EQT Corp 8-K, filed Jan 13, 2020
EQT Corp (EQT)
About this 8-K
EQT Corp filed this 8-K on January 13, 2020.
Items reported
- Item 2.02: Financial results
- Item 5.02: Director or officer change, or executive pay
- Item 8.01: Other events
- Item 9.01: Financial statements and exhibits
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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Item 2.02. Results of Operations and Financial Condition.
On January 13, 2020, EQT Corporation (EQT) will file a preliminary prospectus supplement (the Preliminary Prospectus Supplement) to its effective shelf registration statement on Form S-3 (File No. 333-234151) pursuant to Rule 424(b) under the Securities Act of 1933, as amended (the Securities Act), relating to an underwritten public offering of two new series of fixed rate senior notes. The Preliminary Prospectus Supplement contains select preliminary unaudited financial results for the fourth quarter of 2019. Such preliminary results are furnished under the heading “Recent Developments—Select Preliminary Fourth Quarter 2019 Results” in the excerpt from the Preliminary Prospectus Supplement attached hereto as Exhibit 99.1.
Item 5.02. Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.
Compensatory Arrangements for Interim Chief Financial Officer
On July 10, 2019, Kyle Derham began providing services to EQT as a member of EQT’s Evolution Committee and on August 29, 2019, Mr. Derham was appointed as Interim Chief Financial Officer of EQT. On January 13, 2020 (the Commencement Date), EQT will enter into and commence a compensatory arrangement with Mr. Derham, which includes the following elements:
| · | Base Salary: Pursuant to EQT’s offer letter dated January 13, 2020, Mr. Derham’s base salary for his service as Interim Chief Financial Officer will be $750,000 per year, which will be paid in respect of six months of Mr. Derham’s service to EQT during calendar year 2019 and in respect of the portion of 2020 during which Mr. Derham served as Interim Chief Financial Officer (i.e., through January 3, 2020). |
| · | SAR Award: On the Commencement Date, Mr. Derham will be awarded 333,333 stock appreciation rights (SARs) under the EQT Corporation 2019 Long-Term Incentive Plan (the LTIP). The terms and conditions of the SARs are described below under “Grant of Interim CFO SAR Award.” |
Grant of Interim CFO SAR Award
As discussed above, in connection with his appointment as Interim Chief Financial Officer, Mr. Derham will be awarded 333,333 SARs under the LTIP (the Interim CFO SAR Award and such SARs, the Interim CFO SARs). Once vested, each of the Interim CFO SARs entitles Mr. Derham to receive, upon exercise, a number of shares of EQT’s common stock (the Shares), cash, or a combination of Shares and cash, based upon the excess of the Fair Market Value (as defined in the LTIP) of a Share as of the date of exercise over a base price of $10.00. The Interim CFO SARs generally vest as follows:
| · | Service-Vesting Condition: The Interim CFO SARs will generally service-vest to the extent Mr. Derham remains in continuous service to EQT as an employee or as a consultant (i) until the earlier to occur of (A) EQT’s appointment of a permanent Chief Financial Officer, and (B) December 31, 2020, and (ii) through the 24-month anniversary of the Transition Date (as defined below). |
| · | Performance-Vesting Condition: The Interim CFO SARs will performance-vest if Mr. Derham achieves certain individual performance milestones as EQT’s Interim Chief Financial Officer during the period of time beginning on July 10, 2019 (the date upon which Mr. Derham began to serve as a member of EQT’s Evolution Committee) and concluding on the date of EQT’s appointment of its permanent Chief Financial Officer on January 3, 2020, at which time Mr. Derham ceased to serve as EQT’s Interim Chief Financial Officer (the CFO SAR Performance Period). Under the terms of the Interim CFO SARs, the Management Development and Compensation Committee of EQT’s Board of Directors (the Committee) will determine the extent to which the Interim CFO SARs will vest based on the extent to which the individual performance milestones established for Mr. Derham have been achieved. |
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As previously reported, EQT appointed a permanent Chief Financial Officer on January 3, 2020.
The foregoing description of the Interim CFO SAR Award does not purport to be complete and is qualified in its entirety by reference to the grant agreement for Mr. Derham’s Interim CFO SAR Award, the form of which will be filed as an exhibit to EQT’s Annual Report on Form 10-K for the year ended December 31, 2019.
Compensatory Arrangements for Consulting Services
On January 13, 2020, in order to maintain the benefit of Mr. Derham’s expertise and knowledge following EQT’s appointment of a permanent Chief Financial Officer, EQT will enter into a services agreement with Mr. Derham governing his continued provision of services to EQT as a consultant (the Services Agreement). The Services Agreement will be effective as of the date of EQT’s appointment of a permanent Chief Financial Officer on January 3, 2020, at which time Mr. Derham ceased to serve as EQT’s Interim Chief Financial Officer (the Transition Date). The Services Agreement provides that Mr. Derham will serve as a consultant to EQT, performing financial and other advisory services as needed, and will be expected to spend at least 75% of his working time performing his services to EQT as a consultant. Under the Services Agreement, Mr. Derham will be bound by certain restrictive covenants with respect to non-competition, non-solicitation, non-disparagement and confidentiality. The term of the Services Agreement begins on the Transition Date and ends on the 24-month anniversary of the Transition Date, unless terminated earlier by either party upon 30 days’ advance written notice (the Consulting Term). Pursuant to the Services Agreement, EQT will pay Mr. Derham a consulting fee of $60,000 per month and Mr. Derham will be awarded 906,667 SARs under the LTIP. The terms and conditions of such SARs are described below under “Grant of Consulting SAR Award.”
Upon a termination of Mr. Derham’s engagement as a consultant by EQT other than for “cause” (as defined below) or by Mr. Derham for “good reason” (as defined below), Mr. Derham will be entitled to receive a lump sum payment equal to the remaining unpaid consulting fees Mr. Derham would have been entitled to receive through the 24-month anniversary of the Transition Date.
For purposes of the Services Agreement, EQT will have “cause” to terminate Mr. Derham’s service upon the occurrence of Mr. Derham’s: (i) conviction of a felony, a crime of moral turpitude or fraud or commission of an act of fraud, misappropriation or embezzlement in connection with the performance of his duties; or (ii) willful and repeated failure to substantially perform his assigned duties that continues after notice from EQT.
For purposes of the Services Agreement, Mr. Derham will have “good reason” to terminate his engagement with EQT if he resigns within 120 days after the occurrence of any of the following events: (i) EQT requiring Mr. Derham to perform his services to EQT in a geographic location more than 50 miles from where Mr. Derham is providing services to EQT as of the date the Services Agreement is executed by EQT and Mr. Derham and/or (ii) any other action or inaction that constitutes a material breach by EQT of the Services Agreement.
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Grant of Consulting SAR Award
As discussed above, Mr. Derham will be awarded 906,667 SARs (Consulting SARs) under the LTIP in respect of his services to EQT under the Services Agreement (the Consulting SAR Award). Once vested, each of the Consulting SARs entitles Mr. Derham to receive, upon exercise, a number of Shares, cash, or a combination of Shares and cash, based upon the excess of the Fair Market Value (as defined in the LTIP) of a Share as of the date of exercise over a base price of $10.00. The Consulting SARs generally vest as follows:
| · | Service-Vesting Condition: The Consulting SARs will generally service-vest to the extent Mr. Derham remains continuously engaged by EQT from the Transition Date through the end of the Consulting Term. |
| · | Performance-Vesting Condition: The Consulting SARs will performance-vest if Mr. Derham achieves certain individual and company-based performance milestones during the period of time beginning January 1, 2020 and concluding on December 31, 2022 (the Consulting SAR Performance Period). The Consulting SARs that are subject to the achievement of company-based performance milestones will vest based on EQT’s achievement of certain performance targets related to adjusted well costs and EQT’s adjusted free cash flow over the Consulting SAR Performance Period. |
If Mr. Derham’s engagement as a consultant is terminated by EQT without “cause” (as defined in the LTIP), by Mr. Derham for “good reason” (as defined in the Interim CFO SAR Award grant agreement if such termination occurs prior to the Consulting Term, and as defined in the Services Agreement during the Consulting Term), or due to Mr. Derham’s death or “disability” (as defined in the LTIP), the Consulting SARs will service-vest as of such date and remain eligible to vest on a performance basis as described above at the conclusion of the Consulting SAR Performance Period.
If a “change of control” (as defined in the Consulting SAR Award grant agreement) is consummated during the Consulting SAR Performance Period, the Consulting SARs will performance vest (to the extent unvested at the time of the change of control) based on the projected actual performance through the conclusion of the Consulting SAR Performance Period as determined by the Committee in its good faith discretion. Such Consulting SARs will thereafter remain outstanding and eligible to vest on a service basis (to the extent the Consulting SARs are unvested on a service basis as of the change of control).
The foregoing description of the Services Agreement and the Consulting SAR Award does not purport to be complete and is qualified in its entirety by reference to the Services Agreement and form of grant agreement for Mr. Derham’s Consulting SAR Award, which will be filed as exhibits to EQT’s Annual Report on Form 10-K for the year ended December 31, 2019.
Item 8.01. Other Events.
On January 13, 2020, EQT will file the Preliminary Prospectus Supplement. The Preliminary Prospectus Supplement discloses certain recent developments of EQT and its subsidiaries (the Company) under the heading “Summary—Recent Developments,” which is included in the excerpt from the Preliminary Prospectus Supplement attached hereto as Exhibit 99.1 and incorporated herein by reference.
The recent developments referred to above include the Company’s estimate of its proved natural gas, natural gas liquids (NGLs) and crude oil reserves as of December 31, 2019, which was prepared by the Company’s engineers and audited by the independent consulting firm of Ryder Scott Company, L.P. (Ryder Scott). A copy of Ryder Scott’s audit report is attached hereto as Exhibit 99.2 and is incorporated herein by reference.
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Cautionary Statement Concerning Forward-Looking Statements
This Current Report on Form 8-K contains forward-looking statements within the meaning of Section 21E of the Exchange Act and Section 27A of the Securities Act. Statements that do not relate strictly to historical or current facts are forward-looking and are usually identified by the use of words such as “anticipate,” “estimate,” “could,” “would,” “should,” “will,” “may,” “forecast,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe” and other similar words.
Without limiting the generality of the foregoing, forward-looking statements contained in this Current Report on Form 8-K include the expectations of plans, strategies, objectives and growth and anticipated financial and operational performance of the Company, including guidance regarding the Company’s strategy to develop its reserves; drilling plans and programs (including the number, type, depth, spacing, lateral lengths and location of wells to be drilled and the availability of capital to complete these plans and programs); projections of wells set for combo-development, and the timing of implementing and completing combo-development projects; production and sales volumes (including liquids volumes) and growth rates; production of free cash flow; the Company’s ability to reduce its development and completions costs and capital expenditures; the Company’s ability to maximize recoveries per acre; infrastructure programs; monetization transactions, including asset sales, joint ventures or other transactions involving the Company’s assets, and the planned use of the proceeds from any such monetization transactions; acquisition transactions; the Company’s ability to successfully implement and execute the new management team’s organizational, technological and operational initiatives and achieve the anticipated results of such initiatives; the projected capital efficiency savings and other operating efficiencies and synergies resulting from the Company’s acquisitions and divestitures; the timing and structure of any dispositions of the Company’s approximately 19.9% interest in Equitrans Midstream Corporation, and the planned use of the proceeds from any such dispositions; natural gas prices, changes in basis and the impact of commodity prices on the Company’s business; reserves, including potential future downward adjustments and reserve life; potential future impairments of the Company’s assets; projected capital expenditures; liquidity and financing requirements, including funding sources and availability; and the Company’s ability to maintain or improve its credit ratings.
The forward-looking statements included in this Current Report on Form 8-K involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements on current expectations and assumptions about future events, taking into account all information currently available to it. While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond its control. The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, volatility of commodity prices; the costs and results of drilling and operations; access to and cost of capital; uncertainties about estimates of reserves, identification of drilling locations and the ability to add proved reserves in the future; the assumptions underlying production forecasts; the quality of technical data; the Company’s ability to appropriately allocate capital and resources among its strategic opportunities; inherent hazards and risks normally incidental to drilling for, producing, transporting and storing natural gas, NGLs and oil; cyber security risks; availability and cost of drilling rigs, completion services, equipment, supplies, personnel, oilfield services and water required to execute the Company's exploration and development plans; the ability to obtain environmental and other permits and the timing thereof; government regulation or action; environmental and weather risks, including the possible impacts of climate change; and disruptions to the Company’s business due to acquisitions and other significant transactions. These and other risks are described under Item 1A, “Risk Factors,” and elsewhere in EQT’s Annual Report on Form 10-K for the year ended December 31, 2018, as updated by Part II, Item 1A, “Risk Factors” in EQT’s subsequently filed Quarterly Reports on Form 10-Q. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse impact on it.
Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.
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Item 9.01. Financial Statement and Exhibits.
(d) Exhibits.
| Exhibit No. | Description | |
| 23.1 | Consent of Ryder Scott Company, L.P. | |
| 99.1 | Excerpt from Preliminary Prospectus Supplement, dated January 13, 2020 | |
| 99.2 | Independent Petroleum Engineers’ Audit Report | |
| 104.1 | Cover Page Interactive Data File (embedded within the Inline XBRL document) |
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SIGNATURES
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 hereunto duly authorized.
| EQT CORPORATION | ||
| Date: January 13, 2020 | By: | /s/ William E. Jordan |
| Name: | William E. Jordan | |
| Title: | Executive Vice President and General Counsel | |
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Exhibit 23.1
 |  |
| TBPE REGISTERED ENGINEERING FIRM F-1580 | FAX (713) 651-0849 | ||
| 1100 LOUISIANA SUITE 4600 | HOUSTON, TEXAS 77002-5294 | TELEPHONE (713) 651-9191 |
CONSENT OF INDEPENDENT PETROLEUM AND NATURAL GAS CONSULTANTS
As independent petroleum and natural gas consultants, we hereby consent to the inclusion of our audit report for the year ended December 31, 2019 as an exhibit to and reference of our name in the Current Report on Form 8-K, filed on January 13, 2020 by EQT Corporation, and to the incorporation of our audit report and our name by reference into EQT Corporation’s effective registration statements under the Securities Act of 1933, as amended. We have no interest of a substantial or material nature in EQT Corporation or in any affiliate. We have not been employed on a contingent basis, and we are not connected with EQT Corporation, or any affiliate, as a promoter, underwriter, voting trustee, director, officer, employee or affiliate.
| /s/ Ryder Scott Company, L.P. | |
| RYDER SCOTT COMPANY, L.P. | |
| TBPE Firm Registration No. F-1580 |
Houston, Texas
January 13, 2020
| SUITE 600, 1015 4TH STREET, S.W. | CALGARY, ALBERTA T2R 1J4 | TEL (403) 262-2799 | FAX (403) 262-2790 |
| 621 17TH STREET, SUITE 1550 | DENVER, COLORADO 80293-1501 | TEL (303) 623-9147 | FAX (303) 623-4258 |
Exhibit 99.1
Summary
This summary highlights selected information more fully described elsewhere in this prospectus supplement and the accompanying prospectus. This summary does not contain all of the information you should consider before investing in the notes. You should read this prospectus supplement, the accompanying prospectus, any free writing prospectus and the documents incorporated by reference herein and therein carefully, especially the risks of investing in the notes discussed in “Risk Factors” below and in the documents incorporated by reference herein.
Throughout this prospectus supplement, except as otherwise indicated, references to “EQT Corporation” or “EQT” refer to EQT Corporation, a Pennsylvania corporation, and not its consolidated subsidiaries, and references to “we,” “us,” “our,” and the “Company” refer collectively to EQT Corporation and its consolidated subsidiaries. References to “Appalachian Basin” refer to the area of the United States composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie in the Appalachian Mountains. References to “Tcfe” refer to trillion cubic feet of natural gas equivalents, “Bcfe” refer to billion cubic feet of natural gas equivalents and “Mcfe” refer to thousand cubic feet of natural gas equivalents, in each such case, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic feet of natural gas, and references to “MMcf” refer to million cubic feet, “Mcf” refer to thousand cubic feet, “MBbls” refer to a thousand barrels and “MMBtu” refer to a million British thermal units.
Our Company
We are a natural gas production company with operations focused in the cores of the Marcellus and Utica Shales in the Appalachian Basin. As the largest producer of natural gas in the United States, based on average daily sales volumes, we are committed to being the premier producer of this environmentally friendly, reliable, low-cost energy source, while maximizing the long-term value of our assets through operational efficiency and a culture of sustainability.
We are differentiated from our Appalachian Basin peers in the scale and contiguity of our acreage position, with 17.5 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 1.2 million gross acres, including approximately 1.1 million gross acres in the Marcellus play, as of December 31, 2019. We believe our unique asset base supports a multi-year inventory of core combo-development projects, which consist of developing multiple wells and pads simultaneously. Following a change in leadership in July of 2019, we have implemented an operational strategy designed to leverage this differentiation to become the lowest cost operator in the Appalachian Basin, primarily by focusing on combo-development to maximize operational efficiencies. We believe combo-development projects are key to delivering sustainably low well costs and higher returns on invested capital. Beyond cost benefits, combo-development projects maximize reservoir recoveries, mitigate future curtailments and maximize the capital efficiency of our midstream service providers.
Our operations consist of one reportable segment. We have a single, company-wide management team that administers all properties as a whole rather than by discrete operating segments. We measure financial performance as a single enterprise and not on an area-by-area basis. Substantially all of our assets and operations are located in the Appalachian Basin.
Recent Developments
Appointment of New Chief Financial Officer
On January 3, 2020, we announced the election of David M. Khani as EQT’s Chief Financial Officer, effective as of such date. EQT’s former Interim Chief Financial Officer is serving in an executive advisory role to facilitate a smooth transition and assist in the execution of our strategic initiatives.
Change in Operational Strategy Enabled by Successful 100-Day Plan
Following a successful proxy campaign by Toby Z. Rice and other proxy participants named in the proxy statement filed on May 20, 2019 (the Rice Team), EQT’s Board of Directors was substantially reconstituted at its annual meeting of shareholders on July 10, 2019 and, following that meeting, Toby Z. Rice was appointed as EQT’s President and Chief Executive Officer. Also following that meeting, we adopted the detailed transformation plan (the 100-Day Plan) proposed by the Rice Team in its proxy campaign. The 100-Day Plan was designed to effect operational, organizational, cultural and other changes to our business to facilitate the type of long-term planning required to pursue an operational strategy that prioritizes combo-development, which is expected to lower operating costs and increase free cash flow generation.
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In connection with our third quarter 2019 earnings release, we announced that the 100-Day Plan was a success, with an anticipated approximate 25% decrease in well costs, gross general and administrative costs and land and other capital expenditures in 2020 alone. Furthermore, drilling efficiencies (measured in horizontal feet drilled per hour) increased by 50% and 20% in Pennsylvania Marcellus Shale and Utica Shale development, respectively, in the third quarter of 2019 as compared to the second quarter of 2019. Central to these achievements were the installation of proven leadership, the establishment of a stable operations schedule focused on combo-development and the successful implementation of our proprietary digital work environment. In addition, as part of the 100-Day Plan, the workforce was migrated into a simplified organizational structure to enhance accountability, and the organization was streamlined to reduce overhead costs by approximately $65 million a year. Our operational and organizational improvements are expected to result in annual cost savings in excess of $400 million.
By taking these foundational steps to ensure that we are able to execute project planning with the requisite level of accuracy and speed, we have laid the groundwork to transition to a combo-development focus and to transform the Company into a modern and efficient natural gas producer that we believe will be one of the lowest cost natural gas operators in the United States.
Announced Deleveraging Plan
We plan to reduce absolute debt by approximately 30%, or approximately $1.5 billion, by mid-2020 through asset monetizations and increased free cash flow (the Deleveraging Plan). The Deleveraging Plan contemplates generating targeted proceeds from monetizations of select, non-core exploration and production assets, core mineral assets and/or our 19.9% retained equity interest in Equitrans Midstream. Until our leverage target is achieved, we expect to use all free cash flow and divestiture proceeds to reduce debt.
The successful execution of the Deleveraging Plan is based on our current expectations, including with respect to matters beyond our control, and is subject to change. There can be no assurance that we will be able to find attractive asset monetization opportunities or that any such transactions will be completed on our anticipated timeframe, if at all. Furthermore, our estimated value for the assets to be monetized under the Deleveraging Plan involves multiple assumptions and judgments about future events that are inherently uncertain; accordingly, there can be no assurance that the resulting net cash proceeds from asset monetization transactions will be as anticipated, even if such transactions are consummated. Some of the factors that could affect our ability to successfully execute the Deleveraging Plan include changes in the financial condition or prospects of prospective purchasers and the availability of financing to potential purchasers on reasonable terms, the number of prospective purchasers, the number of competing assets on the market, unfavorable economic conditions, industry trends and changes in laws and regulations. If we are not able to successfully execute the Deleveraging Plan or otherwise reduce absolute debt to a level we believe appropriate, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise or delay our strategic plans.
Summary 2019 Year-End Proved Reserve Data
The following table sets forth estimates of our proved natural gas, NGLs and crude oil reserves as of December 31, 2019:
| Natural gas (MMcf) | NGLs and crude oil (MBbls) | Total natural gas, NGLs and crude oil (Mcfe)(a) | ||||||||||
| Developed | 11,811,521 | 105,411 | 12,443,988 | |||||||||
| Undeveloped | 4,865,681 | 26,621 | 5,025,408 | |||||||||
| Total proved reserves | 16,677,202 | 132,032 | 17,469,396 | |||||||||
| (a) | NGLs and crude oil reserves were converted at the rate of one barrel being equivalent to 6,000 cubic feet of natural gas. |
Our estimate of proved natural gas, NGLs and crude oil reserves was prepared by our engineers and audited by the independent consulting firm of Ryder Scott Company, L.P. Our estimated proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For natural gas volumes, the average Henry Hub price of $2.58 per MMBtu as of December 31, 2019 was adjusted for energy content, transportation fees and a regional price differential. For NGLs and crude oil volumes, the average West Texas Intermediate (WTI) posted price of $55.69 per barrel as of December 31, 2019 was adjusted for quality, transportation fees and a regional price differential. All prices do not give effect to derivative transactions and are held constant throughout the lives of the properties.
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Our estimated 17.5 Tcfe of total natural gas, NGLs and crude oil proved reserves as of December 31, 2019 represents a decrease of approximately 4.3 Tcfe as compared to our estimated reserves as of December 31, 2018, which was driven by negative revisions in the undeveloped reserve category. The implementation of our combo-development strategy has resulted in our (i) concentrating operations on our core assets and (ii) implementing new development sequencing processes focused on maximizing efficiencies and productivity. While these steps are anticipated to result in an approximate 25% decrease in well costs, they will negatively impact proved undeveloped reserves as a result of (x) losing previously booked proved undeveloped reserves that are now outside our substantially revised five-year capital allocation program for purposes of our reserves calculations and (y) executing a development sequencing strategy that will result in increased probable-to-proved developed conversion (instead of proved undeveloped-to-proved developed) than under the legacy development approach.
Based on the mix of our proved undeveloped and probable reserves, we estimate an undeveloped drilling inventory of approximately 1,685 net locations in our Pennsylvania and West Virginia Marcellus Shale core, which, at our current drilling pace, gives us more than 15 years of drilling inventory. We believe that our change in development strategy, coupled with our undeveloped inventory in a premier core asset base, will lead to sustainable free cash flow generation and higher returns on invested capital.
Select Preliminary Fourth Quarter 2019 Results
For the fourth quarter of 2019, we expect net sales volumes to be between 370 Bcfe and 375 Bcfe, which is towards the high end of our previously announced guidance range of 355 Bcfe to 375 Bcfe.
Our average realized price, including the impact of cash settled derivatives, for the fourth quarter of 2019 is expected to be between $2.51 and $2.56 per Mcfe. In addition, our average differential is expected to be between $(0.45) and $(0.40) per Mcf, which is within our previously announced guidance range of $(0.45) to $(0.25) per Mcf.
During the fourth quarter of 2019, capital expenditures are expected to be between $340 million and $360 million, which is within our previously announced guidance range of $320 million to $370 million.
During the fourth quarter of 2019, we also expect to incur a non-cash impairment charge between $1.4 billion and $1.8 billion, principally related to the following: (i) reducing the carrying value of certain proved and unproved properties as a result of management’s potential monetization of select, non-core exploration and production assets and depressed natural gas prices and (ii) the write-down of unproved properties which are primarily the result of changes to our development strategy and renewed focus on a refined core operating footprint. This estimated non-cash impairment charge for the fourth quarter of 2019 is subject to a number of assumptions and judgments and may change as we finalize our financial results for the year ended December 31, 2019. It is also possible we may incur additional impairment charges in future periods as a result of the above factors or otherwise.
We have prepared the above estimates in good faith based upon our internal reporting and accruals as of and for the three months ended December 31, 2019. Such estimates are preliminary and inherently uncertain and subject to change as we finalize our financial and operating data for the fourth quarter of 2019. There can be no assurance that our final results for the fourth quarter of 2019 will not differ materially from these estimates. Important factors that could cause actual results to differ materially are set forth under “Disclosure Regarding Forward-Looking Statements” and “Risk Factors” in this prospectus supplement and the documents incorporated by reference herein.
Estimated 2020 Capital Expenditures
We expect our capital expenditures for 2020 to be between $1.25 billion and $1.35 billion, which has been reduced by $50 million, as compared to the guidance provided in our third quarter 2019 earnings release, reflecting continued operational efficiencies. We plan to spend approximately $1 billion of the total capital expenditures on reserve development, with approximately 65% to be spent in the Pennsylvania Marcellus, 20% in the Utica and 15% in the West Virginia Marcellus.
These estimates are based on our current expectations and subject to change. Important factors that could cause actual results to differ materially are set forth under “Disclosure Regarding Forward-Looking Statements” and “Risk Factors” in this prospectus supplement and the documents incorporated by reference herein.
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Exhibit 99.2
EQT CORPORATION
Estimated
Future Reserves and Income
Attributable to Certain
Leasehold and Royalty Interests
SEC Parameters
As of
December 31, 2019
| \s\ Gabrielle Morrow | ||
| Gabrielle Morrow, P. E. | ||
| TBPE License No. 109935 | ||
| Senior Vice President |
[SEAL]
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
 |  |
| TBPE REGISTERED ENGINEERING FIRM F-1580 | FAX (713) 651-0849 | ||
| 1100 LOUISIANA SUITE 4600 | HOUSTON, TEXAS 77002-5294 | TELEPHONE (713) 651-9191 |
January 10, 2020
| EQT Corporation |
| EQT Plaza |
| 625 Liberty Avenue, Suite 1700 |
| Pittsburgh, PA 15222 |
Ladies and Gentlemen:
At the request of EQT Corporation (EQT), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves, future production and discounted future net income as of December 31, 2019 prepared by EQT’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed on January 3, 2020 and presented herein, was prepared for public disclosure by EQT in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves and income data shown herein represent EQT’s estimated net reserves and income data attributable to the leasehold and royalty interests in certain properties owned by EQT as of December 31, 2019. The properties reviewed by Ryder Scott incorporate EQT reserves determinations and are located in the states of Ohio, Pennsylvania and West Virginia.
The properties covered by Ryder Scott’s review account for 100 percent of the total net proved liquid hydrocarbon reserves, 100 percent of the total net proved gas reserves, and 100 percent of the total proved discounted future net income at 10 percent prepared by EQT as of December 31, 2019. For undeveloped locations, EQT determined, and Ryder Scott reviewed and approved, which areas within EQT’s acreage were to be considered proven. Reserves were assigned and projected by EQT for locations within these proven areas and approved by Ryder Scott based on analogous type curves and offset production information.
As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.
Based on our review, including the data, technical processes and interpretations presented by EQT, it is our opinion that the overall procedures and methodologies utilized by EQT in preparing their estimates of the proved reserves, future production and discounted future net income as of December 31, 2019 comply with the current SEC regulations and that the overall proved reserves, future production and discounted future net income for the reviewed properties as estimated by EQT are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.
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EQT Corporation
January 10, 2020
Page 2
The estimated reserves and future net income amounts presented in this report are related to hydrocarbon prices. EQT has informed us that in the preparation of their reserves and income projections, as of December 31, 2019, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves and net income data as estimated by EQT attributable to EQT's interest in properties that we reviewed are summarized below:
| SEC PARAMETERS | ||
| Estimated Net Reserves and Income Data | ||
| Certain Leasehold and Royalty Interests of | ||
| EQT Corporation | ||
| As of December 31, 2019 |
| Proved | ||||||||||||||||
| Developed | Total | |||||||||||||||
| Producing | Non-Producing | Undeveloped | Proved | |||||||||||||
| Audited by Ryder Scott | ||||||||||||||||
| Net Reserves | ||||||||||||||||
| Gas – MMcf | 11,155,863 | 655,653 | 4,865,680 | 16,677,196 | ||||||||||||
| Plant Products – Mbbl | 97,393 | 3,552 | 26,010 | 126,955 | ||||||||||||
| Oil/Condensate – Mbbl | 4,222 | 243 | 612 | 5,077 | ||||||||||||
| Income Data (M$) | ||||||||||||||||
| Future Gross Revenue | $ | 28,428,993 | $ | 1,635,038 | $ | 12,162,124 | $ | 42,226,155 | ||||||||
| Deductions | 15,261,988 | 630,382 | 7,217,213 | 23,109,583 | ||||||||||||
| Future Net Income (FNI) | $ | 13,167,005 | $ | 1,004,656 | $ | 4,944,911 | $ | 19,116,572 | ||||||||
| Discounted FNI @ 10% | $ | 6,509,504 | $ | 572,255 | $ | 1,581,512 | $ | 8,663,271 | ||||||||
Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, discounted future net income data are expressed as thousands of U.S. dollars (M$).
The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of U.S. state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
EQT Corporation
January 10, 2020
Page 3
Reserves Included in This Report
In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.
The various proved reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the shut-in status category.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At EQT’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.
Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
Audit Data, Methodology, Procedure and Assumptions
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
EQT Corporation
January 10, 2020
Page 4
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves, prepared by EQT, for the properties that we reviewed were estimated by performance methods and analogy. Approximately 94 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data available through October, 2019, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by EQT or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 6 percent of the proved producing reserves that we reviewed were estimated by analogy. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserves estimates was considered to be inappropriate.
One hundred percent of the proved developed non-producing and undeveloped reserves that we reviewed were estimated by the analogy method. The data utilized from the analogues were considered sufficient for the purpose thereof.
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
EQT Corporation
January 10, 2020
Page 5
As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by EQT relating to hydrocarbon prices and costs as noted herein.
The hydrocarbon prices furnished by EQT for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
The initial SEC hydrocarbon prices in effect on December 31, 2019 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by EQT for the geographic areas reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.
The product prices which were actually used by EQT to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used by EQT were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by EQT.
The table below summarizes EQT’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as EQT’s “average realized prices.” The average realized prices shown in the table below were determined from EQT’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and EQT’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.
| Geographic Area | Product | Price Reference |
Average Benchmark Prices |
Average Realized Prices |
| North America | ||||
| United States, | Gas | Henry Hub | $2.58/MMBTU | $2.41/MCF |
| Appalachia Region | Plant Products | Mont Belvieu-Propane | $23.13/BBL | $16.81/BBL |
| Oil/Condensate | WTI Cushing | $55.69/BBL | $41.43/BBL |
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
EQT Corporation
January 10, 2020
Page 6
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in EQT’s individual property evaluations.
Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserves estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
Operating costs furnished by EQT are based on the operating expense reports of EQT and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by EQT were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by EQT. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs furnished by EQT are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by EQT were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by EQT. The estimated net cost of abandonment after salvage was included by EQT for properties where abandonment costs net of salvage were material. EQT’s estimates of the net abandonment costs were accepted without independent verification.
The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with EQT’s plans to develop these reserves as of December 31, 2019. The implementation of EQT’s development plans as presented to us is subject to the approval process adopted by EQT’s management. As the result of our inquiries during the course of our review, EQT has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by EQT’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to EQT. EQT has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, EQT has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2019, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Current costs used by EQT were held constant throughout the life of the properties.
EQT’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
EQT Corporation
January 10, 2020
Page 7
Test data and other related information were used by EQT to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by EQT. Wells or locations that are not currently producing may start producing earlier or later than anticipated in EQT’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
EQT’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a review of the properties in which EQT owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by EQT for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Certain technical personnel of EQT are responsible for the preparation of reserves estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.
EQT has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of EQT’s forecast of future proved production and income, we have relied upon data furnished by EQT with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by EQT. We consider the factual data furnished to us by EQT to be appropriate and sufficient for the purpose of our review of EQT’s estimates of reserves and future net income. In summary, we consider the assumptions, data, methods and analytical procedures used by EQT and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
EQT Corporation
January 10, 2020
Page 8
Audit Opinion
Based on our review, including the data, technical processes and interpretations presented by EQT, it is our opinion that the overall procedures and methodologies utilized by EQT in preparing their estimates of the proved reserves, future production and discounted future net income as of December 31, 2019 comply with the current SEC regulations and that the overall proved reserves , future production and discounted future net income for the reviewed properties as estimated by EQT are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by EQT in their estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties.
We were in reasonable agreement with EQT's estimates of proved reserves, future production and discounted future net income for the properties which we reviewed; although in certain cases there was more than an acceptable variance between EQT's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to EQT when its reserves estimates were prepared. However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves, future production and discounted future net income owned by EQT.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.
We are independent petroleum engineers with respect to EQT. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
EQT Corporation
January 10, 2020
Page 9
The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by EQT.
EQT makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, EQT has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of EQT, of the references to our name, as well as to the references to our third party report for EQT, which appears in the December 31, 2019 annual report on Form 10-K of EQT. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by EQT.
We have provided EQT with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by EQT and the original signed report letter, the original signed report letter shall control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
| Very truly yours, | |
| RYDER SCOTT COMPANY, L.P. | |
| TBPE Firm Registration No. F-1580 | |
| \s\ Gabrielle Morrow | |
| Gabrielle Morrow, P.E. | |
| TBPE License No. 109935 | |
| Senior Vice President |
[SEAL]
GM (FWZ)/pl
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Gabrielle Guerre Morrow was the primary technical person responsible for overseeing the estimate of the reserves prepared by Ryder Scott presented herein.
Mrs. Morrow, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2009, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mrs. Morrow served in a number of reservoir engineering positions with ExxonMobil. For more information regarding Mrs. Morrow’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.
Mrs. Morrow earned a Bachelor of Science degree in Mechanical Engineering from Kansas State University in 2005. She was given the department awards, Most Outstanding Engineer and Extraordinary Leadership & Service, upon completion of her degree. Mrs. Morrow is a registered Professional Engineer in the State of Texas. She is also a member of the Society of Petroleum Engineers, where she has served on the Gulf Coast Section Board of Directors for the previous 5 years.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mrs. Morrow fulfills. As part of her 2019 continuing education hours, Mrs. Morrow attended 2 hours of formalized training from various professional society presentations specifically relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mrs. Morrow attended an additional 15 hours of formalized in-house training as well as 5 hours of formalized external training during 2019 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.
Based on her educational background, professional training and more than 10 years of practical experience in the estimation and evaluation of petroleum reserves, Mrs. Morrow has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 2
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
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PETROLEUM RESERVES DEFINITIONS
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(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)
SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)
EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.
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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
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Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
| (1) | completion intervals that are open at the time of the estimate but which have not yet started producing; |
| (2) | wells which were shut-in for market conditions or pipeline connections; or |
| (3) | wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
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