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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, 2019

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 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, 2019 was $1,733,839,000. 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 25, 2020, there were 254,715,325 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 2020 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

2

 

 

2019 Executive Summary

2

 

 

General

2

 

 

Available Information

3

 

 

Our Business Strategy

3

 

 

Significant Accomplishments in 2019

4

 

 

Industry Operating Environment

5

 

 

Segment and Geographical Information

6

 

 

Outlook for 2020

6

 

 

Production, Price and Cost History

7

 

 

Proved Reserves

8

 

 

Property Overview

10

 

 

Divestitures

12

 

 

Producing Wells

13

 

 

Drilling Activity

13

 

 

Gross and Net Acreage

14

 

 

Undeveloped Acreage Expirations

14

 

 

Title to Properties

14

 

 

Delivery Commitments

15

 

 

Employees

15

 

 

Competition

16

 

 

Marketing and Customers

16

 

 

Seasonal Nature of Business

16

 

 

Markets

17

 

 

Governmental Regulation

17

 

 

Environmental and Occupational Health and Safety Matters

19

 

 

Glossary of Certain Defined Terms

24

 

 

 

 

ITEM 1A.

 

Risk Factors

26

 

ITEM 1B.

 

Unresolved Staff Comments

43

 

ITEM 3.

 

Legal Proceedings

44

 

ITEM 4.

 

Mine Safety Disclosures

44

 

PART II

 

 

ITEM 5.

 

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

45

 

 

Market for Common Stock

45

 

 

Holders of Record

45

 

 

Dividends

45

 

 

Stockholder Return Performance Presentation

46

 

ITEM 6.

 

Selected Financial Data and Proved Reserve Data

47

i


 

 

TABLE OF CONTENTS (continued)

 

 

 

Page

 

ITEM 7.

 

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

48

 

 

Overview of Our Business

48

 

 

Sources of Our Revenues

49

 

 

Principal Components of Our Cost Structure

49

 

 

Management’s Discussion and Analysis of Results of Operations

50

 

 

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

60

 

 

Management’s Discussion of Critical Accounting Estimates

65

 

ITEM 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

70

 

 

Market Risk

70

 

 

Commodity Price Risk

71

 

 

Other Commodity Risk

71

 

 

Commodity Sensitivity Analysis

72

 

 

Interest Rate Risk

72

 

ITEM 8.

 

Financial Statements and Supplementary Data

F-1

 

ITEM 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

74

 

ITEM 9A.

 

Controls and Procedures

74

 

ITEM 9B.

 

Other Information

74

 

PART III

 

 

ITEM 10.

 

Directors, Executive Officers and Corporate Governance

75

 

ITEM 11.

 

Executive Compensation

75

 

ITEM 12.

 

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

75

 

ITEM 13.

 

Certain Relationships and Related Transactions, and Director Independence

75

 

ITEM 14.

 

Principal Accountant Fees and Services

75

 

PART IV

 

 

ITEM 15.

 

Exhibits and Financial Statement Schedules

76

 

 

 

 

SIGNATURES

79

 

 

 

 

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 2020 capital budget and the planned allocation thereof; 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;

 

 

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 markets;

 

 

prices and availability of goods and services, including third-party infrastructure;

 

 

unforeseen hazards such as weather conditions, acts of war or terrorist acts;

 

 

electronic, cyber or physical security breaches;

 

 

changes in safety, health, environmental, tax and other regulations;

 

 

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.

 

 

1


 

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, 2019, we had 251.4 million shares outstanding.

Our 2019 production had the following characteristics:

 

average total production of 2,283.2 Mmcfe per day, an increase of 4% from 2018;

 

69% natural gas;

 

total natural gas production of 578.1 Bcf, an increase of 5% from 2018;

 

total NGLs production of 38.9 Mmbbls (including ethane), an increase of 1% from 2018;

 

total crude oil and condensate production of 3.7 Mmbbls, a decrease of 13% from 2018; and

 

90% of our total production was from the Marcellus Shale play in Pennsylvania.

At year-end 2019, our proved reserves had the following characteristics:

 

18.2 Tcfe of proved reserves;

 

67% natural gas, 31% NGLs and 2% crude oil;

 

54% proved developed;

 

almost 100% operated;

 

95% of proved reserves are in the Marcellus Shale play in Pennsylvania;

 

a reserve life index of approximately 21 years (based on fourth quarter 2019 production);

 

a pretax present value of $7.6 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 $6.6 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 $932.3 million at December 31, 2019.

2019 Executive Summary

Since our production is 69% natural gas, natural gas prices generally constitute a primary variable in our operating results. Over the last few years, New York Mercantile Exchange (“NYMEX”) natural gas prices have been volatile, starting calendar year 2017 at $3.93 per mcf and falling to a low of $2.74 mcf in January 2018 then recovering to $4.72 per mcf at the end of 2018 only to again decrease to a low of $2.14 per mcf in August 2019. The prices we receive for all our products are largely based on current market prices which are beyond our control. In 2019, we continued to focus on areas that are within our control. Currently, our focus is on preservation of cash and liquidity, together with cost reductions and debt management, rather than expansion and growth. During 2019, we:

 

received asset sale proceeds of $784.9 million;

 

repurchased $201.6 million face value of our senior notes at a discount;

 

reduced borrowings on our bank credit facility by $466.0 million from December 2018;

 

increased our bank’s committed borrowing capacity from $2.0 billion to $2.4 billion;

 

spent 4% less than our initial 2019 capital budget of $756.0 million;

 

reduced 2019 general and administration expenses by $28.7 million, a reduction of 14% from 2018 reflecting our reductions in personnel and our efforts to reduce costs to enhance profitability and resilience;

2


 

 

increased proved reserves at December 31, 2019 to 18.2 Tcfe from 18.1 Tcfe at December 31, 2018, despite asset sales, which represents a 139% replacement of 2019 annual production;

 

published our first formal corporate sustainability report;

 

continued with our innovative water recycling program;

 

successfully tested and began utilizing an electric frac fleet;

 

reduced emissions in 2019 compared to 2018 and increased the frequency of leak detection inspections;

 

30% reduction in contractor OSHA recordable injuries and 50% decrease in severity of employee injuries versus 2018; and

 

15% reduction in number of preventable vehicle incidents.

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, 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 responsibility culture, our Corporate Governance Guidelines, the charters of the Audit Committee, the Compensation Committee, the Dividend Committee, the Governance and Nominating 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 and oil properties, measured on a per share debt-adjusted basis. 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:

 

commit to environmental protection and worker and community safety;

 

concentrate in our core operating area;

 

focus on cost efficiency;

 

maintain a 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 different markets under a variety of commercial terms;

 

maintain operational and financial flexibility; and

 

provide employee equity ownership and incentive compensation.

These elements are primarily anchored by our interests in the Marcellus Shale located in Pennsylvania which has a remaining productive life in excess of 50 years. Underlying this interest is 95% of our total proved reserves as of December 31, 2019. In addition, we have natural gas, crude oil and condensate and NGLs production activities in the Lower Cotton Valley in North Louisiana.

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.

3


 

Concentrate in Core Operating Areas. We currently operate in two regions:  Pennsylvania and North Louisiana. 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 areas 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 in the United States (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 sizeable 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 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, multi-year inventory of drilling projects increases our ability to efficiently plan for economic production. Currently, we have over 3,000 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 Different 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. 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, 2019, our employees and directors owned equity securities in our benefit plans (vested and unvested) that had an aggregate market value of approximately $45.9 million.

Significant Accomplishments in 2019

 

Proved reserves – Total proved reserves increased 1% in 2019, from 18.1 Tcfe to 18.2 Tcfe, despite asset sales during the year. This achievement is the result of existing quality production and efficient development. The Marcellus Shale is our largest producing region and contains our greatest concentration of reserves. We believe the quality of our technical teams and our substantial inventory of high quality drilling locations provide the basis for future proved reserves and production.

 

 

Production – In 2019, our production averaged 2,283.2 Mmcfe per day, an increase of 4% from 2018. Drilling in the Marcellus Shale play in Pennsylvania drove our production. Our capital program is designed to allocate investments based on projects that maximize returns while minimizing controllable costs associated with production activities.

 

 

Focus on financial flexibility – As of December 31, 2019, 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 2019, we reduced our total debt $667.6 million. Our 2019 capital budget, which was established at the beginning of the year, was $756.0 million with actual spending for 2019 approximately 4% lower. As we have done historically, we may adjust our capital program, divest of assets and use derivatives to

 

4


 

 

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 2019, we drilled 94 gross natural gas and oil wells. We replaced 139% of our production through drilling in 2019 and our overall drilling success rate was 100%. We continue to maintain and optimize our drilling inventory 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 2019, we continued to reduce average well costs per foot drilled through faster drilling times, longer laterals and innovative completion optimizations.

 

 

Large resource potential – Maintaining an exposure to large low-cost potential resources is important. We maintained and continued to develop our shale plays in 2019. We have three large unconventional and prospective plays in Pennsylvania: the Marcellus, Utica and Upper Devonian shales. These plays cover expansive areas, provide multi-year drilling opportunities, are in many cases stacked pay and, collectively, have sustainable lower risk profiles.  

 

 

Dispositions completed – In third quarter 2019, we sold, in three separate transactions, a proportionately reduced 2.5% overriding royalty primarily covering our Washington County, Pennsylvania leases for gross proceeds of $750.0 million and we recorded a loss of $36.5 million, which represents closing adjustments and transaction fees. In second quarter 2019, we sold natural gas and oil property, primarily representing 20,000 unproved acres, for proceeds of $34.0 million and we recognized a gain of $5.9 million.

 

Industry Operating Environment

We operate entirely within the continental United States. The oil and natural gas industry is affected by many factors that we cannot control. Government regulations, particularly in the areas of taxation, energy, climate change and the environment, can have a significant impact on our operations and profitability. The impact of these factors is difficult to accurately predict or anticipate. It is difficult for us to predict the occurrence of events that may affect commodity prices or the degree to which these prices will be affected; however, the prices we receive for the commodities we produce will generally approximate current market prices in the geographic region of the production, not including the impact of our derivative program.

Significant factors that are likely to affect 2020 commodity prices include: the impact of U.S. production growth, the effect of new policies enacted by the U.S. government, fiscal challenges facing the United States federal government, expected economic growth in the U.S. and throughout the world, forecasted increased demand from Asian and European markets, supply and demand fundamentals for NGLs in the United States and the pace at which export capacity grows and the pace that natural gas storage is refilled during the year.

Natural gas prices are primarily determined by North American supply and demand and natural gas exports and are heavily influenced by weather and storage levels. The NYMEX monthly settlement prices for natural gas averaged $2.62 per mcf in 2019, with a high of $3.64 per mcf in January and a low of $2.14 per mcf in August. In 2018, monthly NYMEX settlement prices averaged $3.07 per mcf. Since the end of 2019, natural gas prices have decreased, with the monthly settlement price for natural gas decreasing from $2.47 per mcf in December 2019 to $1.88 per mcf in February 2020. Natural gas prices have come under pressure largely due to an abundant supply of natural gas caused by the high productivity of shale plays in the United States which could continue to outpace demand. While the industry has invested in initiatives designed to increase takeaway capacity, the supply has increased at a faster pace than demand. Natural gas prices are expected to remain volatile in 2020.

Significant factors that are likely to impact 2020 crude oil prices include worldwide economic conditions, the rate of production growth in the United States, political and economic developments in the Middle East, Africa and South America, demand in Asian and European markets and the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations choose to manage oil supply through export quotas. NYMEX monthly settlement prices for oil averaged $57.21 per barrel in 2019, with a high of $63.87 per barrel in April and a low of $51.55 per barrel in January. In 2018, NYMEX monthly settlement prices for oil averaged $65.49 per barrel. Since the end of 2019, crude oil prices have declined, with the monthly settlement price for crude oil decreasing from $59.81 per barrel in December 2019 to $57.53 per barrel in January 2020. The likelihood of a sustained recovery in worldwide demand for energy is difficult to predict. As a result, we expect crude oil commodity prices will continue to be volatile in 2020.

NGLs prices are determined by North American supply and demand, and increasingly by international supply and demand. The growth of unconventional drilling has substantially increased the supply of NGLs and caused a significant decline in NGLs component prices. Additional export facilities have been built and NGLs exports are increasing along with the expansion of ethane cracking capacity. The supply of NGLs products is expected to increase during 2020 and prices are expected to remain volatile.

5


 

Natural gas, NGLs and oil prices affect:

 

our revenues, profitability and cash flow;

 

the quantity of natural gas, NGLs and oil that we can economically produce;

 

the quantity of natural gas, NGLs and oil shown as proved reserves;

 

the amount of cash flow available to us for capital expenditures; and

 

our ability to borrow and raise additional capital.

Continued or extended decline in natural gas, NGLs and oil prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we currently, and may in the future, use derivative instruments to hedge future sales prices on our natural gas, NGLs, crude oil and condensate production. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements while also partially protecting us from declining price movements.

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 do not maintain complete separate financial statement information 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 2020

For 2020, we have established a $520.0 million capital budget for natural gas, NGLs, crude oil and condensate related activities, excluding proved property acquisitions, for which we do not budget. This budget is 98% allocated to our Appalachian division and includes $490.0 million for drilling costs, $26.0 million for acreage, $1.0 million for pipelines and facilities and $3.0 million for other expenditures. 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 2020 is for our capital expenditure program to be funded within operating cash flows and, if required, with borrowings under our bank credit facility. To the extent our 2020 capital requirements might exceed our internally generated cash flow, we may reduce the capital budget or use proceeds from asset sales, draw on our committed capacity under 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 2020 is mitigated using commodity derivative contracts and we intend to continue to enter into these transactions.

Our primary near-term focus includes the following:

 

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;

 

target limiting capital spending to at or below cash flow; and

 

attract and retain quality employees whose efforts and incentives are aligned with stockholders’ interests.

6


 

Production, Price and Cost History

The following table sets forth information regarding natural gas, NGLs and oil production, realized prices and production costs for the last three years. The price we receive is largely a function of market supply and demand. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. For more information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Year Ended December 31,

 

 

2019

 

  

2018

 

  

2017

 

Production

 

 

 

  

 

 

 

  

 

 

 

Natural gas (Mmcf)

 

578,114

 

  

 

548,085

  

  

 

490,253

  

Natural gas liquids (Mbbls)

 

38,850

 

  

 

38,325

  

  

 

35,709

  

Crude oil and condensate (Mbbls)

 

3,690

 

  

 

4,228

  

  

 

4,787

  

Total (Mmcfe) (a)

 

833,354

 

  

 

803,408

  

  

 

733,231

  

Average sales prices (excluding derivative settlements)

 

 

 

  

 

 

 

  

 

 

 

Natural gas (per mcf)

$

2.40

  

  

$

3.04

  

  

$

2.75

  

Natural gas liquids (per bbl)

 

17.53

 

  

 

24.30

  

  

 

16.93

  

Crude oil and condensate (per bbl)

 

50.26

 

  

 

60.52

  

  

 

46.30

  

Total (per mcfe) (a)

 

2.71

 

  

 

3.55

  

  

 

2.97

  

Average realized prices (including all derivative settlements):

 

 

 

 

 

 

 

 

 

 

 

Natural gas (per mcf)

$

2.64

 

 

$

2.98

 

 

$

2.90

 

Natural gas liquids (per bbl)

 

18.85

 

 

 

22.62

 

 

 

14.88

 

Crude oil and condensate (per bbl)

 

49.74

 

 

 

51.60

 

 

 

49.49

 

Total (per mcfe) (a)

 

2.93

 

 

 

3.39

 

 

 

2.99

 

Average realized prices (including all derivative settlements and third-party transportation costs)

 

 

 

  

 

 

 

  

 

 

 

Natural gas (per mcf)

$

1.36

  

  

$

1.74

  

  

$

1.82

  

Natural gas liquids (per bbl)

 

7.03

 

  

 

11.15

  

  

 

8.32

  

Crude oil and condensate (per bbl)

 

49.74

 

  

 

51.60

  

  

 

49.49

  

Total (per mcfe) (a)

 

1.49

 

  

 

1.99

  

  

 

1.95

  

Direct operating costs

 

 

 

  

 

 

 

  

 

 

 

Lease operating (per mcfe) (a)

$

0.13

  

  

$

0.16

  

  

$

0.17

  

Workovers (per mcfe) (a)

 

0.03

 

  

 

0.01

  

  

 

0.01

  

Stock-based compensation (per mcfe) (a)

 

  

  

 

  

  

 

  

Total (per mcfe) (a)

$

0.16

 

 

$

0.17

 

 

$

0.18

 

(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.

7


 

Proved Reserves

The following table sets forth our estimated proved reserves for years ended 2019, 2018 and 2017 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)

 

  

%

 

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

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

  

 

6,451,012

 

  

 

512,318

 

 

 

38,658

 

 

 

9,756,870

 

 

 

54

Undeveloped

  

 

5,576,690

  

  

 

409,276

 

 

 

47,198

 

 

 

8,315,536

 

 

 

46

%

Total Proved

  

 

12,027,702

  

  

 

921,594

 

 

 

85,856

 

 

 

18,072,406

 

 

 

100

%

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017:

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

Proved

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

Developed

  

 

5,437,674

 

  

 

448,258

 

 

 

36,808

 

 

 

8,348,074

 

 

 

55

Undeveloped

  

 

4,825,975

  

  

 

315,006

 

 

 

33,046

 

 

 

6,914,287

 

 

 

45

Total Proved

  

 

10,263,649

  

  

 

763,264

 

 

 

69,854

 

 

 

15,262,361

 

 

 

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.

The following table sets forth summary information by area with respect to estimated proved reserves at December 31, 2019:

 

Reserve Volumes

 

 

PV-10 (a)

 

 

Natural Gas
(Mmcf)

 

  

NGLs
(Mbbls)

 

  

Oil
(Mbbls)

 

  

Total
(Mmcfe)

 

  

%

 

 

Amount
(In thousands)

 

  

%

 

Appalachian Region

 

11,476,601

 

 

 

906,616

 

 

 

68,127

 

 

 

17,325,055

 

  

 

95

 

$

7,426,007

 

 

 

98

North Louisiana Region

 

638,137

 

 

 

31,620

 

 

 

6,370

 

 

 

866,076

 

 

 

5

%

 

 

133,864

 

 

 

2

%

Other

 

239

 

 

 

 

 

 

35

 

 

 

452

  

  

 

 

 

961

 

 

 

Total

 

12,114,977

 

 

 

938,236

 

 

 

74,532

 

 

 

18,191,583

  

  

 

100

 

$

7,560,832

 

 

 

100

(a) 

PV-10 was prepared using the twelve-month average prices for 2019, discounted at 10% per annum. Year-end PV-10 is a non-GAAP financial measure as defined by 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 prior to 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 securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. Our total standardized measure was $6.6 billion at December 31, 2019. The difference between the standardized measure and the PV-10 amount is the discounted estimated future income tax of $932.3 million at December 31, 2019. Included in the $7.6 billion pretax PV-10 is $5.2 billion related to proved developed reserves.

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 also had Wright & Company, Inc., an independent petroleum consultant, conduct an audit of our year-end 2019 reserves in Appalachia. 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 2019, 2018 and 2017, in the aggregate, represented 90%, 94% and 98% of our

8


 

proved reserves. The reserve audits performed for 2019, 2018 and 2017, in the aggregate represented 94%, 96% and 98% of our 2019, 2018 and 2017 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 professionals who work closely with our independent petroleum consultants 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 consultants 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 consultants 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 basis, some of our estimates may be greater than those of our auditor 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 thirty-five 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. We did not file any reports during the year ended December 31, 2019 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.

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, 2019, NGLs represented approximately 31% 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 2019 averaged approximately 35% 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. As of December 31, 2019, we had 475.0 Mmbbls of ethane reserves (2,102 Bcfe) associated with our Marcellus Shale properties, which are included in NGLs proved reserves and represent 51% of our total NGLs reserves. We currently include ethane in our proved reserves which match volumes to be delivered under our existing long-term, extendable ethane contracts.

9


 

Proved Undeveloped Reserves (PUDs)

As of December 31, 2019, our PUDs totaled 40.2 Mmbbls of crude oil, 403.2 Mmbbls of NGLs and 5.6 Tcf of natural gas, for a total of 8.3 Tcfe. Costs incurred in 2019 relating to the development of PUDs were approximately $340.4 million. Approximately 98% of our PUDs at year-end 2019 were associated with the Marcellus Shale. All PUD drilling locations are scheduled to be drilled prior to the end of 2024. As of December 31, 2019, we have 86 Bcfe of reserves that have been reported for more than five years from their original booking date, all of which are in the process of being drilled and are expected to turn to sales in 2020. 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 1.1 Tcfe new PUDs from drilling;

 

 

265.9 Bcfe net positive revision with 601.3 Bcfe of reserves reclassified to unproved because of previously planned wells not to be drilled within the original five-year development horizon more than offset by positive performance revisions of 867.2 Bcfe; and

 

 

214.6 Bcfe reduction from the sale of properties.

 

For an additional description of changes in PUDs for 2019, see Note 18 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):

 

 

2019

 

 

 

2018

 

 

 

2017

 

 

 

2016

 

 

 

2015

 

Future net cash flows

$

22,179

 

 

$

34,836

 

 

$

21,469

 

 

$

10,301

 

 

$

8,666

 

Present value:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Before income tax

 

7,561

 

 

 

13,173

 

 

 

8,147

 

 

 

3,727

 

 

 

3,029

 

After income tax (Standardized Measure)

 

6,629

 

 

 

11,116

 

 

 

7,165

 

 

 

3,452

 

 

 

2,726

 

Benchmark prices (NYMEX):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas price (per mcf)

 

2.58

 

 

 

3.10

 

 

 

2.98

 

 

 

2.48

 

 

 

2.59

 

Oil price (per bbl)

 

55.73

 

 

 

65.55

 

 

 

51.19

 

 

 

42.68

 

 

 

50.13

 

Wellhead prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas price (per mcf)

 

2.38

 

 

 

2.98

 

 

 

2.60

 

 

 

2.07

 

 

 

2.07

 

Oil price (per bbl)

 

49.24

 

 

 

59.96

 

 

 

45.73

 

 

 

37.41

 

 

 

35.07

 

NGLs price (per bbl)

 

17.32

 

 

 

25.22

 

 

 

17.84

 

 

 

13.44

 

 

 

11.74

 

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 and North Louisiana regions of the United States, primarily in the Marcellus Shale in Pennsylvania and the Lower Cotton Valley formation in Louisiana.  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. We have a single company-wide management team that administers all properties as a whole. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. The table below summarizes our operating data for the year ended December 31, 2019.

10


 

Region

 

 

Average
Daily
Production
(mcfe per day)

 

 

 

Production
(Mmcfe)

 

 

 

Percentage of
Production

 

 

 

Proved
Reserves
(Mmcfe)

 

 

 

Percentage of
Proved
Reserves

 

Appalachian

  

 

2,073,553

 

 

 

756,847

 

  

 

91

 

 

17,325,055

 

  

 

95

North Louisiana

  

 

209,496

 

 

 

76,466

  

  

 

9

 

 

866,076

  

  

 

5

Other

  

 

113

 

 

 

41

  

  

 

 

 

452

  

  

 

Total

  

 

2,283,162

 

 

 

833,354

  

  

 

100

 

 

18,191,583

  

  

 

100

The following table summarizes our costs incurred for the year ended December 31, 2019 (in thousands):

Region

 

 

 

Acreage
Purchases

 

 

 

Development
Costs

 

 

 

Exploration
Costs

 

 

 

Gathering
Facilities

 

 

 

Asset
Retirement
Obligations

 

 

 

Total

 

Appalachian

 

$

52,317

 

 

$

603,187

 

 

$

34,502

 

 

$

1,534

 

 

$

(849

 

$

690,691

 

North Louisiana

 

 

5,007

 

 

 

63,797

 

 

 

2,181

 

 

 

2,049

 

 

 

12,042

 

 

 

85,076

 

Total costs incurred

 

$

57,324

 

 

$

666,984

 

 

$

36,683

 

 

$

3,583

 

 

$

11,193

 

 

$

775,767

 

Approximately 95% of our proved reserves at December 31, 2019 is located in the Marcellus Shale in our Appalachian region. This play has a large portfolio of drilling opportunities and therefore has a significant unbooked resource potential within the Marcellus, Utica and Upper Devonian formations. The following table sets forth annual production volumes, average sales prices and production cost data for our wells in the Marcellus Shale play which, as of December 31, 2019, is our only field in which reserves are greater than 15% of our total proved reserves.

 

Marcellus Shale

 

 

2019

 

  

2018

 

  

2017

 

Production:

 

 

 

  

 

 

 

  

 

 

 

Natural gas (Mmcf)

 

516,031

 

  

 

458,406

 

  

 

377,096

 

NGLs (Mbbls)

 

36,013

 

  

 

34,181

 

  

 

29,972

 

Crude oil and condensate (Mbbls)

 

3,199

 

  

 

3,452

 

  

 

3,407

 

Total Mmcfe (a)

 

751,299

 

  

 

684,205

 

  

 

577,368

 

Sales Prices: (b)

 

 

 

  

 

 

 

  

 

 

 

Natural gas (per mcf)

$

1.13

 

  

$

1.77

 

  

$

1.55

 

NGLs (per bbl)

 

7.12

 

  

 

13.08

 

  

 

9.70

 

Crude oil and condensate (per bbl)

 

49.73

 

  

 

59.76

 

  

 

45.49

 

Total (per mcfe) (a)

 

1.33

 

  

 

2.14

 

  

 

1.79

 

Production Costs:

 

 

 

  

 

 

 

  

 

 

 

Lease operating (per mcfe)

 $

0.11

 

  

 $

0.11

 

  

$

0.10

 

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

 

0.03

 

  

 

0.05

 

  

 

0.05

 

(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.

Appalachian Region

Our properties in this area are located in the Appalachian Basin in the northeastern United States, predominantly in Pennsylvania. Currently, our reserves are primarily in the Marcellus Shale formation but also include the Utica and Upper Devonian formations which principally produce at depths ranging from 6,000 feet to 11,500 feet. We own 1,272 net producing wells, almost all of which we operate. Our average working interest in this region is 95%. As of December 31, 2019, we have approximately 892,000 gross (833,000 net) acres under lease.

Reserves at December 31, 2019 were 17.3 Tcfe, an increase of 358.5 Bcfe, or 2%, from 2018. Drilling additions of 1.2 Tcfe and favorable reserve revisions for performance of 889.2 Bcfe were partially offset by production, negative pricing revisions, downward revisions for proved undeveloped reserves no longer in our current five-year development plan of 413.3 Bcfe and sales of 511.7 Bcfe. Annual production increased 10% from 2018. During 2019, we spent $603.2 million in this region to drill 87 (86.5 net) development

11


 

wells, all of which were productive. At December 31, 2019, we had an inventory in the Appalachian region of over 400 proven drilling locations. During the year, we drilled 73 proven locations in the Appalachian region, added 120 new proven drilling locations and deleted or sold 33 proven drilling locations with deleted reserves reclassified to unproved because of longer laterals and lower future capital spending in response to lower commodity prices. During the year, we achieved a 100% drilling success rate in the Appalachian region.

We began operations in the Marcellus Shale in Pennsylvania during 2004. The Marcellus Shale is an unconventional reservoir, which produces natural gas, NGLs and condensate. This has been our largest investment area over the last ten years and we continue to pursue initiatives to improve drilling and completion efficiencies and reduce costs. Our 2019 production from the Marcellus Shale increased 10% from 2018. During 2019, we had approximately 3.3 drilling rigs in the field and expect to run an average of 2.5 rigs throughout 2020.

We have long-term agreements with third parties to provide gathering and processing services and infrastructure assets in the Marcellus Shale, which includes gathering and residue gas pipelines, compression, cryogenic processing, de-ethanization and NGLs fractionation. We have an ethane sales contract in southwestern Pennsylvania whereby a third party purchases and transports ethane from the tailgate of third-party processing and fractionation facilities to the international border for further deliveries into Canada. We also have agreements to transport ethane to the Gulf Coast.

In 2012, we entered into a fifteen-year agreement to transport ethane and propane from the tailgate of a third-party processing plant to a terminal and dock facility near Philadelphia for sale to domestic and international customers. Also in 2012, we executed a fifteen-year agreement relating to ethane sales from that same terminal near Philadelphia. Propane and ethane operations from the terminal began in early 2016.

North Louisiana

We began operations in North Louisiana in September 2016 as a result of an acquisition of a business. These operations are focused on stacked-pay zones in Northern Louisiana, including the Lower Cotton Valley. The Lower Cotton Valley formation extends across East Texas, Louisiana and Southern Arkansas. The formation has been under development since the 1930s and is characterized by thick, multi-zone natural gas and oil reservoirs with well-known geologic characteristics and long-lived, predictable production profiles. We own 409 net producing wells in these locations, almost all of which we operate. Our average working interest is 72%. As of December 31, 2019, we have approximately 124,000 gross (105,000 net) acres under lease.

Total proved reserves were 866.1 Bcfe at December 31, 2019, a decrease of 22% from 2018. We spent $63.8 million in this region to drill 7 (6.1 net) development wells, all of which were productive. In 2019, we had approximately one drilling rig in the field and we currently expect no drilling activity in 2020 or 2021.

We have long-term agreements with third parties to provide gathering, processing and transportation services and infrastructure assets in North Louisiana. We have entered into an area of mutual interest and exclusivity agreement with one of these parties whereby they have the exclusive right to provide midstream services to support our current and future production within such area.

Divestitures

Over the last three years, we have divested over $1.2 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. In 2019, we sold the following assets:

Pennsylvania. In third quarter 2019, we sold, in three separate transactions, a proportionately reduced 2.5% overriding royalty, primarily in our Washington County, Pennsylvania leases for gross proceeds of $750.0 million. In second quarter 2019, we sold natural gas and oil property, primarily representing 20,000 unproved acres, for proceeds of $34.0 million

Miscellaneous. During the year ended December 31, 2019, we sold miscellaneous unproved property, inventory and other assets for proceeds of $937,000.

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Producing Wells

The following table sets forth information relating to productive wells at December 31, 2019. 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

 

1,908

 

1,678

 

88%

 

Crude oil

 

4

 

3

 

75%

 

Total

 

1,912

 

1,681

 

88%

 

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 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, 2019, we had 51 gross (50.0 net) wells in the process of drilling or active completions stage. In addition, there were 62.0 gross (61.6 net) wells waiting on completion or waiting on pipelines at year-end 2019.

 

2019

 

 

2018

 

 

2017

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

94.0

 

 

 

92.6