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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

(Mark one)

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2021

OR

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from to_____

Commission File Number: 001-12209

 

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Delaware

 

34-1312571

(State or Other Jurisdiction of Incorporation or Organization)

 

(IRS Employer Identification No.)

 

 

100 Throckmorton Street, Suite 1200, Fort Worth, Texas

 

76102

(Address of Principal Executive Offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code (817) 870-2601

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

Title of Each Class

 

Trading Symbol

 

Name of each exchange on which registered

Common Stock, $.01 par value

 

RRC

 

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

 

 

Smaller reporting company

 

Accelerated filer

 

 

Emerging growth company

 

Non-accelerated filer

 

 

 

 

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act:

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b))by the registered public accounting firm that prepared or issued its audit report.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2021 was $4,229,441,000. This amount is based on the closing price of registrant’s common stock on the New York Stock Exchange on that date. Shares of common stock held by executive officers and directors of the registrant are not included in the computation. However, the registrant has made no determination that such individuals are “affiliates” within the meaning of Rule 405 of the Securities Act of 1933.

As of February 18, 2022, there were 262,145,991 shares of Range Resources Corporation Common Stock outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement to be furnished to stockholders in connection with its 2022 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates, are incorporated by reference in Part II, Item 5 and Part III, Items 10-14 of this report.

 


 

RANGE RESOURCES CORPORATION

Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us” or “our” are to Range Resources Corporation and its directly and indirectly owned subsidiaries. Unless otherwise noted, all information in the report relating to natural gas, natural gas liquids and crude oil reserves and the estimated future net cash flows attributable to those reserves are based on estimates and are net to our interest. If you are not familiar with the oil and gas terms used in this report, please refer to the explanation of such terms under the caption “Glossary of Certain Defined Terms” at the end of Items 1 & 2. Business and Properties of this report.

TABLE OF CONTENTS

PART I

 

Page

ITEMS 1. & 2.

Business and Properties

1

 

General

1

 

Executive Summary for 2021

2

 

Available Information

2

 

Our Business Strategy

2

 

Significant Accomplishments in 2021

4

 

Segment and Geographical Information

4

 

Outlook for 2022

4

 

Proved Reserves

5

 

Property Overview

7

 

Divestitures

8

 

Producing Wells

8

 

Drilling Activity

9

 

Gross and Net Acreage

9

 

Undeveloped Acreage Expirations

9

 

Title to Properties

10

 

Delivery Commitments

10

 

Human Capital Management

10

 

Executive Officers of The Registrant

11

 

Competition

11

 

Marketing and Customers

12

 

Seasonal Nature of Business

12

 

Markets

12

 

Governmental Regulation

13

 

Environmental and Occupational Health and Safety Matters

15

 

Glossary of Certain Defined Terms

20

 

 

 

ITEM 1A.

Risk Factors

21

 

 

 

ITEM 1B.

Unresolved Staff Comments

33

 

 

 

ITEM 3.

Legal Proceedings

34

 

 

 

ITEM 4.

Mine Safety Disclosures

34

 

 

 

PART II

 

 

ITEM 5.

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

35

 

Market for Common Stock

35

 

Holders of Record

35

 

Dividends

35

 

Stockholder Return Performance Presentation

36

 

i


 

TABLE OF CONTENTS (continued)

 

 

Page

ITEM 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

37

 

Overview of Our Business

37

 

Management's Discussion and Analysis of Results of Operations

39

 

Management's Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources and Liquidity

49

 

Management's Discussion of Critical Accounting Estimates

55

 

 

 

ITEM 7A.

Quantitative and Qualitative Disclosures about Market Risk

60

 

Market Risk

60

 

Commodity Price Risk

61

 

Other Commodity Risk

61

 

Commodity Sensitivity Analysis

62

 

Counterparty Risk

62

 

Interest Rate Risk

62

 

 

 

ITEM 8.

Financial Statements and Supplementary Data

F-1

 

 

 

ITEM 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

64

 

 

 

ITEM 9A.

Controls and Procedures

64

 

 

 

ITEM 9B.

Other Information

64

 

 

 

PART III

 

 

 

 

 

ITEM 10.

Directors, Executive Officers and Corporate Governance

65

 

 

 

ITEM 11.

Executive Compensation

65

 

 

 

ITEM 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

65

 

 

 

ITEM 13.

Certain Relationships and Related Transactions, and Director Independence

65

 

 

 

ITEM 14.

Principal Accountant Fees and Services

65

 

 

 

PART IV

 

 

 

 

 

ITEM 15.

Exhibits and Financial Statement Schedules

66

 

 

 

SIGNATURES

 

69

 

ii


 

Disclosures Regarding Forward-Looking Statements

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”). These are statements, other than statements of historical fact, that give current expectations or forecasts of future events, including without limitation: drilling plans; planned wells; rig count; our 2022 capital budget; reserve estimates; expectations regarding future economic and market conditions and their effects on us; our financial and operational outlook and ability to fulfill that outlook; our financial position, balance sheet, liquidity and capital resources and the benefits thereof. These statements typically contain words such as “may,” “anticipates,” “believes,” “estimates,” “expects,” “plans,” “predicts,” “targets,” “projects,” “should,” “would” or similar words, indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

While we believe that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. For a description of known material factors that could cause our actual results to differ from those in the forward-looking statements, see other factors discussed in Item 1A. Risk Factors.

Actual results may vary significantly from those anticipated due to many factors, including:

conditions in the oil and gas industry, including supply and demand levels for natural gas, crude oil and natural gas liquids (“NGLs”) and the resulting impact on price;
the availability and volatility of securities, capital or credit markets and the cost of capital to fund our operation and business strategy;
accuracy and fluctuations in our reserves estimates due to regulations, reservoir performance or sustained low commodity prices;
lack of, or disruption in, access to pipelines or other transportation methods;
ability to develop existing reserves or acquire new reserves;
drilling and operating risks;
well production timing;
changes in political or economic conditions in our key operating market;
prices and availability of goods and services, including third-party infrastructure;
unforeseen hazards such as weather conditions, health pandemics, acts of war or terrorist acts;
electronic, cyber or physical security breaches;
changes in safety, health, environmental, tax and other regulations or requirements or initiatives including those addressing the impact of global climate change, air emissions or water management;
other geological, operating and economic considerations;
the ability and willingness of current or potential lenders, derivative contract counterparties, customers and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us; or
other factors discussed in Items 1 and 2. Business and Properties, Item 1A. Risk Factors, Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures about Market Risk and elsewhere in this report.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise except as required by law. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

 

 

iii


 

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

General

Range Resources Corporation, a Delaware corporation, is a Fort Worth, Texas-based independent natural gas, NGLs and oil company, engaged in the exploration, development and acquisition of natural gas and oil properties in the United States. Our principal area of operation is the Marcellus Shale in Pennsylvania. Our corporate offices are located at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102 (telephone (817) 870-2601). We also maintain field offices in our areas of operation. Our common stock is listed and trades on the New York Stock Exchange (the “NYSE”) under the ticker symbol “RRC.” Range Resources Corporation was incorporated in 1980. At December 31, 2021, we had 259.8 million shares outstanding. At year-end 2021, our proved reserves had the following characteristics:

17.8 Tcfe of proved reserves;
64% natural gas, 34% NGLs and 2% crude oil and condensate;
59% proved developed;
nearly 100% operated;
a reserve life index of approximately 22 years (based on fourth quarter 2021 production);
a pretax present value of $14.9 billion of future net cash flows, discounted at 10% per annum (“PV-10”(a)); and
a standardized after-tax measure of discounted future net cash flows of $12.5 billion.
(a)
PV-10 is considered a non-GAAP financial measure as defined by the U.S. Securities and Exchange Commission (the “SEC”). We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on prices and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and security analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the PV-10 amount is the discounted estimated future income tax of $2.4 billion at December 31, 2021. PV-10 for December 31, 2021 was determined using NYMEX benchmark prices of $3.60 per mcf for natural gas and $66.34 per bbl for oil.

Our estimated proved reserves increased 3% to 17.8 Tcfe at December 31, 2021 from 17.2 Tcfe at December 31, 2020. Reserve additions from extensions and discoveries were the result of a successful development program and completion optimizations that resulted in improved well performance. The 2021 reserve additions and higher prices were partially offset by 2021 production volumes of 777.5 Bcfe and 1.3 Tcfe of reserves reclassified to unproved because of previously planned wells not expected to be drilled within the original five-year development horizon. We believe these unproved reserves can be included in our future proved reserves as these locations are added back into our five-year development plan.

Highlights of our 2021 production were:

total production of 541.0 Bcf of natural gas, 36.4 Mmbbls of NGLs and 3.0 Mmbbls of crude oil and condensate;
average daily production of 2.13 Bcfe per day, a decrease of 5% from 2020 which reflects the impact of the divestiture of our North Louisiana properties in August 2020; and
excluding our North Louisiana properties from production in 2020, total production was approximately the same as the previous year.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1


 

Executive Summary for 2021

Because our production is approximately 70% natural gas, natural gas prices generally constitute the primary variable in our operating results. Over the last few years, New York Mercantile Exchange (“NYMEX”) natural gas prices have been volatile. Since the beginning of 2019, natural gas prices have been as low as $1.50 per Mmbtu and as high as $6.20 per Mmbtu. The prices we receive for all our products are largely based on current market prices which are beyond our control but are managed through diversity in our sales agreements combined with an active commodity price hedging program. We have focused on areas that are within our control. Currently, our focus is on enhancing cash flow through cost reductions and operational efficiencies, while strengthening our balance sheet, rather than expansion and growth. We prioritize free cash flow generation across a broad range of commodity products. To the extent commodity prices decline, we would intend to limit capital spending to at or below cash flow. During 2021, we:

issued $600.0 million aggregate principal amount of new 8.25% senior notes due 2029;
decreased total debt $165.3 million and increased cash on hand $214.0 million;
maintained our bank committed borrowing capacity at $2.4 billion;
spent approximately $10.6 million less than our initial 2021 capital budget of $425.0 million;
recognized an average realized price (excluding derivative settlements and third party transportation costs) increase of 110% from 2020;
recognized an average realized price (including derivative settlements and third party transportation costs) increase of 86% from 2020;
reduced direct operating expense by $16.9 million, a reduction of 18% from 2020 reflecting the divestiture of higher operating cost properties;
reduced our depletion, depreciation and amortization rate per mcfe 2% from 2020;
increased our estimates of proved reserves at December 31, 2021 to 17.8 Tcfe from 17.2 Tcfe at December 31, 2020 which includes 1.6 Tcfe of drilling additions;
held our drilling and completion costs to at or below $600 per foot;
published our second formal corporate sustainability report which discusses our continued focus and commitment to the environment and the communities where we work and expanded our strategic goal of net zero greenhouse gases ("GHG") emissions by year-end 2025 to include both Scope 1 and Scope 2;
committed to a pilot certification program for responsibly sourced natural gas;
continued with our innovative water recycling program;
continued utilizing an electric hydraulic fracturing fleet; and
achieved a 40% reduction in employee recordable incident rates compared to 2020.

Available Information

Our corporate website is available at http://www.rangeresources.com. Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing we make with the SEC. We make available, free of charge, on our website, the annual report on Form 10-K, our proxy statement, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after filing such reports with the SEC. Other information such as presentations, our corporate sustainability report, our Corporate Governance Guidelines, the charters of each board committee and the Code of Business Conduct and Ethics are available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including our President and Chief Executive Officer and Chief Financial Officer.

The SEC maintains an internet website that contains reports, proxy and information statements and other information regarding issuers, including Range, that file electronically with the SEC. The public can obtain any document we file with the SEC at http://www.sec.gov.

Our Business Strategy

Our overarching business objective is to build stockholder value through returns focused development of natural gas properties. Our strategy to achieve our business objective is to generate consistent cash flow from reserves and production through internally generated drilling projects coupled with occasional acquisitions and divestitures of non-core, or at times, core assets. In addition, we target funding our capital spending to at or below operating cash flow. Our strategy requires us to make significant investments and financial commitments in technical staff, acreage, seismic data, drilling and completion technology and gathering and transportation arrangements to build drilling inventory and market our products. Our strategy has the following key elements:

commitment to environmental protection and worker and community safety;

2


 

concentrate in our core operating area;
focus on cost efficiency;
maintain a high-quality multi-year drilling inventory;
maintain a long-life reserve base with a low base decline rate;
market our products to a large number of customers in diverse markets under a variety of commercial terms;
maintain operational and financial flexibility; and
provide employee equity ownership and incentive compensation aligned with our stakeholders’ interests.

These elements are anchored by our interests in the Marcellus Shale located in Pennsylvania which is anticipated to have remaining productive life in excess of 50 years.

Commit to Environmental Protection and Worker and Community Safety. We strive to implement technologies and commercial practices to minimize potential adverse impacts from the development of our properties on the environment, worker health and safety and the safety of the communities where we operate. We analyze and review performance while striving for continual improvement by working with peer companies, regulators, non-governmental organizations, industries not related to the oil and natural gas industry and other engaged stakeholders. We expect every employee to maintain safe operations, minimize environmental impact and conduct their daily business with the highest ethical standards.

Concentrate in Our Core Operating Area. We currently operate in one region: Pennsylvania. Concentrating our drilling and producing activities allows us to develop the regional expertise needed to interpret specific geological and operating conditions and develop economies of scale. Operating in our core area also allows us to pursue our goal of consistent production at attractive returns. We intend to further develop our acreage and improve our operating and financial results through the use of technology and detailed analysis of our properties. We periodically evaluate and pursue acquisition opportunities (including opportunities to acquire particular natural gas and oil properties or entities owning natural gas and oil assets) and at any given time we may be in various stages of evaluating such opportunities.

Focus on Cost Efficiency. We concentrate in areas which we believe to have sizable hydrocarbon deposits in place that will allow economic production while controlling costs. Because there is little long-term competitive sales price advantage available to a commodity producer, the costs to find, develop, and produce a commodity are important to organizational sustainability and long-term stockholder value creation. We endeavor to control costs such that our cost to find, develop and produce natural gas, NGLs and oil is one of the lowest in the industry. We operate almost all of our total net production and believe that our extensive knowledge of the geologic and operating conditions in the areas where we operate provides us with the ability to achieve operational efficiencies.

Maintain a High-Quality Multi-Year Drilling Inventory. We focus on areas with multiple prospective and productive horizons and development opportunities. We use our technical expertise to build and maintain a multi-year drilling inventory. We believe that a large, high-quality multi-year inventory of drilling projects increases our ability to efficiently plan for economic production. Currently, we have over 3,400 proven and unproven drilling locations in inventory.

Maintain a Long-Life Reserve Base with a Low Base Decline Rate. Long-life natural gas and oil reserves provide a more stable platform than short-life reserves. Long-life reserves reduce reinvestment risk as they lessen the amount of reinvestment capital deployed each year to replace production. Long-life natural gas and oil reserves also assist us in minimizing costs as stable production makes it easier to build and maintain operating economies of scale. Long-life reserves also offer upside from technology enhancements.

Market Our Products to a Large Number of Customers in Diverse Markets Under a Variety of Commercial Terms. We market our natural gas, NGLs, crude oil and condensate to a large number of customers in both domestic and international markets to maximize cash flow and diversify risk. We hold numerous firm transportation contracts on multiple pipelines to enable us to transport and sell natural gas and NGLs in the Midwest, Gulf Coast, Southeast, Northeast and international markets. We sell our products under a variety of price indexes and price formulas that assist us in optimizing regional price differentials and commodity price volatility.

Maintain Operational and Financial Flexibility. Because of the risks involved in drilling, coupled with changing commodity prices, we are flexible and adjust our capital budget throughout the year. If certain areas generate higher than anticipated returns, we may accelerate development in those areas and decrease expenditures elsewhere. We also believe in maintaining ample liquidity, using commodity derivatives to help stabilize our realized prices and focusing on financial discipline. We believe this provides more predictable cash flows and financial results. We regularly review our asset base to identify nonstrategic assets, the disposition of which is expected to increase capital resources available for other activities and create organizational and operational efficiencies.

Provide Employee Equity Ownership and Incentive Compensation Aligned with Our Stakeholders’ Interest. We want our employees to think and act like business owners. To achieve this, we reward and encourage them through equity ownership in Range. All full-time employees are eligible to receive equity grants. As of December 31, 2021, our employees and directors owned equity

3


 

securities in our benefit plans (vested and unvested) that had an aggregate market value of approximately $263.0 million. We seek to align our incentive compensation with stakeholders’ interests and key business objectives and members of our board of directors annually engage with stockholders to discuss our incentive compensation framework.

Significant Accomplishments in 2021

Proved reserves – Total proved reserves increased 3% in 2021 compared to 2020, from 17.2 Tcfe to 17.8 Tcfe. This achievement is the result of existing quality production and efficient development. We believe the quality of our technical teams and our substantial inventory of high quality Marcellus Shale drilling locations provide the basis for future proved reserves and production.
Production – In 2021, our production averaged 2.13 Bcfe per day, a decrease of 5% from 2020 reflecting the impact of the sale of our North Louisiana properties. Excluding production from these North Louisiana properties in 2020, our production was approximately the same when compared to 2020. Our capital program is designed to allocate investments based on projects that maximize returns while minimizing controllable costs associated with production activities. We intend to continue our disciplined investment in our Marcellus Shale assets.
Focus on financial flexibility – As of December 31, 2021, we maintained a $4.0 billion bank credit facility, with a borrowing base of $3.0 billion and committed borrowing capacity of $2.4 billion. We endeavor to maintain a strong liquidity position. In 2021, we reduced our aggregate principal amount of debt by $165.3 million. We ended 2021 with strong liquidity resulting from $214.4 million of cash and $2.1 billion available under the credit facility. Also, in early January 2022, we issued $500.0 million of new 4.75% senior notes due 2030; with the proceeds from this issuance, cash on hand and borrowings under our credit facility, we redeemed our 9.25% senior notes due 2026 in February 2022. Our 2021 capital budget, which was established at the beginning of the year, was originally $425.0 million with actual spending for 2021 approximately $10.6 million lower. As we have done historically, we may adjust our capital program, divest assets and use derivatives to protect a portion of our future cash flow from commodity price volatility to reduce the risk of returns on investment and maintain ample liquidity.
Successful drilling program – In 2021, we drilled 59 gross natural gas wells and our overall drilling success rate was 100%. We continue to maintain and optimize a sufficient inventory of drilled lateral footage which is critical to our ability to consistently sustain production each year on a cost effective and efficient basis. Controlling the costs to find, develop and produce natural gas, NGLs and oil is critical in creating long-term stockholder value. Our focus areas are characterized by large, contiguous acreage positions and multiple stacked geologic horizons. In 2021, we continued to reduce average well costs per foot drilled through faster drilling times, longer laterals and innovative completion optimizations.
Focus on safe, responsible and sustainable operations – We believe we are on track to achieve our goal of net zero GHG emissions by year-end 2025, now expanded to include Scope 1 and Scope 2 emissions. During the year, we committed to a pilot program seeking to certify our natural gas as responsibly sourced. We continued to recycle approximately 100% of produced water and our non-fresh water spill rate was reduced 48% when compared to 2020. We also saw a 29% reduction in our notices of violations.

Segment and Geographical Information

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 track only basic operational data by area. We measure financial performance as a single enterprise and not on an area-by-area basis. Our exploration and production operations are limited to onshore United States.

Outlook for 2022

For 2022, we expect our capital budget to be in the range of $460.0 million to $480.0 million for natural gas, NGLs, crude oil and condensate related activities, excluding proved property acquisitions, for which we do not budget. This budget includes $425.0 million to $445.0 million for drilling costs and $35.0 million for acreage and other expenditures and is expected to achieve 2022 production similar to 2021 production volumes. As has been our historical practice, we will periodically review our capital expenditures throughout the year and may adjust the budget based on commodity prices, drilling success and other factors. Throughout the year, we allocate capital on a project-by-project basis. Our expectation for 2022 is for our capital expenditure program to be funded within operating cash flows. However, in the event our 2022 capital requirements exceed our internally generated cash flow, we may reduce the capital budget, draw on our bank credit facility and/or debt or equity financing may be used to fund these requirements. The prices we receive for our natural gas, NGLs and oil production are largely based on current market prices, which are beyond our control. The price risk on a portion of our forecasted natural gas, NGLs and oil production for 2022 is mitigated using commodity derivative contracts and we intend to continue to enter into these transactions.

4


 

Our primary near-term focus includes the following:

Operate safely and efficiently;
target limiting capital spending at or below cash flow;
reduce direct emissions and target net-zero Scope 1 and Scope 2 GHG emissions by year-end 2025;
achieve competitive returns on investments;
preserve liquidity and improve financial strength;
focus on organic opportunities through disciplined capital investments;
improve operational efficiencies and economic returns;
attract and retain quality employees; and
align employee incentives with our stockholders’ interests and key business objectives.

Proved Reserves

The following table sets forth our estimated proved reserves for years ended 2021, 2020 and 2019 based on the average of prices on the first day of each month of the given calendar year, in accordance with SEC rules. Oil includes both crude oil and condensate. We have no natural gas, NGLs or oil reserves from non-traditional sources. Additionally, we do not provide optional disclosures of probable or possible reserves.

 

 

 

Summary of Oil and Gas Reserves as of Year-End Based on Average Prices

 

Reserve Category

 

Natural Gas
(Mmcf)

 

 

NGLs
(Mbbls)

 

 

Oil
(Mbbls)

 

 

Total
(Mmcfe)
(a)

 

 

%

 

2021:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

 

6,809,849

 

 

 

577,507

 

 

 

23,834

 

 

 

10,417,887

 

 

 

59

%

Undeveloped

 

 

4,642,232

 

 

 

423,798

 

 

 

28,762

 

 

 

7,357,597

 

 

 

41

%

Total Proved

 

 

11,452,081

 

 

 

1,001,305

 

 

 

52,596

 

 

 

17,775,484

 

 

 

100

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2020:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

 

6,350,057

 

 

 

550,771

 

 

 

22,976

 

 

 

9,792,540

 

 

 

57

%

Undeveloped

 

 

4,798,503

 

 

 

400,695

 

 

 

34,650

 

 

 

7,410,574

 

 

 

43

%

Total Proved

 

 

11,148,560

 

 

 

951,466

 

 

 

57,626

 

 

 

17,203,114

 

 

 

100

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2019:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

 

6,486,211

 

 

 

535,007

 

 

 

34,369

 

 

 

9,902,468

 

 

 

54

%

Undeveloped

 

 

5,628,766

 

 

 

403,229

 

 

 

40,163

 

 

 

8,289,115

 

 

 

46

%

Total Proved

 

 

12,114,977

 

 

 

938,236

 

 

 

74,532

 

 

 

18,191,583

 

 

 

100

%

 

(a)

Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

 

Reserve Estimation

All reserve information in this report is based on estimates prepared by our petroleum engineering staff and is the responsibility of management. We have established internal controls over our reserves estimation process and procedures to support the accurate and timely preparation and disclosure of reserve estimates in accordance with SEC requirements. We also had Netherland, Sewell & Associates, Inc., an independent petroleum consultant, conduct an audit of our year-end 2021 reserves. The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserve estimates. This engineering firm was selected for its geographic expertise and its historical experience in engineering certain properties. The proved reserve audits performed for 2021, 2020 and 2019, in the aggregate, represented 97%, 97% and 90% of our proved reserves. The reserve audits performed for 2021, 2020 and 2019, in the aggregate represented 97%, 99% and 94% of our 2021, 2020 and 2019 associated pretax present value of proved reserves discounted at ten percent. A copy of the summary reserve report prepared by our independent petroleum consultant is included as an exhibit to this Annual Report on Form 10-K. The technical person at our independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meets the requirements regarding qualifications, independence, objectivity and confidentiality as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience

5


 

professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of data furnished during the reserve audit process. Throughout the year, our technical team meets periodically with representatives of our independent petroleum consultant to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserve estimation process, our senior management reviews and approves significant changes to our proved reserves. We provide historical information to our consultant for our largest producing properties such as ownership interest, natural gas, NGLs and oil production, well test data, commodity prices and operating and development costs. Our consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering and Economics. In some cases, additional meetings are held to review identified reserve differences. Our reserve auditor estimates of proved reserves and the pretax present value of such reserves discounted at 10% did not differ from our estimates by more than 10% in the aggregate. However, when compared on a lease-by-lease, field-by-field or area-by-area, some of our estimates may be greater and some may be less than the estimates of the reserve auditor. When such differences do not exceed 10% in the aggregate, our reserve auditor is satisfied that the proved reserves and pretax present value of such reserves discounted at 10% are reasonable and will issue an unqualified opinion. Remaining differences, if any, are not resolved due to the limited cost benefit of continuing such analysis.

Historical variances between our reserve estimates and the aggregate estimates of our independent petroleum consultants have been less than 5%. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, Mr. Alan Farquharson, who reports directly to our President and Chief Executive Officer. Our Senior Vice President of Reservoir Engineering and Economics holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources and has more than forty years of engineering experience in the oil and gas industry. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions. During the year ended December 31, 2021, we did not file any reports with any federal authority or agency with respect to our estimate of natural gas and oil reserves.

Reserve Technologies

Proved reserves are those quantities of natural gas, NGLs and oil that 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. The term “reasonable certainty” implies a high degree of confidence that the quantities of natural gas, NGLs and oil actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal technical staff employs technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, empirical evidence through drilling results and well performance, decline curve analysis, well logs, geologic maps and available downhole and production data, seismic data, well test data, reservoir simulation modeling and implementation and application of enhanced data analytics.

Proved undeveloped reserves (or “PUDs”) include reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a major expenditure is required for completion. PUD reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic production. Undrilled locations may be classified as having PUD reserves only if an ability and intent has been established to drill the reserves within five years, unless specific circumstances justify a longer time period.

Reporting of Natural Gas Liquids

We produce NGLs as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2021, NGLs represented approximately 34% of our total proved reserves on an mcf equivalent basis. NGLs are products priced by the gallon (and sold by the barrel) to our customers. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels. Prices for a barrel of NGLs in 2021 averaged approximately 52% of the average price for equivalent volumes of oil. We report all production information related to natural gas net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs. We currently include ethane in our proved reserves which match volumes to be delivered under our existing long-term, extendable ethane contracts.

6


 

Proved Undeveloped Reserves

As of December 31, 2021, our PUDs totaled 28.8 Mmbbls of crude oil, 423.8 Mmbbls of NGLs and 4.6 Tcf of natural gas, for a total of 7.4 Tcfe. Costs incurred in 2021 relating to the development of PUDs were approximately $361.3 million. All PUD drilling locations are scheduled to be drilled prior to the end of 2026. As of December 31, 2021, we have 21 Bcfe of reserves that have been reported for more than five years from their original booking date, which is in the process of being drilled and completed and expected to turn to sales in 2022. Changes in PUDs that occurred during the year were due to:

conversion of approximately 1.2 Tcfe of PUDs into proved developed reserves;
addition of 1.5 Tcfe new PUDs from drilling; and
393.6 Bcfe net negative revision with 1.3 Tcfe of reserves reclassified to unproved because of previously planned wells not expected to be drilled within the original five-year development horizon partially offset by positive performance revisions of 929.4 Bcfe.

For an additional description of changes in PUDs for 2021, see Note 17 to our consolidated financial statements. We believe our PUDs reclassified to unproved can be included in our future proved reserves as these locations are added back into our five-year development plan.

Proved Reserves (PV-10)

The following table sets forth the estimated future net cash flows, excluding open derivative contracts, from proved reserves, the present value of those net cash flows discounted at a rate of 10% (PV-10), and the expected benchmark prices and average field prices used in projecting net cash flows over the past five years. Our reserve estimates do not include any probable or possible reserves (in millions, except prices):

 

 

2021

 

 

2020

 

 

2019

 

 

2018

 

 

2017

 

Future net cash flows

 

$

39,919

 

 

$

9,795

 

 

$

22,179

 

 

$

34,836

 

 

$

21,469

 

Present value:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Before income tax

 

 

14,868

 

 

 

2,981

 

 

 

7,561

 

 

 

13,173

 

 

 

8,147

 

After income tax (Standardized Measure)

 

 

12,485

 

 

 

2,846

 

 

 

6,629

 

 

 

11,116

 

 

 

7,165

 

Benchmark prices (NYMEX):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas price (per mcf)

 

 

3.60

 

 

 

1.98

 

 

 

2.58

 

 

 

3.10

 

 

 

2.98

 

Oil price (per bbl)

 

 

66.34

 

 

 

39.77

 

 

 

55.73

 

 

 

65.55

 

 

 

51.19

 

Wellhead prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas price (per mcf)

 

 

3.30

 

 

 

1.68

 

 

 

2.38

 

 

 

2.98

 

 

 

2.60

 

Oil price (per bbl)

 

 

59.35

 

 

 

30.13

 

 

 

49.24

 

 

 

59.96

 

 

 

45.73

 

NGLs price (per bbl)

 

 

28.41

 

 

 

16.14

 

 

 

17.32

 

 

 

25.22

 

 

 

17.84

 

 

 

Future net cash flows represent projected revenues from the sale of proved reserves, net of production and development costs (including transportation and gathering expenses, operating expenses and production taxes). Revenues are based on a twelve-month unweighted average of the first day of the month pricing, without escalation. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current economic conditions at each year-end. There can be no assurance that the proved reserves will be produced in the future or that prices, production or development costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.

Property Overview

Currently, our natural gas and oil operations are concentrated in the Appalachian region of the United States, and more specifically, in the Marcellus Shale in Pennsylvania. Our properties consist of interests in developed and undeveloped natural gas and oil leases. These interests entitle us to drill for and produce natural gas, NGLs, crude oil and condensate from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, royalty and overriding royalty interests.

7


 

We hold a large portfolio of drilling opportunities beyond the five-year horizon of proved reserves and therefore a significant unbooked resource potential within the Marcellus, Utica and Upper Devonian formations. We own 1,350 net producing wells, almost all of which we operate. Our average working interest in this region is 94%. As of December 31, 2021 we have approximately 909,000 gross (794,000 net) acres under lease. During 2021, we had approximately three drilling rigs in the field and expect to run an average of three drilling rigs throughout 2022.

 

The following table sets forth annual production volumes, average sales prices and production cost data for our wells in the Marcellus Shale play which, in 2019 and 2020, was the only field in which our reserves were greater than 15% of our total proved reserves. For the year ended December 31, 2021, substantially all of our reserves are located in the Marcellus Shale.

 

 

 

Marcellus Shale

 

 

 

2021

 

 

2020

 

 

2019

 

Production:

 

 

 

 

 

 

 

 

 

Natural gas (Mmcf)

 

 

540,824

 

 

 

544,079

 

 

 

516,031

 

NGLs (Mbbls)

 

 

36,365

 

 

 

36,185

 

 

 

36,013

 

Crude oil and condensate (Mbbls)

 

 

3,032

 

 

 

2,599

 

 

 

3,199

 

Total Mmcfe (a)

 

 

777,205

 

 

 

776,786

 

 

 

751,299

 

Sales Prices: (b)

 

 

 

 

 

 

 

 

 

Natural gas (per mcf)

 

$

2.29

 

 

$

0.49

 

 

$

1.13

 

NGLs (per bbl)

 

 

17.12

 

 

 

4.91

 

 

 

7.12

 

Crude oil and condensate (per bbl)

 

 

59.76

 

 

 

29.24

 

 

 

49.73

 

Total (per mcfe) (a)

 

 

2.62

 

 

 

0.67

 

 

 

1.33

 

Production Costs:

 

 

 

 

 

 

 

 

 

Lease operating (per mcfe)

 

$

0.10

 

 

$

0.10

 

 

$

0.11

 

Production and ad valorem tax (per mcfe) (c)

 

 

0.04

 

 

 

0.02

 

 

 

0.03

 

 

(a)

Oil and NGLs volumes are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

(b)

We do not record derivatives or the results of derivatives at the field level. Includes deductions for third-party transportation, gathering and compression expense.

(c)

Includes Pennsylvania impact fee.

Reserves at December 31, 2021 were 17.8 Tcfe, an increase of 572.4 Bcfe, or 3%, from 2020. Drilling additions of 1.6 Tcfe, favorable pricing revisions of 22.6 Bcfe and positive performance revisions of 1.0 Tcfe were partially offset by production of 777.2 Bcfe and downward revisions for proved undeveloped reserves deferred beyond our current five-year development plan of 1.3 Tcfe. Annual production was the same as production in 2020. During 2021, we spent $388.1 million in this region to drill 58 (57.1 net) development wells and 1 (1.0 net) exploratory well, all of which were productive. At December 31, 2021, we had an inventory of over 3,400 proven and unproven drilling locations. During the year, we drilled 59 proven locations in the Appalachian region, added 140 new proven drilling locations and deleted 82 proven drilling locations with deleted reserves reclassified to unproved due to lower future capital spending, improved well performance and the impact of the five year rule on wells not to be drilled within the original development horizon. During the year, we achieved a 100% drilling success rate.

Divestitures

Over the last three years, we have divested over $1.0 billion of assets in order to increase capital resources available for other activities, reduce our unit cost structure, create organizational and operating efficiencies and increase financial flexibility. See Note 3 to our consolidated financial statements for more detail on our divestitures.

Producing Wells

The following table sets forth information relating to productive wells at December 31, 2021. If we own both a royalty and a working interest in a well, such interest is included in the table below. Wells are classified as natural gas or crude oil according to their predominant production stream. We do not have a significant number of dual completions.

 

 

 

 

 

 

 

 

 

Average

 

 

 

Total Wells

 

 

Working

 

 

 

Gross

 

 

Net

 

 

Interest

 

Natural gas

 

 

1,430

 

 

 

1,349

 

 

 

94

%

Crude oil

 

 

3

 

 

 

1

 

 

 

34

%

Total

 

 

1,433

 

 

 

1,350

 

 

 

94

%

 

Production wells are producing wells and wells mechanically capable of production. The day-to-day operations of natural gas and oil properties are the responsibility of the operator designated under pooling or operating agreements. The operator supervises

8


 

production, maintains production records, employs or contracts for field personnel and performs other functions. An operator receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged by unaffiliated third parties. The charges customarily vary with the depth and location of the well being operated.

Drilling Activity

The following table summarizes drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. This information should not be indicative of future performance nor should it be assumed that there was any correlation between the number of productive wells and the natural gas and oil reserves generated thereby. As of December 31, 2021, we had 33 gross (33 net) wells in the process of drilling or active completions stage. In addition, there were 22 gross (21 net) wells waiting on completion or waiting on pipelines at year-end 2021.

 

 

 

2021

 

 

2020

 

 

2019

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

58.0

 

 

 

57.1

 

 

 

52.0

 

 

 

51.4

 

 

 

94.0

 

 

 

92.6

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

1.0

 

 

 

1.0

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

59.0

 

 

 

58.1

 

 

 

52.0

 

 

 

51.4

 

 

 

94.0

 

 

 

92.6

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total