo Mitsui Banking Corporation, as administrative agent, the lenders party thereto from time to time and any other persons party thereto from time to time.
For the period beginning on July 22, 2024 and ending on September 30, 2024, under Eureka's revolving credit facility, both the maximum amount of outstanding borrowings and average daily balance was $330 million, and interest was incurred at a weighted average annual interest rate of 8.1%.
2024年7月22日，公司根据2024年3月10日签署的的合并协议和计划完成了equitrans midstream的合并，参与方包括EQt、Humpty Merger Sub Inc.（EQt的间接全资子公司）、Humpty Merger Sub LLC（EQt的间接全资子公司）和equitrans midstream。
证券类集体诉讼诉讼2019年12月6日，在宾夕法尼亚州西区联邦地方法院，剑桥养老系统、关岛政府养老基金、东北木工年金基金以及东北木工养老金基金代表自己和所有类似情况下的人，对EQt以及EQt的某些前高管和现任及前任董事提起修正的集体诉讼。起诉书声称，EQt就其2017年与Rice Energy Inc.的合并所作的某些声明是虚假的，并违反了各种联邦证券法。根据起诉书，原告寻求补偿性或返还性损害赔偿，以未指明的金额，因为据称EQT股价在2018年和2019年遭受的种种负面影响而导致该类损害。
在获得联邦能源监管委员会（FERC）授权后，Mountain Valley Pipeline（MVP）于2024年6月14日投入运营。随着长期的固定容量义务的开始，MVP投入运营日期（《基本报表》第8条所定义）于2024年7月1日发生。 我们的生产业务领域致力于在2024年6月30日之前将MVP的初始每天12.9亿立方英尺（Bcf）的固定容量。 因此，由于MVP投入运营日期的发生，我们预计我们的生产业务领域未来的（i）变速器费用将因额外的合同容量而增加，（ii）根据《基本财务报表》第2条所定义的综合GGA条款，汇聚费用将减少。
(a)Prior period selling, general and administrative expense was not recast as the necessary information is not available and the cost to develop such information would be excessive.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Operating Activities. Net cash provided by operating activities was $2,071 million for the nine months ended September 30, 2024 compared to $2,554 million for the same period in 2023. The decrease was due primarily to higher cash operating expenses (including increased transaction costs related to the Equitrans Midstream Merger), unfavorable timing of working capital payments, lower cash operating revenues and higher net interest expense, partly offset by higher net cash settlements received on derivatives and lower net premiums paid on derivatives.
Our cash flows from operating activities are affected by movements in the market price for commodities. We are unable to predict such movements outside of the current market view as reflected in forward strip pricing. For a discussion of potential commodity market risks, refer to "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position" in our Annual Report on Form 10-K for the year ended December 31, 2023.
Investing Activities. Net cash used in investing activities was $2,162 million for the nine months ended September 30, 2024 compared to $3,774 million for the same period in 2023. The decrease was attributable primarily to lower cash paid for the Equitrans Midstream Merger and the NEPA Gathering System Acquisition in 2024 compared to cash paid for the Tug Hill and XcL Midstream Acquisition in 2023 as well as the proceeds received from the NEPA Non-Operated Asset Divestiture, partly offset by increased capital expenditures.
The following tables summarize our capital expenditures.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(Millions)
Production:
Reserve development (a)
$
371
$
355
$
1,283
$
1,147
Land and lease (b)
37
41
105
101
Other production infrastructure
16
17
57
49
Capitalized interest, capitalized overhead and other
31
23
95
70
Total Production
455
436
1,540
1,367
Gathering (c)
80
7
112
12
Transmission
10
—
10
—
Other corporate items
13
2
21
8
Total capital expenditures
558
445
1,683
1,387
Add (deduct): Non-cash items (d)
11
59
(21)
99
Total cash capital expenditures
$
569
$
504
$
1,662
$
1,486
(a)Capital expenditures for reserve development included capital expenditures for water infrastructure of $28.9 million and $7.7 million for the three months ended September 30, 2024 and 2023, respectively, and $58.7 million and $26.4 million for the nine months ended September 30, 2024 and 2023, respectively.
(b)Capital expenditures for land and lease included capital expenditures attributable to noncontrolling interest in The Mineral Company LLC of approximately $8.5 million for the nine months ended September 30, 2023. The Mineral Company LLC was dissolved in the third quarter of 2023.
(c)Gathering capital expenditures included capital expenditures attributable to noncontrolling interest in Eureka Midstream Holdings of approximately $1.6 million for both the three and nine months ended September 30, 2024.
(d)Represents the net impact of non-cash capital expenditures, including the effect of timing of receivables from working interest partners, accrued capital expenditures, transfers to or from inventory as assets are completed or assigned to a project and capitalized share-based compensation costs. The impact of accrued capital expenditures includes the current period estimate, net of the reversal of the prior period accrual.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Financing Activities. Net cash provided by financing activities was $100 million for the nine months ended September 30, 2024 compared to net cash used in financing activities of $174 million for the same period in 2023. For the nine months ended September 30, 2024, the primary sources of financing cash flows were our net borrowings under EQT's revolving credit facility, proceeds from the issuance of EQT's 5.750% senior notes and proceeds from the net settlement of the Capped Call Transactions (defined in Note 7 to the Condensed Consolidated Financial Statements), and the primary uses of financing cash flows were our repayment and retirement of debt, repayment of EQM's revolving credit facility and payment of dividends. For the nine months ended September 30, 2023, the primary source of financing cash flows was proceeds from the Term Loan Facility borrowings, and the primary uses of financing cash flows were our repayment and retirement of debt, repurchase and retirement of EQT common stock and payment of dividends.
See Note 7 to the Condensed Consolidated Financial Statements for further discussion of our debt and borrowings under EQT's revolving credit facility and the Term Loan Facility. See Notes 1 and 7 to the Condensed Consolidated Financial Statements for discussion of borrowings under the revolving credit facility of Eureka Midstream, LLC (Eureka), a wholly-owned subsidiary of Eureka Midstream Holdings.
On October 10, 2024, our Board of Directors declared a quarterly cash dividend of $0.1575 per share of EQT common stock, payable on December 2, 2024, to shareholders of record at the close of business on November 6, 2024.
Depending on our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may from time to time seek to redeem or repurchase our outstanding debt or equity securities through tender offers or other cash purchases in the open market or privately negotiated transactions. The amounts involved in any such transactions may be material. See Note 7 to the Condensed Consolidated Financial Statements for discussion of redemptions and repurchases of debt.
Security Ratings and Financing Triggers
Our credit ratings and rating outlooks are subject to revision or withdrawal at any time by the assigning rating agency, and each rating should be evaluated independently from any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in the rating agency's judgment, circumstances so warrant. See Note 4 to the Condensed Consolidated Financial Statements for a description of what is deemed investment grade.
The table below reflects the credit ratings and rating outlooks assigned to EQT's debt instruments as of September 30, 2024.
Rating agency
Senior notes
Outlook
Moody's Investor Service (Moody's)
Baa3
Negative
Standard and Poor's Ratings Service (S&P)
BBB–
Negative
Fitch Ratings Service (Fitch)
BBB–
Stable
The table below reflects the credit ratings and rating outlooks assigned to EQM's debt instruments as of September 30, 2024.
Rating agency
Senior notes
Outlook
Moody's Investor Service (Moody's)
Ba2
Stable
Standard and Poor's Ratings Service (S&P)
BBB–
Negative
Fitch Ratings Service (Fitch)
BB+
Stable
Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under EQT's and Eureka's revolving credit facilities, the interest rate on the Term Loan Facility, the interest rate on EQT's senior notes with adjustable rates, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our over the counter (OTC) derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. Margin deposits on our OTC derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and our hedging counterparties.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under our debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. EQT's revolving credit facility and the Term Loan Facility contain financial covenants that require us to have a total debt to total capitalization ratio no greater than 65%. As of September 30, 2024, we were in compliance with all EQT, Eureka and EQM debt provisions and covenants under our debt agreements.
See Note 7 to the Condensed Consolidated Financial Statements for a discussion of borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility.
Commodity Risk Management
The substantial majority of our commodity risk management program is related to hedging sales of our produced natural gas. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. The derivative commodity instruments that we use are primarily swap, collar and option agreements. The following table summarizes the approximate volume and prices of our NYMEX hedge positions as of October 25, 2024. The difference between the fixed price and NYMEX price is included in average differential presented in our price reconciliation in "Average Realized Price Reconciliation." The fixed price natural gas sales agreements can be physically or financially settled.
Q4 2024 (a)
Q1 2025
Q2 2025
Q3 2025
Q4 2025
Hedged Volume (MMDth)
377
332
336
281
281
Hedged Volume (MMDth/d)
4.1
3.7
3.7
3.1
3.1
Swaps – Short
Volume (MMDth)
304
250
290
281
95
Avg. Price ($/Dth)
$
3.18
$
3.49
$
3.11
$
3.26
$
3.27
Calls – Long
Volume (MMDth)
13
—
—
—
—
Avg. Strike ($/Dth)
$
3.20
$
—
$
—
$
—
$
—
Calls – Short
Volume (MMDth)
91
188
46
—
137
Avg. Strike ($/Dth)
$
4.23
$
4.19
$
3.48
$
—
$
5.49
Puts – Long
Volume (MMDth)
73
82
46
—
186
Avg. Strike ($/Dth)
$
3.54
$
3.19
$
2.83
$
—
$
3.30
Option Premiums
Cash Settlement of Deferred Premiums (millions)
$
—
$
—
$
—
$
—
$
(45)
(a)October 1 through December 31.
We have also entered into derivative instruments to hedge basis. We may use other contractual agreements to implement our commodity hedging strategy from time to time.
See "Quantitative and Qualitative Disclosures About Market Risk" and Note 4 to the Condensed Consolidated Financial Statements for further discussion of our hedging program.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Commitments and Contingencies
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against us. While the amounts claimed may be substantial, we are unable to predict with certainty the ultimate outcome of such claims and proceedings. We evaluate our legal proceedings, including litigation and regulatory and governmental investigations and inquiries, on a regular basis and accrue a liability for such matters when we believe that a loss is probable and the amount of the loss can be reasonably estimated. Any such accruals are adjusted thereafter as appropriate to reflect changed circumstances. In the event we determine that (i) a loss is probable but the amount of the loss cannot be reasonably estimated, or (ii) a loss is less likely than probable but is reasonably possible, then we are required to disclose the matter in our Annual Report on Form 10-K with any update thereto in this Quarterly Report on Form 10-Q, as applicable, although we are not required to accrue such loss.
When able, we determine an estimate of reasonably possible losses or ranges of reasonably possible losses, whether in excess of any related accrued liability or where there is no accrued liability, for legal proceedings. In instances where such estimates can be made, any such estimates are based on our analysis of currently available information and are subject to significant judgment and a variety of assumptions and uncertainties and may change as new information is obtained.
See Note 13 to the Condensed Consolidated Financial Statements herein and Note 11 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2023 for discussions of our commitments and contingencies, including certain pending legal and regulatory proceedings and other contingent matters.
Additionally, in the normal course of business, we are subject to various other pending and threatened legal proceedings in which claims for monetary damages or other relief are asserted. We do not anticipate, at the present time, that the ultimate aggregate liability, if any, arising out of such other legal proceedings will have a material adverse effect on our financial position, results of operations or liquidity.
Critical Accounting Estimates
Our critical accounting estimates, including a discussion regarding the estimation uncertainty and the impact that our critical accounting estimates have had, or are reasonably likely to have, on our financial condition or results of operations, are described in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" section of our Annual Report on Form 10-K for the year ended December 31, 2023 and have been updated below. The application of our critical accounting estimates may require us to make judgments and estimates about the amounts reflected in the Condensed Consolidated Financial Statements. We use historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.
Goodwill. Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business.
Goodwill is evaluated for impairment at least annually or whenever events or changes in circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We use a combination of an income and market approach to estimate the fair value of our reporting units.
We believe goodwill is a "critical accounting estimate" because the valuation of a reporting unit involves significant judgment and is sensitive to changes in assumptions, including changes in our stock price, weighted-average cost of capital, terminal growth rates and industry multiples. Changes to assumptions could materially affect the estimated fair value of our reporting units and the resulting conclusion on impairment could materially affect our results of operations and financial position. In addition, future assumptions and estimates may materially differ from current assumptions and estimates.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk and Derivative Instruments. Our primary market risk exposure is the volatility of future prices for natural gas and NGLs. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas and NGLs at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations. Prolonged low, or significant, extended declines in, natural gas and NGLs prices could adversely affect, among other things, our development plans, which would decrease the pace of development and the level of our proved reserves and, similarly, could adversely affect timing of development of additional reserves and production that is accessible by our pipeline and storage assets and limit growth in, or may reduce the demand for, and usage of, our gathering or transmission and storage services. Price declines and sustained periods of low natural gas and NGLs prices could also have an adverse effect on the creditworthiness of our gathering and transmission and storage customers and related ability to pay firm reservation fees under long-term contracts. Increases in natural gas and NGLs prices may be accompanied by, or result in, increased well drilling costs, increased production taxes, increased LOE, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels. In addition, to the extent we have hedged our production at prices below the current market price, we will not benefit fully from an increase in the price of natural gas, and, depending on our then-current credit ratings and the terms of our hedging contracts, we may be required to post additional margin with our hedging counterparties.
The overall objective of our hedging program is to protect our cash flows from undue exposure to the risk of changing commodity prices. Our use of derivatives is further described in Note 4 to the Condensed Consolidated Financial Statements and "Commodity Risk Management" under "Capital Resources and Liquidity" in Item 2. Our OTC derivative commodity instruments are placed primarily with financial institutions and the creditworthiness of those institutions is regularly monitored. We primarily enter into derivative instruments to hedge forecasted sales of production. We also enter into derivative instruments to hedge basis. Our use of derivative instruments is implemented under a set of policies approved by our management-level Hedge and Financial Risk Committee and is reviewed by our Board of Directors.
For derivative commodity instruments used to hedge our forecasted sales of production, which are at, for the most part, NYMEX natural gas prices, we set policy limits relative to the expected production and sales levels that are exposed to price risk. We have an insignificant amount of financial natural gas derivative commodity instruments for trading purposes.
The derivative commodity instruments we use are primarily swap, collar and option agreements. These agreements may require payments to, or receipt of payments from, counterparties based on the differential between two prices for the commodity. We use these agreements to hedge our NYMEX and basis exposure. We may also use other contractual agreements when executing our commodity hedging strategy.
We monitor price and production levels on a continuous basis and adjust quantities hedged as warranted.
A hypothetical decrease of 10% in the NYMEX natural gas price on September 30, 2024 and December 31, 2023 would increase the fair value of our natural gas derivative commodity instruments by approximately $440 million and $204 million, respectively. A hypothetical increase of 10% in the NYMEX natural gas price on September 30, 2024 and December 31, 2023 would decrease the fair value of our natural gas derivative commodity instruments by approximately $434 million and $482 million, respectively. For purposes of this analysis, we applied the 10% change in the NYMEX natural gas price on September 30, 2024 and December 31, 2023 to our natural gas derivative commodity instruments as of September 30, 2024 and December 31, 2023 to calculate the hypothetical change in fair value. The change in fair value was determined using a method similar to our normal process for determining derivative commodity instrument fair value described in Note 5 to the Condensed Consolidated Financial Statements.
The above analysis of our derivative commodity instruments does not include the offsetting impact that the same hypothetical price movement may have on our physical sales of natural gas. The portfolio of derivative commodity instruments held to hedge our forecasted produced natural gas approximates a portion of our expected physical sales of natural gas; therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held to hedge our forecasted production associated with the hypothetical changes in commodity prices referenced above should be offset by a favorable impact on our physical sales of natural gas, assuming that the derivative commodity instruments are not closed in advance of their expected term and the derivative commodity instruments continue to function effectively as hedges of the underlying risk.
If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.
Interest Rate Risk. Changes in market interest rates affect the amount of interest we earn on cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility. In addition, changes in Eureka's Consolidated Leverage Ratio (defined in that certain Credit Agreement, dated May 13, 2021, among Eureka, Sumitomo Mitsui Banking Corporation, as administrative agent, the lenders party thereto from time to time and any other persons party thereto from time to time, as amended, governing Eureka's revolving credit facility (the Eureka Credit Agreement)) as a result on Eureka's liquidity needs, operating results or distributions to its member affect the interest rate Eureka pays on borrowings under its revolving credit facility. None of the interest we pay on our senior notes fluctuates based on changes to market interest rates. A 1% increase in interest rates for the borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility during the nine months ended September 30, 2024 would have increased interest expense by approximately $9.7 million.
Interest rates for EQT's revolving credit facility, the Term Loan Facility and EQT's 7.000% senior notes fluctuate based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. Prior to EQT's redemption of all of EQT's outstanding 6.125% senior notes, interest rates for EQT's 6.125% senior notes fluctuated based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. Interest rates for our other outstanding senior notes do not fluctuate based on changes to the credit ratings assigned to our senior notes by Moody's, S&P and Fitch. For a discussion of credit rating downgrade risk, see "Risk Factors – Our operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms" in our Annual Report on Form 10-K for the year ended December 31, 2023. Changes in interest rates affect the fair value of our fixed rate debt. See Note 7 to the Condensed Consolidated Financial Statements for further discussion of our debt and Note 5 to the Condensed Consolidated Financial Statements for a discussion of fair value measurements, including the fair value measurement of our debt.
Other Market Risks. We are exposed to credit loss in the event of nonperformance by counterparties to our derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. Our OTC derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies individually as well as the financial industry as a whole. We use various processes and analyses to monitor and evaluate our credit risk exposures, including monitoring current market conditions and counterparty credit fundamentals. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, we enter into transactions primarily with financial counterparties that are of investment grade, enter into netting agreements whenever possible and may obtain collateral or other security.
Approximately 54%, or $210 million, of our OTC derivative contracts outstanding at September 30, 2024 had a positive fair value. Approximately 86%, or $912 million, of our OTC derivative contracts outstanding at December 31, 2023 had a positive fair value.
As of September 30, 2024, we were not in default under any derivative contracts and had no knowledge of default by any counterparty to our derivative contracts. During the three months ended September 30, 2024, we made no adjustments to the fair value of our derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in our established fair value procedure. We monitor market conditions that may impact the fair value of our derivative contracts.
We are exposed to the risk of nonperformance by credit customers on physical sales of natural gas, NGLs and oil. Revenues and related accounts receivable from our operations are generated primarily from the sale of our produced natural gas, NGLs and oil to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through our transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States and Canada. We also contract with certain processors to market a portion of our NGLs on our behalf.
As of September 30, 2024, no one lender of the large group of financial institutions in the syndicate for either EQT's revolving credit facility or the Term Loan Facility held more than 10% of the financial commitments thereunder. In addition, as of September 30, 2024, no one lender of the large group of financial institutions in the syndicate for Eureka's revolving credit facility held more than 13% of the financial commitments thereunder. The large syndicate group and relatively low percentage of participation by each lender are expected to limit our exposure to disruption or consolidation in the banking industry.
Our management, with the participation of our principal executive officer and our principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control over Financial Reporting
Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. During the third quarter of 2024, we completed the Equitrans Midstream Merger and began integrating the acquired assets into our internal control over financial reporting. We will continue to evaluate and monitor our internal control over financial reporting and will continue to evaluate the operating effectiveness of related key controls.
Except as noted above, there were no changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the third quarter of 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against us. While the amounts claimed may be substantial, we are unable to predict with certainty the ultimate outcome of such claims and proceedings. We accrue legal and other direct costs related to loss contingencies when actually incurred. We have established reserves in amounts that we believe to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any pending matter involving us will not materially affect our financial position, results of operations or liquidity.
Environmental Proceedings
Pratt Storage Field Matter, Morgan Township, Pennsylvania. On October 31, 2018, a gas explosion occurred in Morgan Township, Greene County, Pennsylvania (the Pratt Incident). Following the explosion, the Pennsylvania Department of Environmental Protection (PADEP), the Pennsylvania Public Utilities Commission and the Pipeline and Hazardous Materials Safety Administration of the Department of Transportation (PHMSA) began investigating the Pratt Incident. In October 2019, the PADEP notified Equitrans Midstream that it was required to submit an investigation report pursuant to the state's gas migration regulations due to the Pratt Incident's proximity to Equitrans, L.P.'s (a subsidiary of Equitrans Midstream) Pratt Storage Field assets. Equitrans Midstream, while disputing the applicability of the regulations, submitted a report to the PADEP in May 2020. In September 2020, the PADEP responded to Equitrans Midstream's investigation report with a request for additional information. Equitrans Midstream responded to the September 2020 request. Over the next several months, Equitrans Midstream provided responses to the PADEP's continuing information requests. The PADEP issued a final report and closed its investigation in August 2022, and we do not expect further inquiry from the PADEP on this matter.
On October 23, 2023, Equitrans, L.P. received permission from the FERC to plug and abandon the well in the Pratt Storage Field that was the subject of the PADEP's investigation of the Pratt Incident. On October 22, 2024, Equitrans, L.P. received from the FERC an extension until January 31, 2025 to complete plugging and abandonment of the well. Additionally, Equitrans Midstream is continuing to defend in a civil litigation related to the Pratt Incident.
On October 30, 2023, Equitrans, L.P. received a criminal complaint from the State Attorney General's Office charging Equitrans, L.P. with violations of the Clean Streams Law (the Pratt Complaint). As a result of the Equitrans Midstream Merger, we indirectly assumed Equitrans Midstream's and Equitrans, L.P.'s defense against the Pratt Complaint and matters related to the Pratt Incident. We intend to fully assert Equitrans Midstream's and Equitrans, L.P.'s rights and defenses to the claims raised in the Pratt Complaint. The Pratt Complaint carries the possibility of a monetary sanction, that if imposed could result in a fine in excess of $300,000; however, we expect that the resolution of this matter will not have a material adverse impact on our financial condition, results of operations or liquidity.
Rager Mountain Storage Field Venting, Jackson Township, Pennsylvania. On November 6, 2022, Equitrans Midstream became aware of natural gas venting from one of the storage wells, well 2244, at Equitrans, L.P.'s Rager Mountain natural gas storage facility (the Rager Mountain Facility), located in Jackson Township, a remote section of Cambria County, Pennsylvania. Venting at the Rager Mountain Facility was halted on November 19, 2022. Since the time of the incident, the PADEP has concluded its investigation and PHMSA and other investigators are continuing to conduct civil and criminal investigations of the incident, and Equitrans Midstream has been cooperating in such investigations. On December 7, 2022, Equitrans Midstream and Equitrans, L.P. each separately received an order from the PADEP alleging, in connection with earth disturbance activities undertaken to halt the venting of natural gas from well 2244, (i) in the case of the order received by Equitrans Midstream, violations of Pennsylvania's Clean Streams Law and requiring certain remedial actions and (ii) in the case of the order received by Equitrans, L.P., violations of Pennsylvania's 2012 Oil and Gas Act, Clean Streams Law and Solid Waste Management Act and requiring certain remedial actions. On December 8, 2022, the PADEP submitted a compliance order to Equitrans, L.P. relating to certain alleged violations of law with respect to wells at the Rager Mountain Facility and the venting of natural gas, including from well 2244. The December 8, 2022 order also prohibited Equitrans, L.P. from injecting natural gas into the storage wells at the Rager Mountain Facility. Equitrans Midstream and Equitrans, L.P. disputed aspects of the applicable orders, and on January 5, 2023, Equitrans Midstream and Equitrans, L.P., as applicable, appealed each of the orders to the Commonwealth of Pennsylvania Environmental Hearing Board. Equitrans, L.P. and the PADEP entered into a Stipulation of Settlement on April 12, 2023 that, among other things, resulted in the PADEP rescinding its December 8, 2022 order and Equitrans, L.P. withdrawing its appeal of such order.
On October 5, 2023, Equitrans, L.P. received a notice of violation (NOV) from the PADEP's Bureau of Air Quality Management for the release of uncontrolled hydrocarbons to the atmosphere during the Rager Mountain Facility incident. On April 8, 2024, the PADEP's Bureau of Air Quality Management executed a Consent Assessment of Civil Penalty that settled the October 5, 2023 NOV and included an agreed upon civil penalty of $350,000, which was paid in full by Equitrans Midstream on April 15, 2024.
On April 4, 2024, (i) Equitrans, L.P. and the PADEP entered into a Stipulation of Settlement, that, among other things, resulted in the PADEP deeming the December 8, 2022 orders to Equitrans Midstream and Equitrans, L.P. administratively closed and (ii) the PADEP issued a Civil Penalty Assessment (CPA) in the amount of $764,000, of which $549,500 was reimbursement of PADEP's expenses. The CPA closed the outstanding NOVs issued by the PADEP's Office of Oil and Gas Management related to the Rager Mountain Facility incident. Equitrans Midstream paid the civil penalty pursuant to the CPA in full on April 8, 2024.
On December 29, 2022, the PHMSA issued Equitrans Midstream a Notice of Proposed Safety Order that included proposed remedial requirements related to the Rager Mountain Facility incident, including, but not limited to, completing a root cause analysis, and subsequently, on May 26, 2023, the PHMSA issued a consent order to Equitrans Midstream requiring the completion of a root cause analysis and a remedial work plan and providing that Equitrans Midstream may not resume injection operations at the Rager Mountain Facility until authorized by the PHMSA. In August 2023, Equitrans Midstream submitted a root cause analysis to the PHMSA and later submitted a remedial work plan and injection plan seeking authority to resume injections at the Rager Mountain Facility using all wells in the facility except three, which remained disconnected from the storage field. On October 2, 2023, the PHMSA approved Equitrans Midstream's injection plan and Equitrans Midstream restarted injections at the Rager Mountain Facility on October 5, 2023, subject to certain pressure restrictions and other requirements in the PHMSA consent agreement. On November 16, 2023, the PHMSA issued a letter to Equitrans Midstream approving Equitrans Midstream's request to remove all pressure restrictions at the Rager Mountain Facility. On May 30, 2024, the PHMSA approved resuming operations for one of the three remaining wells excluded from the injection plan.
As a result of the Equitrans Midstream Merger, we indirectly assumed Equitrans Midstream's and Equitrans, L.P.'s defense and responses to matters related to the Rager Mountain Facility incident. We plan to continue working with the PHMSA, pursuant to the consent order between PHSMA and Equitrans Midstream, regarding the remaining two disconnected wells at the Rager Mountain Facility. If additional penalties are pursued and ultimately imposed related to the Rager Mountain Facility incident, the penalties, individually and/or in the aggregate, may exceed $300,000; however, we expect that the resolution of this matter will not have a material adverse impact on our financial condition, results of operations or liquidity.
There are no material changes to the risk factors previously disclosed in the "Risk Factors" section of our Annual Report on Form 10-K for the year ended December 31, 2023 other than those listed below.
Risks Related to Gathering Segment and Transmission Segment Operations
We are subject to numerous operational risks and hazards incidental to the gathering, transmission and storage of natural gas, as well as unforeseen interruptions.
Our business operations are subject to the inherent hazards and risks normally incidental to the gathering, transmission and storage of natural gas. These operating risks, some of which we have experienced and/or could experience in the future, include but are not limited to:
•aging infrastructure and mechanical or structural problems;
•security risks, including cybersecurity;
•pollution and other environmental risks;
•operator error;
•failure of equipment, facilities or new technology;
•damage to pipelines, wells and storage assets, facilities, equipment, environmental controls and surrounding properties, and pipeline blockages or other operational interruptions, caused or exacerbated by natural phenomena, weather conditions, acts of sabotage, vandalism and terrorism;
•inadvertent damage from construction, vehicles, and farm and utility equipment;
•uncontrolled releases of natural gas and other hydrocarbons or of fresh, mixed or produced water, or other hazardous materials;
•leaks, migrations or losses of natural gas as a result of issues regarding pipeline and/or storage equipment or facilities and, including with respect to storage assets, as a result of undefined boundaries, geologic anomalies, limitations in then-applied industry-standard testing methodologies, operational practices (including as a result of regulatory requirements), natural pressure migration and wellbore migration or other factors relevant to such storage assets;
•ruptures, fires, leaks and explosions; and
•other hazards that could also result in personal injury and loss of life, pollution to the environment and suspension of operations.
Any such events, certain of which we have experienced, and any of which we may experience in the future, could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment or interruption, which could be significant, to our operations, regulatory investigations and penalties or other sanctions and substantial losses to us and could have a material adverse effect on our business, financial condition, results of operations, and liquidity, particularly if the event is not fully covered by insurance. The location of certain segments of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. Accidents or other operating risks have resulted, and in the future could result, in loss of service available to our customers. Customer impacts arising from service interruptions on segments of our systems and/or our assets have included and/or may include, without limitation and as applicable, curtailments, limitations on our ability to satisfy customer contractual requirements, obligations to provide reservation charge credits to customers and solicitation of our existing customers by third parties for potential new projects that would compete directly with our existing services. Such circumstances could adversely impact our ability to retain customers and negatively impact our business, financial condition, results of operations, and liquidity.
Expanding our business by constructing new midstream assets subjects us to construction, business, economic, competitive, regulatory, judicial, environmental, political and legal uncertainties that are beyond our control.
The development and construction by us or our joint ventures of pipeline and storage facilities and the optimization of such assets involve numerous construction, business, economic, competitive, regulatory, judicial, environmental, political and legal uncertainties that are beyond our control, require the expenditure of significant amounts of capital and expose us to risks. Those risks include, but are not limited to: (i) physical construction conditions, such as topographical, or unknown or unanticipated geological, conditions and impediments; (ii) construction site access logistics; (iii) crew availability and productivity and ability to adhere to construction workforce drawdown plans; (iv) adverse weather conditions; (v) project opposition, including delays caused by landowners, advocacy groups or activists opposed to our projects and/or the natural gas industry through lawsuits or intervention in regulatory proceedings; (vi) environmental protocols and evolving regulatory or legal requirements and related impacts therefrom, including additional costs of compliance; (vii) the application of time of year or other regulatory restrictions affecting construction, (viii) failure to meet customer contractual requirements; (ix) environmental hazards; (x) vandalism; (xi) the lack of available skilled labor, equipment and materials (or escalating costs in respect thereof, including as a result of inflation); (xii) issues regarding availability of or access to connecting infrastructure; and (xiii) the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all (and maintain such rights-of-way, approvals and permits once obtained, including by reason of judicial hostility or activism). Risks inherent in the construction of these types of projects, such as unanticipated geological conditions, challenging terrain in certain of our construction areas and severe or continuous adverse weather conditions, have adversely affected, and in the future could adversely affect, project timing, completion and cost, as well as increase the risk of loss of human life, personal injuries, significant damage to property or environmental pollution. Most notably, certain of these risks have been realized in the construction of the MVP project, including construction-related risks and adverse weather conditions, and such risks or other risks may be realized in the future which may further adversely affect the timing and/or cost of the MVP and the MVP Southgate project.
Given such risks and uncertainties, our midstream projects or those of our joint ventures may not be completed on schedule, within budgeted cost or at all. As a further example, public participation, including by pipeline infrastructure opponents, in the review and permitting process of projects, through litigation or otherwise, has previously introduced, and in the future can introduce, uncertainty and adversely affect project timing, completion and cost. See also Item 1A., "Risk Factors – The regulatory approval process for the construction of new transmission assets is very challenging, and, as demonstrated with the MVP pipeline, has resulted in significantly increased costs and delayed targeted in-service dates, and decisions by regulatory and/or judicial authorities in pending or potential proceedings relevant to the development of midstream assets, particularly any litigation instituted in the Fourth Circuit, such as regarding the MVP Southgate project and/or expansions or extensions of the MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations, including as may be necessary to complete certain projects in a timely manner or at all, or our ability to achieve the expected investment returns on the projects." Further, civil protests regarding environmental justice and social issues or challenges in project permitting processes related to such issues, including proposed construction and location of infrastructure associated with fossil fuels, poses an increased risk and may lead to increased litigation, legislative and regulatory initiatives and review at federal, state, tribal and local levels of government or permitting delays that can prevent or delay the construction of such infrastructure and realization of associated revenues.
Additionally, construction expenditures on projects generally occur over an extended period, yet we will not receive revenues from, or realize any material increases in cash flow as a result of, the relevant project until it is placed into service. Moreover, our cash flow from a project may be delayed or may not meet our expectations, including as a result of taxes which could potentially be calculated based on excess expenditures, inclusive of maintenance, incurred during extended court-driven construction delays. Furthermore, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize or is delayed beyond our expectations. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return. Such issues in respect of the construction of midstream assets could adversely affect our business, financial condition, results of operations and liquidity.
The regulatory approval process for the construction of new transmission assets is very challenging, and, as demonstrated with the MVP pipeline, has resulted in significantly increased costs and delayed targeted in-service dates, and decisions by regulatory and/or judicial authorities in pending or potential proceedings relevant to the development of midstream assets, particularly any litigation instituted in the Fourth Circuit, such as regarding the MVP Southgate project and/or expansions or extensions of the MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations, including as may be necessary to complete certain projects in a timely manner or at all, or our ability to achieve the expected investment returns on the projects.
Certain of our projects require regulatory approval from federal, state and/or local authorities prior to and/or in the course of construction, including any extensions from, expansions of or additions to our and the MVP Joint Venture's gathering, transmission and storage systems, as applicable. The approval process for certain projects has become increasingly slower and more difficult, due in part to federal, state and local concerns related to exploration and production, transmission and gathering activities and associated environmental impacts, and the increasingly negative public perception regarding, and opposition to, the oil and gas industry, including major pipeline projects like the MVP and MVP Southgate. Further, regulatory approvals and authorizations, even when obtained, have increasingly been subject to judicial challenge by activists requesting that issued approvals and authorizations be stayed and vacated.
Accordingly, authorizations needed for our or the MVP Joint Venture's projects, including any expansion of the MVP project and the MVP Southgate project or other extensions, may not be granted or, if granted, such authorizations may include burdensome or expensive conditions or may later be stayed or revoked or vacated, as was repeatedly the case with the construction of the MVP project, particularly in respect of litigation in the Fourth Circuit. Significant delays in the regulatory approval process for projects, as well as stays and losses of critical authorizations and permits, should they be experienced, have the potential to significantly increase costs, delay targeted in-service dates and/or affect operations for projects (among other adverse effects), as has happened with the MVP and the originally contemplated MVP Southgate projects and could occur in the future in the case of authorizations required for our or the MVP Joint Venture's current or future projects, including in respect of developing expansions or extensions, such as expansion of the MVP project and the MVP Southgate project.
Any such adverse developments and uncertainties could adversely affect our ability, and/or, as applicable, the ability for the MVP Joint Venture and its owners, including us, to achieve expected investment returns, adversely affect our willingness or ability and/or that of our joint venture partners to continue to pursue projects, and/or cause impairments, including to our equity investment in the MVP Joint Venture.
We have experienced and may further experience increased opposition with respect to our and the MVP Joint Venture's projects from activists in the form of lawsuits, intervention in regulatory proceedings and otherwise, which could result in adverse impacts to our business, financial condition, results of operations and liquidity. In particular, opponents were successful in past challenges with respect to the MVP project and certain challenges with respect to MVP project authorizations remain outstanding. Opposition is ongoing regarding the MVP Southgate project and is expected for future projects, including any expansions of the MVP. If ongoing or future challenges are successful, it could result in significant, adverse impacts to our business, financial condition, results of operations and liquidity. Such opposition has made it increasingly difficult to complete projects and place them in service and, following any in-service, may also affect operations or affect extensions and/or expansions of projects. Further, such opposition and/or adverse court rulings and regulatory determinations may have the effect of increasing the timeframe on necessary agency action to address actual or perceived concerns in prior adverse court rulings, or may have the effect of increasing the risk that at a future point joint venture partners may elect not to continue to pursue or fund a project, which could, absent additional project sponsors, significantly imperil the ability to complete the project. See also Item 1A., "Risk Factors – We have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility and divert our management's time and our resources. In addition, we exercise no control over joint venture partners and it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture's best interests and these joint ventures are subject to many of the same risks to which we are subject." Challenges to our projects could adversely affect our business (including by increasing the possibility of investor activism), financial condition, results of operations, and liquidity.
Increased competition from other companies that provide gathering, transmission and storage of natural gas, or from alternative fuel or energy sources, could negatively impact demand for our services, which could adversely affect our financial results.
Our ability to renew or replace existing contracts or add new contracts at rates sufficient to maintain or grow our Gathering segment and Transmission segment revenues and cash flows could be adversely affected by the activities of our midstream competitors. Our midstream systems compete primarily with other interstate and intrastate pipelines and storage facilities in the gathering, transmission and storage of natural gas. Some of our competitors have greater financial resources and may be better positioned to compete, including if the midstream industry moves towards greater consolidation. Some of these competitors may expand or construct gathering systems, transmission and storage systems that would create additional competition for the services we provide to our customers. In addition, certain of our customers have developed or acquired their own gathering infrastructure, and may acquire or develop gathering, transmission or storage infrastructure in the future, which could have a negative impact on the demand for our services depending on the location of such systems relative to our assets and our producer customers' drilling plans, commodity prices, existing contracts and other factors.
The policies of the FERC promoting competition in natural gas markets continue to have the effect of increasing the natural gas transmission and storage options for our customer base. As a result, in the future we could experience "turnback" of firm capacity as existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported or stored on our systems or, in cases where we do not have long-term firm contracts, could force us to lower our transmission or storage rates.
Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, liquid fuels and, increasingly, renewable and alternative energy. Increases, whether driven by legislation, regulation or consumer preferences, in the availability and demand for renewable and alternative energy at the expense of natural gas (or increases in the demand for other sources of energy relative to natural gas based on price and other factors) could adversely affect our producer customers and lead to a reduction in demand for our natural gas gathering, transmission and storage services.
In addition, competition, including from renewable and alternative energy, could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers and/or additional volumes from existing customers as we seek to maintain and expand our business, which could have a material adverse effect on our business, financial condition, results of operations, and liquidity.
We may not be able to renew or replace expiring gathering, transmission or storage contracts at favorable rates, on a long-term basis or at all, and disagreements have occurred and may arise with contractual counterparties on the interpretation of existing or future contractual terms.
One of our exposures to market risk occurs at the time our existing gathering, transmission and storage contracts expire and are subject to renegotiation and renewal. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with existing customers or other customers. We may be unable to do so on favorable commercial terms, if at all. Further, we also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. The extension or renewal of existing contracts and entry into new contracts depends on a number of factors beyond our control, including, but not limited to: (i) the level of existing and new competition to provide services to our markets; (ii) macroeconomic factors affecting natural gas economics for our current and potential customers; (iii) the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets; (iv) the extent to which the customers in our markets are willing to contract on a long-term basis or require capacity on our systems; (v) customers' existing and future downstream commitments; and (vi) the effects of federal, state or local regulations on the contracting practices of our customers and us. Additionally, disagreements may arise with contractual counterparties on the interpretation of contractual provisions, including during the negotiation, for example, of contract amendments required to be entered into upon the occurrence of specified events.
Any failure to extend or replace a significant portion of our existing contracts or to extend or replace our significant contracts, or extending or replacing contracts at unfavorable or lower rates or with lower or no associated firm reservation fee revenues, or other disadvantageous terms relative to the prior contract structure, or disagreements or disputes on the interpretation of existing or future contractual terms, could have a material adverse effect on our business, financial condition, results of operations, and liquidity.
We may not be able to increase our customer throughput and resulting revenue due to competition and other factors, which could limit our ability to grow our Gathering segment and Transmission segment.
Our ability to increase our customer-subscribed capacity and throughput and resulting revenue is subject to numerous factors beyond our control, including competition from producers' existing contractual obligations to competitors, the location of our assets relative to those of competitors for existing or potential producer customers (or such producer customers' own midstream assets), takeaway capacity constraints out of the Appalachian Basin, commodity prices, producers' optionality in utilizing our (relative to third-party) systems to fill downstream commitments, and the extent to which we have available capacity when and where shippers require it. To the extent that we lack available capacity on our systems for volumes, or we cannot economically increase capacity, we may not be able to compete effectively with third-party systems for additional natural gas production in our areas of operation and capacity constraints, as well as commodity prices, may, as has occurred in the past, adversely affect the degree to which natural gas production occurs in the Appalachian Basin, and relatedly the degree to which our systems are utilized.
Our efforts to attract new customers or larger commitments from existing customers may be adversely affected by our desire to provide services pursuant to long-term firm contracts and contracts with MVCs. Our potential customers may prefer to obtain services under other forms of contractual arrangements which could require volumetric exposure or potentially direct commodity exposure, and we may not be willing to agree to such other forms of contractual arrangements.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport or process natural gas or do not accept deliveries of natural gas from us, our business, financial condition, results of operations, and liquidity could be adversely affected.
We depend on third-party pipelines and other facilities that provide receipt and delivery options to and from our transmission and storage systems. For example, our storage system and the MVP Joint Venture's transmission system interconnect, as applicable, with the following third-party interstate pipelines: Transcontinental Gas Pipe Line Company, LLC, East Tennessee Natural Gas, Texas Eastern, Eastern Gas Transmission, Columbia Gas Transmission, Tennessee Gas Pipeline Company, Rockies Express Pipeline LLC, National Fuel Gas Supply Corporation and ET Rover Pipeline, LLC, as well as multiple distribution companies. Similarly, our gathering systems have multiple delivery interconnects to multiple interstate pipelines. In the event that our or the MVP Joint Venture's access to such systems is impaired (or any third-party refuses to accept our or any of the MVP Joint Venture's deliveries), our or the MVP Joint Venture's operations could be adversely affected, resulting in adverse economic impact to us or the MVP Joint Venture.
Because we do not own these third-party pipelines or facilities, their continuing operation and access requirements are not within our control. If these or any other pipeline connections or facilities were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our or the MVP Joint Venture's ability to operate efficiently and ship natural gas to end markets could be restricted, as has occurred in the past. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material adverse effect on our business, financial condition, results of operations, and liquidity.
A substantial majority of the services we provide on our transmission and storage system are subject to long-term, fixed-price "negotiated rate" contracts that are subject to limited or no adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts, we could be unable to achieve the expected investment return under such contracts, and/or our business, financial condition, results of operations, and liquidity could be adversely affected.
It is possible that costs to perform services under "negotiated rate" contracts could exceed the negotiated rates we have agreed to with our customers. If this occurs, it could decrease the cash flow realized by our systems and, therefore, could have a material adverse effect on our business, financial condition, results of operations, and liquidity. Under FERC policy, a regulated service provider and a customer may mutually agree to a "negotiated rate," and that contract must be filed with and accepted by the FERC. As of December 31, 2023, approximately 97% of the contracted firm transmission capacity on our system was subscribed under such "negotiated rate" contracts. Unless the parties to these "negotiated rate" contracts agree otherwise, the contracts generally may not be adjusted to account for increased costs that could be caused by inflation, greenhouse gas emission cost (such as carbon taxes, fees, or assessments) or other factors relating to the specific facilities being used to perform the services.
We have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility and divert our management's time and our resources. In addition, we exercise no control over joint venture partners and it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture's best interests and these joint ventures are subject to many of the same risks to which we are subject.
We have entered into several joint ventures primarily pertaining to the construction and operation of certain midstream infrastructure, including the MVP Joint Venture and Eureka Midstream Holdings, and may in the future enter into additional joint venture arrangements with third parties, including in respect of any expansion of the MVP. Joint venture arrangements may restrict our operational and corporate flexibility. Joint venture arrangements and dynamics can also divert management and operating resources in a manner that is disproportionate to our ownership percentage in such ventures. Because we do not control all of the decisions of our joint ventures or joint venture partners, it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture's best interests. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing that we fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not act in a manner that we believe would be in our or the joint venture's best interests, may elect not to support further pursuit of projects, and/or may not satisfy their financial obligations to the joint venture. The loss of joint venture partner support in further pursuing or funding a project may, and would in the case of the MVP project, significantly adversely affect the ability to complete the project. In addition, such joint ventures are subject to many of the same risks to which we are subject.
Significant portions of our assets have been in service for several decades. There could be unknown events or conditions, or increased maintenance or repair expenses and downtime, associated with our assets that could have a material adverse effect on our business, financial condition, results of operations, and liquidity.
Significant portions of our transmission and storage system have been in service for several decades. The age and condition of these systems has contributed to, and could result in, adverse events, or increased maintenance or repair expenditures, and downtime associated with increased maintenance and repair activities, as applicable. Any such adverse events or any significant increase in maintenance and repair expenditures or downtime, or related loss of revenue, due to the age or condition of our systems could adversely affect our business, financial condition, results of operations, and liquidity. See also Item 1A., "Risk Factors – We and our joint ventures may incur significant costs and liabilities as a result of performance of our pipeline and storage integrity management programs and compliance with increasingly stringent safety regulation."
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations and future development.
We do not own all of the land on which our pipelines, storage systems and facilities have been constructed, and we have been, and in the future could be, subject to more onerous terms, and/or increased costs or delays, in attempting (or by virtue of the need to attempt) to acquire or to maintain use rights to land. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines and other facilities on land owned by third parties and governmental agencies for a specific period of time or in a manner in which certain facts could give rise to the presumption of the abandonment of the pipeline or other facilities. As has been the case in the past, if we were to be unsuccessful in negotiating or renegotiating rights-of-way or easements, we might have to institute condemnation proceedings on our FERC-regulated assets, the potential for which may have a negative effect on the timing and/or terms of FERC action on a project's certification application and/or the timing of any authorized activities, or relocate our facilities for non-regulated assets. The FERC has announced a policy that would presumptively stay the effectiveness of certain future construction certificates, which may limit when we are able to exercise condemnation authority. It is possible that the U.S. Congress may amend Section 7 of the NGA to codify the FERC's presumptive stay or otherwise limit, modify, or remove the ability to utilize condemnation. It is also possible that a court may limit, modify or remove an operator's ability to utilize condemnation under Section 7 of the NGA. A loss of rights-of-way, lease or easements or a relocation of our non-regulated assets could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Additionally, even when we own an interest in the land on which our pipelines, storage systems and facilities have been constructed, agreements with correlative rights owners have caused us to, and in the future may require that we, relocate pipelines and facilities or shut in storage systems and facilities to facilitate the development of the correlative rights owners' estate, or pay the correlative rights owners the lost value of their estate if they are not willing to accommodate development.
Our and the MVP Joint Venture's natural gas gathering, transmission and storage services, as applicable, are subject to extensive regulation by federal, state and local regulatory authorities. Changes in or additional regulatory measures adopted by such authorities, and related litigation, could have a material adverse effect on our business, financial condition, results of operations, and liquidity.
Our and the MVP Joint Venture's interstate natural gas transmission and storage operations, as applicable, are regulated by the FERC under the NGA and the Natural Gas Policy Act of 1978 (NGPA) and the regulations, rules and policies promulgated under those and other statutes. Our and the MVP Joint Venture's FERC-regulated operations are pursuant to tariffs approved by the FERC that establish rates (other than market-based rate authority), cost recovery mechanisms and terms and conditions of service to our customers. The FERC's authority extends to a variety of matters relevant to our operations.
Pursuant to the NGA, existing interstate transmission and storage rates, terms and conditions of service, and contracts may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases, changes to terms and conditions of service and contracts proposed by a regulated interstate pipeline may be protested and such actions can be delayed and may ultimately be rejected by the FERC. As of the filing of this Quarterly Report on Form 10-Q, we and the MVP Joint Venture currently hold authority from the FERC to charge and collect (i) "recourse rates," which are the maximum rates an interstate pipeline may charge for its services under its tariff, (ii) "discount rates," which are rates below the "recourse rates" and above a minimum level, (iii) "negotiated rates," which involve rates that may be above or below the "recourse rates," provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement, and (iv) market-based rates for some of our storage services from which we derive a small portion of our revenues. As of December 31, 2023, approximately 97% of our contracted firm transmission capacity was subscribed to by customers under negotiated rate agreements under our tariff, rather than recourse, discount or market-based rate contracts. There can be no guarantee that we or the MVP Joint Venture will be allowed to continue to operate under such rates or rate structures for the remainder of those assets' operating lives. Customers, the FERC or other interested stakeholders, such as state regulatory agencies, may challenge our or the MVP Joint Venture's rates offered to customers or the terms and conditions of service included in our tariffs. Neither we nor the MVP Joint Venture have an agreement in place that would prohibit customers from challenging our or the MVP Joint Venture's rates or tariffs. Any successful challenge against rates charged for our or the MVP Joint Venture's transmission and storage services, as applicable, could have a material adverse effect on our business, financial condition, results of operations, and liquidity.
Any changes to the FERC's policies regarding the natural gas industry may have an impact on us, including the FERC's approach to pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transmission capacity and transmission and storage facilities. The FERC and U.S. Congress may continue to evaluate changes in the NGA or new or modified FERC regulations or policies that may impact our or the MVP Joint Venture's operations and affect our or the MVP Joint Venture's ability to construct new facilities and the timing and cost of such new facilities, as well as the rates charged to our or the MVP Joint Venture's customers and the services provided.
Our and the MVP Joint Venture's significant construction projects generally require review by multiple governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any agency's delay in the issuance of, or refusal to issue, authorizations or permits, issuance of such authorizations or permits with unanticipated conditions, or the loss of a previously-issued authorization or permit, for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate (as has been the case with our MVP project). Such delays, refusals, losses of permits, or resulting modifications to projects, certain of which we have experienced with respect to the MVP project and the originally contemplated MVP Southgate project, could materially and negatively impact the revenues and costs expected from these projects or cause us or our joint venture partners to abandon planned projects.
Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.5 million (adjusted periodically for inflation) per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes.
In addition, future federal, state or local legislation or regulations under which we or the MVP Joint Venture will operate may have a material adverse effect on our business, financial condition, results of operations, and liquidity.
We and our joint ventures may incur significant costs and liabilities as a result of performance of our pipeline and storage integrity management programs and compliance with increasingly stringent safety regulation.
The U.S. Department of Transportation, acting through PHMSA, and certain state agencies certificated by PHMSA, have adopted regulations requiring pipeline operators to develop an integrity management program for transmission pipelines located where a leak or rupture could impact high population sensitive areas (also known as High Consequence Areas) and newly defined Moderate Consequence Areas, and an integrity management program for storage wells, unless the operator effectively demonstrates by a prescriptive risk assessment that these operational assets have mitigated risks that could affect these predefined areas, as applicable. The regulations require operators, including us, to perform ongoing assessments of pipeline and storage integrity; identify and characterize applicable threats to pipeline segments and storage wells that could impact population sensitive areas; confirm maximum allowable operating pressures; maintain and improve processes for data collection, integration and analysis; repair and remediate facilities as necessary; and implement preventive and mitigating actions. In addition to population sensitive areas, PHMSA has recently adopted regulations extending existing design, operation and maintenance, and reporting requirements to onshore gathering pipelines in rural areas. Finally, new PHMSA regulations require operators of certain transmission pipelines to assess their integrity management and maintenance practices, comply with enhanced corrosion control and mitigation timelines, and follow new requirements for pipeline inspections following an extreme weather event or natural disaster.
The cost and financial impact of compliance will vary and depend on factors such as the number and extent of maintenance determined to be necessary as a result of the application of our integrity management programs, and such costs and financial impact could have a material adverse effect on us. Further, our pipeline and storage integrity management programs depend in part on inspection tools and methodologies developed, maintained, enhanced and applied, and certain testing conducted, by certain third parties, many of which are widely utilized within the natural gas industry. Advances in these tools and methodologies could identify potential and/or additional integrity issues for our assets. Consequently, we may incur additional costs and expenses to remediate those newly identified or potential issues, and we may not have the ability to timely comply with applicable laws and regulations. Additionally, pipeline and storage safety laws and regulations are subject to change and failures to comply with pipeline and storage safety laws and regulations, including changes in such laws and regulations or interpretations thereof that result in more stringent or costly safety standards, could have a material adverse effect on us.
We may, and joint ventures of which we are the operator could, as is the case with the MVP Joint Venture, become subject to consent orders and agreements relating to integrity matters. Failure to comply with any such consent order or agreements could have adverse effects on our business.
Risks Related to the Equitrans Midstream Merger
We incurred significant indebtedness as a result of the Equitrans Midstream Merger, and any future indebtedness, as well as the restrictions under our and our subsidiaries' debt agreements, could adversely affect our operating flexibility, business, financial condition, results of operations, and liquidity.
As a result of the Equitrans Midstream Merger, we incurred additional indebtedness under EQT's revolving credit facility, and the outstanding debt under Eureka's revolving credit facility and the outstanding senior notes issued by EQM were consolidated by the Company. See Note 7 to the Condensed Consolidated Financial Statements for a discussion of EQT's revolving credit facility, Eureka's revolving credit facility and the outstanding senior notes issued by EQM. Eureka's revolving credit facility contains various covenants and restrictive provisions that limit Eureka's ability to, among other things: incur or guarantee additional debt, make distributions on or redeem or repurchase membership units, incur or permit liens on assets, enter into certain types of transactions with affiliates, enter into burdensome agreements, subject to certain specified exceptions, enter into certain mergers or acquisitions; and, dispose of all or substantially all of their respective assets.
Additionally, under Eureka's revolving credit facility, Eureka is required to maintain a Consolidated Leverage Ratio (as defined in the Eureka Credit Agreement) of not more than 4.75 to 1.00 (or not more than 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions). As of the end of any fiscal quarter, Eureka may not permit the ratio of Consolidated EBITDA (as defined in the Eureka Credit Agreement) for the four fiscal quarters then ending to Consolidated Interest Charges (as defined in the Eureka Credit Agreement) to be less than 2.50 to 1.00. Eureka's revolving credit facility also contains certain events of default, including the occurrence of a change of control (as defined in the Eureka Credit Agreement). Events beyond the control of Eureka (including changes in general economic and business conditions) may affect the ability of Eureka to meet and comply with their respective financial obligations and covenants.
The provisions of our and our subsidiaries' debt agreements may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of these debt agreements could result in an event of default, which could enable creditors to, subject to the terms and conditions of the applicable agreement, declare any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, our assets may be insufficient to repay such debt in full, and in turn our shareholders could experience a partial or total loss of their investments. EQT's revolving credit facility, Eureka's revolving credit facility, the Term Loan Facility and certain of EQT's and EQM's senior notes each contain a cross default provision that applies to a default related to any other indebtedness the applicable borrower may have with an aggregate principal amount in excess of a specified threshold as set forth in the applicable debt documents.
Our and our subsidiaries' levels of debt could have important consequences to us, including that our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on favorable terms; our funds available for operations, future business opportunities and dividends to our shareholders may be reduced by that portion of our cash flow required to make interest payments on our or our subsidiaries' debt; we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our and our subsidiaries' current, or our or our subsidiaries' future respective debts, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. Further, we view de-levering our business as a critical strategic objective given that leverage levels affect the manner in which we may pursue strategic and organic initiatives, our ability to respond to market and competitive pressures, and the competition for investment capital. Our ability to de-lever and the pace thereof will depend on our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, as well as the MVP Joint Venture's ability to execute on project-level financing, some of which are beyond our control.
If our operating results are not sufficient to service our and our subsidiaries' current, or our or our subsidiaries' future indebtedness, as applicable, or our operating results affect our ability to comply with covenants in our debt agreements, we may be forced to take actions such as seeking modifications to the terms of our debt agreements, including providing guarantees, pledging assets as collateral, reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity or debt capital. We may not be able to timely effect any of these actions on satisfactory terms or at all. Further, if our operating results are not sufficient to enable de-levering or affect the pace of de-levering, or if MVP project-level financing is not realized, the manner in which we may pursue strategic and organic initiatives, address market and competitive pressures, and compete for investment capital may be adversely affected, absent additional actions to de-lever, which may not be available to us on satisfactory terms or at all.
Our and our subsidiaries' current indebtedness and the additional debt we and/or our subsidiaries will incur in the future for, among other things, working capital, repayment of existing indebtedness, capital expenditures, capital contributions to joint ventures, including the MVP Joint Venture, acquisitions or operating activities may adversely affect our liquidity and therefore our ability to pay dividends to our shareholders.
In addition, our and our subsidiaries' level of indebtedness may be viewed negatively by credit rating agencies, our or our subsidiaries' credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise our shareholder returns strategy or other strategic plans. Changes in our or our subsidiaries' credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on EQT's revolving credit facility, Eureka's revolving credit facility, the Term Loan Facility and EQT's senior notes with adjustable rates, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts.
We may not achieve the anticipated benefits of the Equitrans Midstream Merger, and the Equitrans Midstream Merger may disrupt our current plans or operations.
There can be no assurance that we will be able to successfully integrate Equitrans Midstream and the anticipated benefits of the transaction may not be realized fully or at all or may take longer to realize than expected. If the combined company is not able to realize the anticipated benefits expected from the transaction within the anticipated timing or at all, the combined company's business, financial condition and operating results may be adversely affected, the combined company's earnings per share may be diluted, the accretive effect of the Equitrans Midstream Merger may decrease or be delayed and the share price of the combined company may be negatively impacted. The integration of the two companies has required and will continue to require significant time and focus from management and could result in performance shortfalls as a result of the diversion of management's attention to such integration efforts. Difficulties in integrating Equitrans Midstream into our company may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated synergies on the anticipated timeline. Potential difficulties that may be encountered in the integration process include, among others, complexities associated with managing a larger, more complex, integrated business; potential unknown liabilities and unforeseen expenses associated with Equitrans Midstream; and inconsistencies between the two company's standards, controls, procedures and policies. In addition, our business may be negatively impacted if we are unable to effectively manage our expanded operations.
We are expected to continue to incur significant transaction costs in connection with the Equitrans Midstream Merger, which may be in excess of those anticipated by us.
We have incurred and are expected to continue to incur a number of non-recurring costs associated with the Equitrans Midstream Merger, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial and could have an adverse effect on our financial condition and operating results. For the three and nine months ended September 30, 2024, we recognized $274.6 million and $298.7 million, respectively, of transaction costs related to the Equitrans Midstream Merger. Of this amount, for the three months ended September 30, 2024, we recognized severance and other termination benefits and stock-based compensation costs of $161.0 million.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
We did not repurchase any equity securities registered under Section 12 of the Exchange Act during the third quarter of 2024.
On December 13, 2021, we announced that our Board of Directors approved a share repurchase program (the Share Repurchase Program) authorizing us to repurchase shares of our outstanding common stock for an aggregate purchase price of up to $1 billion, excluding fees, commissions and expenses. On September 6, 2022, we announced that our Board of Directors approved a $1 billion increase to the Share Repurchase Program, pursuant to which approval we are authorized to repurchase shares of our outstanding common stock for an aggregate purchase price of up to $2 billion, excluding fees, commissions and expenses. Repurchases under the Share Repurchase Program may be made from time to time in amounts and at prices we deem appropriate and will be subject to a variety of factors, including the market price of our common stock, general market and economic conditions, applicable legal requirements and other considerations. The Share Repurchase Program was originally scheduled to expire on December 31, 2023; however, on April 26, 2023, we announced that our Board of Directors approved a one-year extension of the Share Repurchase Program. As a result of such extension, the Share Repurchase Program will expire on December 31, 2024, but it may be suspended, modified or discontinued at any time without prior notice. As of September 30, 2024, we had purchased shares for an aggregate purchase price of $622.1 million, excluding fees, commissions and expenses, under the Share Repurchase Program since its inception, and the approximate dollar value of shares that may yet be purchased under the Share Repurchase Program is $1.4 billion.
Item 5. Other Information
During the three months ended September 30, 2024, none of our directors or "officers" (as such term is defined in Rule 16a-1(f) under the Exchange Act) adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement" (as each term is defined in Item 408(a) of Regulation S-K).
Amended and Restated Purchase Agreement, dated December 23, 2022, among THQ Appalachia I, LLC, THQ-XcL Holdings I, LLC, the subsidiaries of the foregoing entities named on the signature pages thereto, EQT Production Company and EQT Corporation.
Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on December 27, 2022.
First Amendment to Amended and Restated Purchase Agreement, dated April 21, 2023, among THQ Appalachia I, LLC, THQ-XcL Holdings I, LLC, the subsidiaries of the foregoing entities named on the signature pages thereto, EQT Production Company and EQT Corporation.
Incorporated herein by reference to Exhibit 2.2 to Form 8-K (#001-3551) filed on August 22, 2023.
Second Amendment to Amended and Restated Purchase Agreement, dated August 21, 2023, among THQ Appalachia I, LLC, THQ-XcL Holdings I, LLC, the subsidiaries of the foregoing entities named on the signature pages thereto, EQT Production Company and EQT Corporation.
Incorporated herein by reference to Exhibit 2.3 to Form 8-K (#001-3551) filed on August 22, 2023.
Agreement and Plan of Merger, dated March 10, 2024, among EQT Corporation, Humpty Merger Sub Inc., Humpty Merger Sub LLC and Equitrans Midstream Corporation.
Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on March 11, 2024.
Indenture, dated August 1, 2014, among EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP), as issuer, the subsidiaries of EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) party thereto, and The Bank of New York Mellon Trust Company, N.A., as trustee.
Incorporated herein by reference to Exhibit 4.1 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on August 1, 2014.
Second Supplemental Indenture, dated November 4, 2016, between EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which EQM Midstream Partners, LP’s 4.125% Senior Notes due 2026 were issued.
Incorporated herein by reference to Exhibit 4.2 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on November 4, 2016.
Fourth Supplemental Indenture, dated June 25, 2018, between EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which EQM Midstream Partners, LP’s 5.500% Senior Notes due 2028 were issued.
Incorporated herein by reference to Exhibit 4.4 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on June 25, 2018.
Fifth Supplemental Indenture, dated June 25, 2018, between EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which EQM Midstream Partners, LP’s 6.500% Senior Notes due 2048 were issued.
Incorporated herein by reference to Exhibit 4.6 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on June 25, 2018.
Indenture, dated June 18, 2020, between EQM Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which EQM Midstream Partners, LP’s 6.000% Senior Notes due 2025 and 6.500% Senior Notes due 2027 were issued.
Incorporated herein by reference to Exhibit 4.1 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on June 18, 2020.
Indenture, dated January 8, 2021, between EQM Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which EQM Midstream Partners, LP’s 4.50% Senior Notes due 2029 and 4.75% Senior Notes due 2031 were issued.
Incorporated herein by reference to Exhibit 4.1 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on January 8, 2021.
Indenture, dated June 7, 2022, between EQM Midstream Partners, LP and U.S. Bank Trust Company, National Association, as trustee, pursuant to which EQM Midstream Partners, LP’s 7.500% Senior Notes due 2027 and 7.500% Senior Notes due 2030 were issued.
Incorporated herein by reference to Exhibit 4.1 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on June 7, 2022.
Indenture, dated February 26, 2024, between EQM Midstream Partners, LP and U.S. Bank Trust Company, National Association, as trustee, pursuant to which EQM Midstream Partners, LP’s 6.375% Senior Notes due 2029 were issued.
Incorporated herein by reference to Exhibit 4.1 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on February 26, 2024.
Fourth Amended and Restated Credit Agreement, dated July 22, 2024, among EQT Corporation, PNC Bank, National Association, as Administrative Agent, Swing Line Lender and L/C Issuer, and the other lenders party thereto.
Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on July 22, 2024.
Fourth Amendment to Credit Agreement, dated July 22, 2024, among EQT Corporation, PNC Bank, National Association, as Administrative Agent, and the other lenders party thereto.
Incorporated herein by reference to Exhibit 10.2 to Form 8-K (#001-3551) filed on July 22, 2024.
Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC, dated as of April 6, 2018, by and among MVP Holdco, LLC, US Marcellus Gas Infrastructure, LLC, WGL Midstream MVP LLC (formerly WGL Midstream, Inc.), Con Edison Gas Pipeline and Storage, LLC, RGC Midstream, LLC and Mountain Valley Pipeline, LLC. Specific items in this exhibit have been redacted, as marked by three asterisks [***], because confidential treatment for those items has been granted by the SEC. The redacted material has been separately filed with the SEC.
Incorporated herein by reference to Exhibit 10.1 to EQM Midstream Partners, LP's Form 10-Q/A (#001-35574) for the quarter ended March 31, 2018.
First Amendment to Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC, dated as of February 5, 2020, by and among MVP Holdco, LLC, US Marcellus Gas Infrastructure, LLC, WGL Midstream MVP LLC (formerly WGL Midstream, Inc.), Con Edison Gas Pipeline and Storage, LLC, RGC Midstream, LLC and Mountain Valley Pipeline, LLC.
Incorporated herein by reference to Exhibit 10.21(b) to Equitrans Midstream Corporation's Form 10-K (#001-38629) for the year ended December 31, 2019.
Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated November 13, 2018, between Equitrans Midstream Corporation and Thomas F. Karam.
Incorporated herein by reference to Exhibit 10.9 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on November 13, 2018.
First Amendment, dated February 20, 2023, to Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated as of November 13, 2018, between Equitrans Midstream Corporation and Thomas F. Karam.
Incorporated herein by reference to Exhibit 10.15(b) to Equitrans Midstream Corporation’s Form 10-K (#001-38629) for the year ended December 31, 2022.
Second Amendment, effective September 6, 2023, to Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated November 13, 2018, between Equitrans Midstream Corporation and Thomas F. Karam.
Incorporated herein by reference to Exhibit 10.3 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on September 7, 2023.
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer.
Furnished herewith as Exhibit 32.
101
Interactive Data File.
Filed herewith as Exhibit 101.
104
Cover Page Interactive Data File.
Formatted as Inline XBRL and contained in Exhibit 101.
+ Certain schedules and similar attachments to this exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. EQT Corporation agrees to provide a copy of any omitted schedule or attachment to the Securities and Exchange Commission or its staff upon request.
** Management contract or compensatory arrangement.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.