10-K 1 rrc-10k_20171231.htm 10-K rrc-10k_20171231.htm

d. 

 

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, 2017

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

 

Name of each exchange on which registered

Common Stock, $.01 par value

 

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes      No  

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  

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

 

Large accelerated filer

 

  

Accelerated filer

 

 

 

 

  

Smaller reporting company

 

Non-accelerated filer

 

(Do not check if a smaller reporting company)

  

Emerging growth company

 

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, 2017 was $5,683,957,000. 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 23, 2018, there were 248,539,169 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 2018 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 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 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

 

 

General

 2

 

 

Available Information

 2

 

 

Our Business Strategy

 3

 

 

Significant Accomplishments in 2017

 4

 

 

Industry Operating Environment

 4

 

 

Segment and Geographical Information

 5

 

 

Outlook for 2018

 6

 

 

Production, Price and Cost History

 7

 

 

Proved Reserves

 8

 

 

Property Overview

 10

 

 

Divestitures

13

 

 

Producing Wells

 13

 

 

Drilling Activity

 13

 

 

Gross and Net Acreage

 14

 

 

Undeveloped Acreage Expirations

14

 

 

Title to Properties

 15

 

 

Delivery Commitments

 15

 

 

Employees

 15

 

 

Competition

 15

 

 

Marketing and Customers

 15

 

 

Seasonal Nature of Business

 16

 

 

Markets

16

 

 

Governmental Regulation

 16

 

 

Environmental and Occupational Health and Safety Matters

 18

 

 

Glossary of Certain Defined Terms

24

 

 

 

 

ITEM 1A.

 

Risk Factors

26

 

ITEM 1B.

 

Unresolved Staff Comments

 42

 

ITEM 3.

 

Legal Proceedings

42

 

ITEM 4.

 

Mine Safety Disclosures

 42

 

PART II

 

 

 ITEM 5.

 

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

 43

 

 

Market for Common Stock

 43

 

 

Holders of Record

 43

 

 

Dividends

 43

 

 

Stockholder Return Performance Presentation

 44

 

ITEM 6.

 

Selected Financial Data and Proved Reserve Data

45

i


 

 

TABLE OF CONTENTS (continued)

 

 

 

Page

 

ITEM 7.

 

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

 46

 

 

Overview of Our Business

 46

 

 

Sources of Our Revenues

 46

 

 

Principal Components of Our Cost Structure

 46

 

 

Management’s Discussion and Analysis of Results of Operations

 48

 

 

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

 57

 

 

Management’s Discussion of Critical Accounting Estimates

 62

 

ITEM 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

67

 

 

Market Risk

 67

 

 

Commodity Price Risk

 68

 

 

Other Commodity Risk

 69

 

 

Commodity Sensitivity Analysis

69

 

 

Interest Rate Risk

 69

 

ITEM 8.

 

Financial Statements and Supplementary Data

F-1

 

ITEM 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

71

 

ITEM 9A.

 

Controls and Procedures

71

 

ITEM 9B.

 

Other Information

71

 

PART III

 

 

ITEM 10.

 

Directors, Executive Officers and Corporate Governance

72

 

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 2018 capital budget and the planned allocation thereof; reserve estimates; expectations regarding future economic and market conditions and their effects on us; and our ability to manage through the lower commodity cycles. 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 pricing and supply/demand levels for natural gas, crude oil and natural gas liquids (“NGLs”);

 

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;

 

well production timing;

 

changes in political or economic conditions in our key operating markets;

 

prices and availability of goods and services;

 

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

 

electronic, cyber or physical security breaches;

 

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 areas of operation are the Marcellus Shale in Pennsylvania and the Lower Cotton Valley formation in Louisiana. Our corporate offices are located at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102 (telephone (817) 870-2601). Our common stock is listed and trades on the New York Stock Exchange (the “NYSE”) under the ticker symbol “RRC”. We have been a member of the S&P 500 Index since 2007. Range Resources Corporation was incorporated in 1980. At December 31, 2017, we had 248 million shares outstanding.

Our 2017 production had the following characteristics:

 

average total production of 2,008.9 Mmcfe per day, an increase of 30% from 2016;

 

67% natural gas;

 

total natural gas production of 490.3 Bcf, an increase of 30% from 2016;

 

total NGLs production of 35.7 Mmbbls (including ethane), an increase of 28% from 2016;

 

total crude oil and condensate production of 4.8 Mmbbls, an increase of 33% from 2016; and

 

79% of our total production was from the Marcellus Shale play in Pennsylvania.

At year-end 2017, our proved reserves had the following characteristics:

 

15.3 Tcfe of proved reserves;

 

67% natural gas, 30% NGLs and 3% crude oil;

 

55% proved developed;

 

100% operated;

 

91% of proved reserves are in the Marcellus Shale in Pennsylvania;

 

a reserve life index of approximately 19 years (based on fourth quarter 2017 production);

 

a pretax present value of $8.1 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 $7.2 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 $982.0 million at December 31, 2017.

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, and 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 the President and Chief Executive Officer and Chief Financial Officer.

The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, 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.

2


 

Our Business Strategy

Our overarching business objective is to build stockholder value through returns − focused growth, on a per share debt-adjusted basis, of both reserves and production. Our strategy to achieve our business objective is to increase reserves and production through internally generated drilling projects coupled with occasional acquisitions and divestitures of non-core assets. In addition, we expect to limit capital spending to at or below 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 core operating areas;

 

maintain a multi-year drilling inventory;

 

focus on cost efficiency;

 

maintain a long-life reserve base;

 

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. Complementing this growth area, 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 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 Core Operating Areas. We currently operate primarily in two regions:  Pennsylvania and North Louisiana. Concentrating our drilling and producing activities in these core areas allows us to develop the regional expertise needed to interpret specific geological and operating conditions and develop economies of scale. Operating in core areas as large as the Marcellus Shale and the Lower Cotton Valley allows us to pursue our goal of consistent production and reserve growth at attractive returns. We intend to further develop our acreage in both the Marcellus Shale and North Louisiana and improve our well 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.

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 the economic growth of production and reserves. Currently, we have over 4,400 proven and unproven drilling locations in inventory.

Focus on Cost Efficiency. We concentrate in areas which we believe to have sizeable hydrocarbon deposits in place that will allow us to consistently increase 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 Long-Life Reserve Base. Long-life natural gas and oil reserves provide a more stable growth 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, and oil 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

3


 

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 will 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, 2017, our employees and directors owned equity securities in our benefit plans (vested and unvested) that had an aggregate market value of approximately $100 million.

Significant Accomplishments in 2017

 

Production growth – In 2017, our production averaged 2,008.9 Mmcfe per day, an increase of 30% from 2016. Drilling in the Marcellus Shale play in Pennsylvania drove our production growth. In addition, our merger with Memorial Resource Development Corp. (“Memorial” or “MRD Merger”) in September 2016 also positively impacted our 2017 production. Our capital program is designed to allocate investments based on projects that maximize our production and reserve growth at attractive returns, while minimizing controllable costs associated with production activities.

 

Proved reserves – Total proved reserves increased 26% in 2017, from 12.1 Tcfe to 15.3 Tcfe. This achievement is the result of continued drilling success. The Marcellus Shale is our largest producing region and contains our greatest concentration of reserves. While consistent growth is challenging to sustain, we believe the quality of our technical teams and our substantial inventory of high quality drilling locations provide the basis for future reserve and production growth.

 

Successful drilling program – In 2017, we drilled 177 gross natural gas and oil wells. We replaced 476% of our production through drilling in 2017 and our overall drilling success rate approached 100%. We continue to build our drilling inventory which is critical to our ability to drill a large number of wells 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 2017, 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 potential resources is important. We continued expansion of our shale plays in 2017. 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 growth profiles. Our activity in North Louisiana targets four of the stacked over-pressured pay zones in the Lower Cotton Valley formation.  

 

Focus on financial flexibility – As of December 31, 2017, we maintained a $4.0 billion bank credit facility, with a borrowing base of $3.0 billion and committed borrowing capacity of $2.0 billion. We endeavor to maintain a strong liquidity position. As we have done historically, we may adjust our capital program, divest of non-strategic assets and use derivatives to protect a portion of our future production from commodity price volatility to ensure adequate funds to execute our drilling program and maintain liquidity.

 

Dispositions completed – During 2017, we completed several divestitures. In first quarter 2017, we sold certain properties in Western Oklahoma for proceeds of $26.0 million and we recorded a gain of $22.1 million related to this sale, after closing adjustments and transaction fees. In fourth quarter 2017, we sold certain properties in the Texas Panhandle and Oklahoma for proceeds of $44.4 million and we recorded a loss of $28,000 related to these sales.

 

Leasing acquisitions completed – In 2017, we leased or renewed $62.1 million of acreage located in our core areas. We continue to see outstanding results in the Marcellus Shale. Production in the Marcellus Shale increased 16% and we continue to prove up acreage, acquire additional acreage and gain access to additional pipeline and processing capacity.

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 extremely 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

4


 

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.

Natural gas prices are primarily determined by North American supply and demand and to a lesser extent, natural gas exports and are heavily influenced by weather and storage levels. The New York Mercantile Exchange (“NYMEX”) monthly settlement prices for natural gas averaged $3.10 per mcf in 2017, with a high of $3.93 per mcf in January and a low of $2.63 per mcf in March. In 2016, monthly NYMEX settlement prices averaged $2.51 per mcf. Since the end of 2017, natural gas prices have increased, with the monthly settlement price for natural gas increasing from $3.07 per mcf in December 2017 to $3.63 per mcf in February 2018. Natural gas prices may continue to be under pressure largely due to excess supply of natural gas caused by the high productivity of shale plays in the United States which has outpaced demand. Depressed natural gas futures prices reflect the expectation there will be an oversupply of natural gas in the future.

Significant factors that will impact 2018 crude oil prices include worldwide economic conditions, 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 $51.07 per barrel in 2017, with a high of $57.95 per barrel in December and a low of $45.20 per barrel in June. In 2016, NYMEX monthly settlement oil averaged $43.69 per barrel. Since the end of 2017, crude oil prices have improved, with the monthly settlement price for crude oil rising from $57.95 per barrel in December 2017 to $63.66 per barrel in January 2018. 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 2018.

NGLs prices are primarily determined by North American supply and demand and to a lesser extent, international supply and demand. The growth of unconventional drilling has substantially increased the supply of NGLs, which until recently, 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 which has recently improved NGLs pricing in the United States. While NGLs component prices have improved in recent months, we expect prices will continue to be volatile in 2018.

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.

Any 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 and oil 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 but also partially protect 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.

5


 

Outlook for 2018

For 2018, we have established a $941.2 million capital budget for natural gas, NGLs, crude oil and condensate related activities, excluding proved property acquisitions, for which we do not budget. 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, across our entire asset base to optimize returns without regard to individual areas. To the extent our 2018 capital requirements exceed our internally generated cash flow, proceeds from asset sales, drawing 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 2018 is mitigated using commodity derivative contracts and we intend to continue to enter into these transactions.

Our primary near-term focus includes:

 

preserve liquidity and improve financial strength;

 

focus on organic opportunities through disciplined capital investments;

 

high-grade investments based on rates of returns;

 

improve operational efficiencies and economic returns;

 

limit capital spending to at or below cash flow; and

 

attract and retain quality employees whose efforts 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. For more information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Year Ended December 31,

 

 

2017

 

  

2016

 

  

2015

 

Production

 

 

 

  

 

 

 

  

 

 

 

Natural gas (Mmcf)

 

490,253

 

  

 

375,811

  

  

 

362,687

  

Natural gas liquids (Mbbls)

 

35,709

 

  

 

27,826

  

  

 

20,356

  

Crude oil and condensate (Mbbls)

 

4,787

 

  

 

3,609

  

  

 

4,084

  

Total (Mmcfe) (a)

 

733,231

 

  

 

564,420

  

  

 

509,328

  

Average sales prices (excluding derivative settlements)

 

 

 

  

 

 

 

  

 

 

 

Natural gas (per mcf)

$

2.75

  

  

$

2.01

  

  

$

2.13

  

Natural gas liquids (per bbl)

 

16.93

 

  

 

11.44

  

  

 

8.67

  

Crude oil and condensate (per bbl)

 

46.30

 

  

 

34.60

  

  

 

34.28

  

Total (per mcfe) (a)

 

2.97

 

  

 

2.12

  

  

 

2.14

  

Average realized prices (including all derivative settlements):

 

 

 

 

 

 

 

 

 

 

 

Natural gas (per mcf)

$

2.90

 

 

$

2.68

 

 

$

3.07

 

Natural gas liquids (per bbl)

 

14.88

 

 

 

13.16

 

 

 

10.73

 

Crude oil and condensate (per bbl)

 

49.49

 

 

 

47.82

 

 

 

71.28

 

Total (per mcfe) (a)

 

2.99

 

 

 

2.74

 

 

 

3.18

 

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

 

 

 

  

 

 

 

  

 

 

 

Natural gas (per mcf)

$

1.82

  

  

$

1.60

  

  

$

2.12

  

Natural gas liquids (per bbl)

 

8.32

 

  

 

7.33

  

  

 

8.12

  

Crude oil and condensate (per bbl)

 

49.49

 

  

 

47.82

  

  

 

71.28

  

Total (per mcfe) (a)

 

1.95

 

  

 

1.74

  

  

 

2.41

  

Direct operating costs

 

 

 

  

 

 

 

  

 

 

 

Lease operating (per mcfe) (a)

$

0.17

  

  

$

0.16

  

  

$

0.25

  

Workovers (per mcfe) (a)

 

0.01

 

  

 

0.01

  

  

 

0.01

  

Stock-based compensation (per mcfe) (a)

 

  

  

 

  

  

 

0.01

  

Total (per mcfe) (a)

$

0.18

 

 

$

0.17

 

 

$

0.27

 

 

(a) 

Oil and NGLs 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 of oil and natural gas prices.


7


 

Proved Reserves

The following table sets forth our estimated proved reserves for years ended 2017, 2016 and 2015 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)

 

  

%

 

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

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

  

 

4,352,141

 

  

 

363,852

 

 

 

39,110

 

 

 

6,769,908

 

 

 

56

Undeveloped

  

 

3,518,275

  

  

 

266,214

 

 

 

31,143

 

 

 

5,302,414

 

 

 

44

%

Total Proved

  

 

7,870,416

  

  

 

630,066

 

 

 

70,253

 

 

 

12,072,322

 

 

 

100

%

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015:

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

Proved

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

Developed

  

 

3,376,165

 

  

 

309,306

 

 

 

31,679

 

 

 

5,422,075

 

 

 

55

Undeveloped

  

 

2,901,533

  

  

 

239,828

 

 

 

21,514

 

 

 

4,469,588

 

 

 

45

Total Proved

  

 

6,277,698

  

  

 

549,134

 

 

 

53,193

 

 

 

9,891,663

 

 

 

100

 

(a)

Oil and NGLs 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 of oil and natural gas prices.

The following table sets forth summary information by area with respect to estimated proved reserves at December 31, 2017:

 

Reserve Volumes

 

 

PV-10 (a)

 

 

Natural Gas
(Mmcf)

 

  

NGLs
(Mbbls)

 

  

Oil
(Mbbls)

 

  

Total
(Mmcfe)

 

  

%

 

 

Amount
(In thousands)

 

  

%

 

Appalachian Region

 

9,336,478

 

 

 

704,202

 

 

 

55,855

 

 

 

13,896,819

 

  

 

91

 

$

7,079,971

 

 

 

87

North Louisiana Region

 

877,226

 

 

 

50,836

 

 

 

10,270

 

 

 

1,243,863

 

 

 

8

%

 

 

1,008,553

 

 

 

12

%

Other

 

49,945

 

 

 

8,226

 

 

 

3,729

 

 

 

121,679

  

  

 

1

 

 

58,722

 

 

 

1

Total

 

10,263,649

 

 

 

763,264

 

 

 

69,854

 

 

 

15,262,361

  

  

 

100

 

$

8,147,246

 

 

 

100

 

(a) 

PV-10 was prepared using the twelve-month average prices for 2017, 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 $7.2 billion at December 31, 2017. The difference between the standardized measure and the PV-10 amount is the discounted estimated future income tax of $982.0 million at December 31, 2017. Included in the $8.1 billion pretax PV-10 is $5.5 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 have the following independent petroleum consultants conduct an audit of our year-end 2017 reserves:  Wright & Company, Inc. (Appalachia) and Netherland, Sewell & Associates, Inc. (North Louisiana). The purpose of these audits was to provide additional assurance on the reasonableness of internally prepared reserve estimates. These engineering firms were selected for their geographic expertise and their historical experience in engineering certain properties. The proved reserve audits performed

8


 

for 2017, 2016 and 2015, in the aggregate represented 98%, 96% and 94% of our proved reserves. The reserve audits performed for 2017, 2016 and 2015, in the aggregate represented 98%, 96% and 97% of our 2017, 2016 and 2015 associated pretax present value of proved reserves discounted at ten percent. Copies of the summary reserve reports prepared by our independent petroleum consultants are included as an exhibit to this Annual Report on Form 10-K. The technical person at each 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. The 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 auditors. When such differences do not exceed 10% in the aggregate, our reserve auditors are 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 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 Chairman, 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, 2017 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, 2017, NGLs represented approximately 30% of our total proved reserves on an mcf equivalent basis. NGLs are products priced by the gallon (and sold by the barrel) to the end-user. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels. Prices for a barrel of NGLs in 2017 averaged approximately 63% lower than the average prices 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, 2017, we have 360.6 Mmbbls of ethane reserves (1,596 Bcfe) associated with our Marcellus Shale properties, which are included in NGLs proved reserves and represent 48% 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, 2017, our PUDs totaled 33.0 Mmbbls of crude oil, 315.0 Mmbbls of NGLs and 4.8 Tcf of natural gas, for a total of 6.9 Tcfe. Costs incurred in 2017 relating to the development of PUDs were approximately $920.0 million. Approximately 93% of our PUDs at year-end 2017 were associated with the Marcellus Shale. All PUD drilling locations are scheduled to be drilled prior to the end of 2022 with more than 76% of the future development costs expected to be spent in the next three years. As of December 31, 2017, we have 64 Bcfe of reserves that have been reported for more than five years from their original booking, all of which are in the process of being drilled. Changes in PUDs that occurred during the year were due to:

 

conversion of approximately 1.9 Tcfe of PUDs into proved developed reserves;

 

addition of new PUDs from drilling consisting of 3.2 Tcfe;

 

308.9 Bcfe net positive revision with 668.3 Bcfe of reserves reclassified to unproved because of previously planned wells not to be drilled within the original five-year development horizon offset by improved recovery and other positive performance revisions of 977.2 Bcfe; and

 

9 Bcfe reduction from the sale of properties.

For an additional description of changes in PUDs for 2017, 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):

 

 

2017

 

 

 

2016

 

 

 

2015

 

 

 

2014

 

 

 

2013

 

Future net cash flows

$

21,469

 

 

$

10,301

 

 

$

8,666

 

 

$

26,993

 

 

$

21,029

 

Present value:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Before income tax

 

8,147

 

 

 

3,727

 

 

 

3,029

 

 

 

10,070

 

 

 

7,898

 

After income tax (Standardized Measure)

 

7,165

 

 

 

3,452

 

 

 

2,726

 

 

 

7,593

 

 

 

5,862

 

Benchmark prices (NYMEX):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas price (per mcf)

 

2.98

 

 

 

2.48

 

 

 

2.59

 

 

 

4.35

 

 

 

3.67

 

Oil price (per bbl)

 

51.19

 

 

 

42.68

 

 

 

50.13

 

 

 

94.42

 

 

 

97.33

 

Wellhead prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas price (per mcf)

 

2.60

 

 

 

2.07

 

 

 

2.07

 

 

 

4.14

 

 

 

3.75

 

Oil price (per bbl)

 

45.73

 

 

 

37.41

 

 

 

35.07

 

 

 

79.04

 

 

 

86.66

 

NGLs price (per bbl)

 

17.84

 

 

 

13.44

 

 

 

11.74

 

 

 

27.20

 

 

 

25.93

 

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 North Louisiana properties were acquired in September 2016. 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, 2017. During December 2017, certain properties included in our “Other” operational region were sold.

10


 

Region

 

 

Average
Daily
Production
(mcfe per day)

 

 

 

Production
(Mmcfe)

 

 

 

Percentage of
Production

 

 

 

Proved
Reserves
(Mmcfe)

 

 

 

Percentage of
Proved
Reserves

 

Appalachian

  

 

1,600,566

 

 

 

584,207

 

  

 

80

 

 

13,896,819

 

  

 

91

North Louisiana

  

 

379,982

 

 

 

138,693

  

  

 

19

 

 

1,243,863

  

  

 

8

Other

  

 

28,304

 

 

 

10,331

  

  

 

1

 

 

121,679

  

  

 

1

Total

  

 

2,008,852

 

 

 

733,231

  

  

 

100

 

 

15,262,361

  

  

 

100

The following table summarizes our costs incurred for the year ended December 31, 2017 (in thousands):

Region

 

 

 

Acreage
Purchases

 

 

 

Acquisitions

 

 

 

Development
Costs

 

 

 

Exploration
Costs

 

 

 

Gathering
Facilities

 

 

 

Asset
Retirement
Obligations

 

 

 

Total

 

Appalachian

 

$

37,396

 

 

$

 

 

$

719,479

 

 

$

30,382

 

 

$

8,067

 

 

$

8,162

 

 

$

803,486

 

North Louisiana

 

 

24,635

 

 

 

18,269

 

 

 

453,800

 

 

 

16,113

 

 

 

7,052

 

 

 

11,236

 

 

 

531,105

 

Other

 

 

44

 

 

 

 

 

 

4,247

 

 

 

9,197

 

 

 

(22

 

 

847

 

 

 

14,313

 

Total costs incurred

 

$

62,075

 

 

$

18,269

 

 

$

1,177,526

 

 

$

55,692

 

 

$

15,097

 

 

$

20,245

 

 

$

1,348,904

 

Approximately 91% of our proved reserves at December 31, 2017 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 below 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, 2017, is our only field in which reserves are greater than 15% of our total proved reserves.

 

Marcellus Shale

 

 

2017

 

  

2016

 

  

2015

 

Production:

 

 

 

  

 

 

 

  

 

 

 

Natural gas (Mmcf)

 

377,096

 

  

 

327,000

 

  

 

301,721

 

NGLs (Mbbls)

 

29,972

 

  

 

25,666

 

  

 

19,389

 

Crude oil and condensate (Mbbls)

 

3,407

 

  

 

2,783

 

  

 

3,387

 

Total Mmcfe (a)

 

577,368

 

  

 

497,697

 

  

 

438,377

 

Sales Prices: (b)

 

 

 

  

 

 

 

  

 

 

 

Natural gas (per mcf)

$

1.55

 

  

$

0.79

 

  

$

0.94

 

NGLs (per bbl)

 

9.70

 

  

 

5.00

 

  

 

5.66

 

Crude oil and condensate (per bbl)

 

45.49

 

  

 

32.24

 

  

 

31.78

 

Total (per mcfe)

 

1.79

 

  

 

0.96

 

  

 

1.14

 

Production Costs:

 

 

 

  

 

 

 

  

 

 

 

Lease operating (per mcfe)

 $

0.10

 

  

 $

0.11

 

  

$

0.16

 

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

 

0.05

 

  

 

0.05

 

  

 

0.05

 

(a) 

Oil and NGLs 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 of 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, Medina and Upper Devonian formations which principally produce at depths ranging from 3,500 feet to 11,500 feet. We own 4,554 net producing wells, 100% of which we operate. Our average working interest in this region is 89%. As of December 31, 2017, we have approximately 945,000 gross (881,000 net) acres under lease.

Reserves at December 31, 2017 were 13.9 Tcfe, an increase of 3.3 Tcfe, or 32%, from 2016. Drilling additions of 3.2 Tcfe and favorable reserve revisions for performance, improved recovery and positive pricing revisions were partially offset by production, downward revisions for proved undeveloped reserves no longer in our current five year development plan of 652.6 Bcfe and sales of

11


 

6.6 Bcfe. Annual production increased 16% from 2016. During 2017, we spent $721.5 million in this region to drill 110 (107.2 net) development wells, all of which were productive. At December 31, 2017, the Appalachian region had an inventory of over 349 proven drilling locations and 2 proven recompletions. During the year, the Appalachian region drilled 95 proven locations, added 208 new proven drilling locations and deleted or sold 64 proven drilling locations with deleted reserves reclassified to unproved because of lower future capital spending in response to lower commodity prices. During the year, the region achieved a 100% drilling success rate.

Marcellus Shale

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 nine years and we continue to pursue initiatives to improve drilling and completion efficiencies and reduce costs. We had over 349 proven drilling locations at December 31, 2017. Our 2017 production from the Marcellus Shale increased 16% from 2016. During 2017, we drilled 110 (107.2 net) development wells and no exploratory wells, all of which were successful. In 2018, we plan to drill approximately 100 net wells. During 2017, we had approximately 7 drilling rigs in the field and expect to run an average of 5 rigs throughout 2018.

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 NGL 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 the MRD Merger. These operations are focused on over-pressured natural gas opportunities in multiple zones in the Lower Cotton Valley formation. 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 415 net producing wells in these locations, 100% of which we operate. Our average working interest is 72%. As of December 31, 2017, we have approximately 233,000 gross (205,000 net) acres under lease.

Total proved reserves were 1.2 Tcfe at December 31, 2017, a decrease of 3% from 2016. At December 31, 2017, this area had a development inventory of over 50 proven drilling locations and over 40 proven recompletions. We spent $453.8 million in this region to drill 63 (53.2 net) development wells, all of which were productive. In 2018, we plan to drill approximately 10 net wells. Our operational focus in the Lower Cotton Valley will be on a horizontal development drilling program and continued testing of defined extension areas. We expect our redevelopment program to target four of the stacked over-pressured pay zones in the Lower Cotton Valley formation − zones we term the Upper Red, Lower Red, Lower Deep Pink and Upper Deep Pink. These four zones have an overall thickness ranging from 525 to 1,800 feet. In 2017, we had approximately 5 drilling rigs in the field and we expect to run an average of one rig throughout 2018.

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.

Other

Our other operations include drilling, production and field operations in the Nemaha Uplift of Northern Oklahoma. We own 151 net producing wells in these locations, 100% of which we operate. Our average working interest is 95%. As of December 31, 2017, we have approximately 195,000 gross (121,000 net) acres under lease.

Total proved reserves decreased 101.3 Bcfe, or 45%, at December 31, 2017 when compared to year-end 2016. Reserves declined due to production, property sales (74.6 Bcfe), downward revisions for proved undeveloped reserves no longer in our current five year development plan (15.6 Bcfe) partially offset by positive pricing revisions. Annual production volumes decreased 32% from 2016.

At December 31, 2017, this area had a development inventory of over 25 proven drilling locations and over 5 proven recompletions. During the year, this area had 1 (1.0 net) exploratory well which was not productive. Development projects include

12


 

recompletions and infill drilling. These activities can also include increasing reserves and production through cost control, upgrading lifting equipment, improving gathering systems and surface facilities, and performing restimulations and refracturing operations.

Divestitures

Over the last three years, we have divested over $1.2 billion of non-strategic 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 2017, we sold the following assets:

Texas Panhandle. In fourth quarter 2017, we sold our oil and gas properties in the Texas Panhandle for proceeds of $40.4 million.

Western Oklahoma. In first six months 2017, we sold certain properties in Western Oklahoma for proceeds of $26.8 million. In fourth quarter 2017, we sold Oklahoma remnant properties for proceeds of $4.0 million.

Miscellaneous. During the year ended December 31, 2017, we sold miscellaneous unproved property, inventory and other assets for proceeds of $1.3 million.

Producing Wells

The following table sets forth information relating to productive wells at December 31, 2017. 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

 

5,824

 

5,077

 

87%

 

Crude oil

 

44

 

43

 

98%

 

Total

 

5,868

 

5,120

 

87%

 

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, 2017, we had 56 gross (53.6 net) wells in the process of drilling or active completions stage. In addition, there are 59 gross (58.7 net) wells waiting on completion or waiting on pipelines at year-end 2017.

 

2017

 

 

2016

 

 

2015

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

176.0

 

 

 

163.5

 

 

 

107.0

  

 

 

100.9

  

 

 

133.0

  

 

 

122.3

  

Dry

 

 

 

 

 

 

 

  

 

 

  

 

 

  

 

 

  

Exploratory wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

 

 

 

 

 

1.0

  

 

 

1.0

  

 

 

19.0

  

 

 

19.0

  

Dry

 

1.0

 

 

 

1.0

 

 

 

  

 

 

  

 

 

  

 

 

  

Total wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

176.0

 

 

 

163.5

 

 

 

108.0

  

 

 

101.9

  

 

 

152.0

  

 

 

141.3

  

Dry

 

1.0

  

 

 

1.0

  

 

 

  

 

 

  

 

 

  

 

 

  

Total

 

177.0

  

 

 

164.5

  

 

 

108.0

  

 

 

101.9

  

 

 

152.0

  

 

 

141.3

  

Success ratio

 

99

 

 

99

 

 

100

 

 

100

 

 

100

 

 

100

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Gross and Net Acreage

We own interests in developed and undeveloped natural gas and oil acreage. These ownership interests generally take the form of working interests in oil and natural gas leases that have varying terms. Developed acreage includes leased acreage that is allocated or assignable to producing wells or wells capable of production even though shallower or deeper horizons may not have been fully explored. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether or not the acreage contains proved reserves. The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2017. Acreage related to option acreage, royalty, overriding royalty and other similar interests is excluded from this summary:

 

 

Developed Acres

 

 

 

Undeveloped Acres

 

 

 

Total Acres

 

 

Gross

 

 

 

Net

 

 

 

Gross

 

 

 

Net

 

 

 

Gross

 

 

 

Net

 

Kansas

 

 

 

 

 

 

 

390

 

 

 

390

 

 

 

390

 

 

 

390

 

Louisiana

 

90,051

 

 

 

69,922

 

 

 

142,696

 

 

 

134,872

 

 

 

232,747

 

 

 

204,794

 

New York

 

 

 

 

 

 

 

2,265

 

 

 

567

 

 

 

2,265

 

 

 

567

 

Oklahoma

 

129,475

 

 

 

80,785

 

 

 

12,127

 

 

 

3,164

 

 

 

141,602

 

 

 

83,949

 

Pennsylvania

 

826,870

 

 

 

770,465

 

 

 

110,412

 

 

 

105,253

 

 

 

937,282

 

 

 

875,718

 

Texas

 

39,741

 

 

 

26,394

 

 

 

 

 

 

 

 

 

39,741

 

 

 

26,394

 

West Virginia

 

5,876

 

 

 

5,197

 

 

 

 

 

 

 

 

 

5,876

 

 

 

5,197

 

Wyoming

 

 

 

 

 

 

 

12,468

 

 

 

9,952

 

 

 

12,468

 

 

 

9,952

 

 

 

1,092,013

 

 

 

952,763

 

 

 

280,358

 

 

 

254,198

 

 

 

1,372,371

 

 

 

1,206,961

 

Average working interest

 

 

 

 

 

87

%

 

 

 

 

 

 

91

%

 

 

 

 

 

 

88

%

Undeveloped Acreage Expirations

The table below summarizes by year our undeveloped acreage scheduled to expire in the next five years. Over 75% of the acres scheduled to expire in 2018 is in North Louisiana and Oklahoma.

As of December 31,

  

Acres

  

% of Total

 

 

  

Gross

  

Net

  

Undeveloped

 

 

2018

  

131,474

 

121,115

  

 

48%

 

2019

  

36,596

 

33,314

  

 

13%

 

2020

  

24,945

 

23,487

  

 

9%

 

2021

  

37,630

 

34,082

  

 

13%

 

2022

  

15,589

 

14,707

  

 

6%

 

In all cases the drilling of a commercial well will hold acreage beyond the lease expiration date. We have leased acreage that is subject to lease expiration if initial wells are not drilled within a specified period, generally between three and five years. However, we have in the past and expect in the future, to be able to extend the lease terms of some of these leases and sell or exchange some of these leases with other companies. The expirations included in the table above do not take into account the fact that we may be able to extend the lease terms. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire from time to time and expect to allow additional acreage to expire in the future. We currently have no proved undeveloped reserve locations scheduled to be drilled after lease expiration.

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Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often minimal investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

 

customary royalty or overriding royalty interests;

 

liens incident to operating agreements and for current taxes;

 

obligations or duties under applicable laws;

 

development obligations under oil and gas leases; or

 

net profit interests.

Delivery Commitments

For a discussion of our delivery commitments, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Delivery Commitments.

Employees

As of January 1, 2018, we had 773 full-time employees. All full-time employees are eligible to receive equity awards approved by the compensation committee of the board of directors. No employees are currently covered by a labor union or other collective bargaining arrangement. We believe that the relationship with our employees is excellent.

Competition

Competition exists in all sectors of the oil and gas industry and in particular, we encounter substantial competition in developing and acquiring natural gas and oil properties, securing and retaining personnel, conducting drilling and field operations and marketing production. Competitors in exploration, development, acquisitions and production include the major oil and gas companies as well as numerous independent oil and gas companies, individual proprietors and others. Although our sizable acreage position and core area concentration provide some competitive advantages, many competitors have financial and other resources substantially exceeding ours. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources allow. We face competition for pipeline and other services to transport our product to markets, particularly in the Northeastern portion of the United States. Competitive advantage is gained in the oil and gas exploration and development industry by employing well-trained and experienced personnel who make prudent capital investment decisions based on management direction, embrace technological innovation and are focused on price and cost management. We have a team of dedicated employees who represent the professional disciplines and sciences that we believe are necessary to allow us to maximize the long-term profitability and net asset value inherent in our physical assets. For more information, see Item 1A. Risk Factors.

Marketing and Customers

We market the majority of our natural gas, NGLs, crude oil and condensate production from the properties we operate for our interest, and that of the other working interest owners. We pay our royalty owners from the sales attributable to our working interest. Natural gas, NGLs and oil purchasers are selected on the basis of price, credit quality and service reliability. For a summary of purchasers of our natural gas, NGLs and oil production that accounted for 10% or more of consolidated revenue, see Note 2 to our consolidated financial statements. Because alternative purchasers of natural gas and oil are usually readily available, we believe that the loss of any of these purchasers would not have a material adverse effect on our operations. Production from our properties is marketed using methods that are consistent with industry practice. Sales prices for natural gas, NGLs and oil production are negotiated based on factors normally considered in the industry, such as index or spot price, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. Our natural gas production is sold to utilities, marketing and midstream companies and industrial users. Our NGLs production is typically sold to petrochemical end users (both domestically and internationally) and, to a lesser extent, NGL distributors and natural gas processors. Our oil and condensate production is sold to crude oil processors, transporters and refining and marketing companies in the area. Market volatility due to fluctuating weather conditions, international political developments, overall energy supply and demand, economic growth rates and other factors in the United States and worldwide have had, and will continue to have, a significant effect on energy prices.

We enter into derivative transactions with unaffiliated third parties for a varying portion of our production to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas, NGLs and oil prices. For a more detailed

15


 

discussion, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

We incur gathering and transportation expense to move our production from the wellhead, tanks and processing plants to purchaser-specified delivery points. These expenses vary based on volume, distance shipped and the fee charged by the third-party gatherers and transporters. In Oklahoma, our production is transported primarily through purchaser-owned or third-party trucks, field gathering systems and transmission pipelines. Transportation capacity on these gathering and transportation systems and pipelines is occasionally constrained. Our Appalachian production is transported on third-party pipelines on which, in most cases, we hold long-term contractual capacity. We attempt to balance sales, storage and transportation positions, which can include purchase of commodities from third parties for resale, to satisfy transportation commitments. In Louisiana, we sell substantially all of our production, which is transported on third-party pipelines, to a variety of purchasers. We also have entered into gas processing agreements that have volumetric requirements.

We have not experienced significant difficulty to date in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to transport and market all of our production or obtain favorable prices.

We have entered into several ethane agreements to sell or transport ethane from our Marcellus Shale area. Initial deliveries commenced in late 2013 and deliveries under our most recent agreement began in early 2016. For more information, see Item 1A. Risk Factors – Our business depends on natural gas and oil transportation and NGLs processing facilities, most of which are owned by others and depends on our ability to contract with those parties.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas and propane decreases during the spring and fall months and increases during the winter months and, in some areas, also increases during the summer months. Seasonal anomalies such as mild winters or hot summers also may impact this demand. In addition, pipelines, utilities, local distribution companies and industrial end-users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also impact the seasonality of demand.

Markets

Our ability to produce and market oil, NGLs and natural gas profitably depends on numerous factors beyond our control. The effect of these factors cannot be accurately predicted or anticipated. Although we cannot predict the occurrence of events that may affect commodity prices or the degree to which commodity prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production.

Governmental Regulation

Enterprises that sell securities in public markets are subject to regulatory oversight by federal agencies such as the SEC. The NYSE, a private stock exchange, also requires us to comply with listing requirements for our common stock. This regulatory oversight imposes on us the responsibility for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting, and ensuring that the financial statements and other information included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in such submissions not misleading. Failure to comply with the NYSE listing rules and regulations of the SEC could subject us to litigation from public or private plaintiffs. Failure to comply with the rules of the NYSE could result in the de-listing of our common stock, which could have an adverse effect on the market price of our common stock. Compliance with some of these rules and regulations is costly and regulations are subject to change or reinterpretation.

Exploration and development and the production and sale of oil and gas are subject to extensive federal, state and local regulations. An overview of these regulations is set forth below. We believe we are in substantial compliance with currently applicable laws and regulations and the continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. See Item 1A. Risk Factors The natural gas and oil industry is subject to extensive regulation. We do not believe we are affected differently by these regulations than others in the industry.

General Overview. Our oil and gas operations are subject to various federal, state, tribal and local laws and regulations. Generally speaking, these regulations relate to matters that include, but are not limited to:

 

leases;

 

acquisition of seismic data;

16


 

 

location of wells, pads, roads, impoundments, facilities, rights of way;

 

size of drilling and spacing units or proration units;

 

number of wells that may be drilled in a unit;

 

unitization or pooling of oil and gas properties;

 

drilling, casing and completion of wells;

 

issuance of permits in connection with exploration, drilling, production, gathering, processing and transportation;

 

well production, maintenance, operations and security;

 

spill prevention and containment plans;

 

emissions permitting or limitations;

 

protection of endangered species;

 

use, transportation, storage and disposal of hazardous waste, fluids and materials incidental to oil and gas operations;

 

surface usage and the restoration of properties upon which wells have been drilled;

 

calculation and disbursement of royalty payments and production taxes;

 

plugging and abandoning of wells;

 

hydraulic fracturing;

 

water withdrawal;

 

operation of underground injection wells to dispose of produced water and other liquids;

 

the marketing of production;

 

transportation of production; and

 

health and safety of employees and contract service providers.

In August 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as Range, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (the “FERC”), in contravention of rules prescribed by the FERC. In January 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit any such statement necessary to make the statements not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA of up to $1,000,000 per day per violation. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities or otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to the FERC’s jurisdiction which includes the reporting requirements under Order 704 (as defined and described below). Therefore, the EPAct 2005 was a significant expansion of the FERC’s enforcement authority. Range has not been affected differently than any other producer of natural gas by this act. Failure to comply with applicable laws and regulations with respect to the EPAct 2005 could result in substantial penalties and the regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations with respect to the EPAct 2005, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC, other federal regulatory entities and the courts. We cannot predict when or whether any such proposals may become effective.

In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are required to report to the FERC, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting.

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Intrastate gas pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate gas pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate gas pipeline rates, vary from state to state. Additional proposals and proceedings that might affect the gas industry are considered from time to time by the U.S. Congress, FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their impact, if any, on our operations. We believe that the regulation of intrastate gas pipeline transportation rates will not affect our operations in any way that is materially different from its effects on similarly situated competitors.

Natural gas processing. We depend on gas processing operations owned and operated by third parties. There can be no assurance that these processing operations will continue to be unregulated in the future. However, although the processing facilities may not be directly related, other laws and regulations may affect the availability of gas for processing, such as state regulation of production rates and maximum daily production allowable from gas wells, which could impact our processing.

Gas gathering. Section 1(b) of the NGA exempts gas gathering facilities from FERC jurisdiction. We believe that our gathering facilities meet the traditional tests FERC has used to establish a pipeline system’s status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts. Thus, we cannot guarantee that the jurisdictional status of our gas gathering facilities will remain unchanged.

While we own or operate some gas gathering facilities, we also depend on gathering facilities owned and operated by third parties to gather from our properties, and therefore we are affected by the rates charged by these third parties for gathering services. To the extent that changes in federal or state regulation affect the rates charged for gathering services at any of these third party facilities, we also may be affected by these changes. We do not anticipate that we would be affected differently than similarly situated gas producers.

Regulation of transportation and sale of oil and NGLs. Intrastate liquids pipeline transportation rates, terms and conditions are subject to regulation by numerous federal, state and local authorities and, in a number of instances, the ability to transport and sell such products on interstate pipelines is dependent on pipelines that are also subject to FERC jurisdiction under the Interstate Commerce Act (the “ICA”). We do not believe these regulations affect us differently than other producers.

The ICA requires that pipelines maintain a tariff on file with the FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable”. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before the FERC.

The FERC currently regulates rates of interstate liquids pipelines, primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by the FERC. For the five-year period beginning in July 2016, the FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23 percent. This adjustment is subject to review every five years. Under the FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exits between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. Increases in liquids transportation rates may result in lower revenue and cash flow.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity by current shippers or capacity requests are received from a new shipper. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Environmental and Occupational Health and Safety Matters

Our operations are subject to numerous federal, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may include but are not limited to:  

 

the acquisition of a permit before construction commences;

 

restriction of the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines;

 

governing the sourcing and disposal of water used in the drilling and completion process;

18


 

 

limiting or prohibiting drilling activities on certain lands lying within wilderness, wetlands, frontier and other protected areas;

 

requiring some form of remedial action to prevent or mitigate pollution from existing and former operations such as plugging abandoned wells or closing earthen impoundments; and

 

imposing substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings.

These laws and regulations also may restrict the rate of production. Moreover, changes in environmental laws and regulations often occur, and any changes that result in more stringent and costly well construction, drilling, water management or completion activities or more restrictive waste handling, storage, transport, disposal or cleanup requirements for any substances used or produced in our operations could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general.

Oil and gas activities have increasingly faced opposition from environmental organizations and, in certain areas, have been, restricted or banned by governmental authorities in response to concerns regarding the prevention of pollution or the protection of the environment. Moreover, some environmental laws and regulations may impose strict liability regardless of fault or knowledge, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties at sites we currently own or where we have sent wastes for disposal. To the extent future laws or regulations are implemented or other governmental action is taken that prohibits, restricts or materially increases the costs of drilling, or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected. The following is a summary of some of the environmental laws to which our operations are subject.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons may include owners or operators of the disposal site or sites where the hazardous substance release occurred and companies that disposed of or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, all of these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties, pursuant to environmental statutes, common law or both, to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment. Although petroleum, including crude oil and natural gas, is not a “hazardous substance” under CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as “hazardous substances” under CERCLA and that releases of such wastes may therefore give rise to liability under CERCLA. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA. In addition, certain state laws also regulate the disposal of oil and natural gas wastes. New state and federal regulatory initiatives that could have a significant adverse impact on us may periodically be proposed and enacted.

Waste handling. We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state laws, which impose requirements related to the handling and disposal of non-hazardous solid wastes and hazardous wastes. Drilling fluids, produced waters, and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy are currently regulated by the United States Environmental Protection Agency (“EPA”) and state agencies under RCRA’s less stringent non-hazardous solid waste provisions. It is possible that these solid wastes could in the future be reclassified as hazardous wastes, whether by amendment of RCRA or adoption of new laws, which could significantly increase our costs to manage and dispose of such wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, may be regulated as hazardous wastes. Although the costs of managing wastes classified as hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly situated companies in our industry. Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

We currently own or lease, and have in the past owned or leased, properties that have been used for many years for the exploration and production of crude oil and natural gas. Petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under other locations where such materials have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and comparable state laws and regulations. Under such laws and regulations, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.

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Water discharges and use. The Federal Water Pollution Control Act, as amended (the “CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws also prohibit the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil. We regularly review our natural gas and oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans, the costs of which are not expected to be substantial.

The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from an oil spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe we have been in substantial compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

The Underground Injection Control (“UIC”) Program authorized by the Safe Drinking Water Act prohibits any underground injection unless authorized by a permit. In connection with our operations, Range may dispose of produced water in underground wells, which are designed and permitted to place the water into deep geologic formations, isolated from fresh water sources. However, because some states have become concerned that the disposal of produced water could under certain circumstances contribute to seismicity, they have adopted or are considering adopting additional regulations governing such disposal. For example, in January 2016, Ohio lawmakers proposed new legislation that would, among other things, require injection wells be located more than 2,000 feet from any occupied dwelling. While that particular legislation did not become law, should similar onerous regulations or bans relating to underground wells be placed in effect in areas where Range has significant operations, there could be an impact on Range’s ability to operate.

Hydraulic fracturing.  Hydraulic fracturing, which has been used by the industry for over 60 years, is an important and common practice to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely apply hydraulic fracturing techniques as part of our operations. This process is typically regulated by state environmental agencies and oil and natural gas commissions; however, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act (as defined below) regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; proposed effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Additionally, while the Federal Bureau of Land Management (“BLM”) released a final rule setting forth disclosure requirements and other regulatory mandates for hydraulic fracturing on federal lands in March 2015, on December 29, 2017, the U.S. Department of Interior rescinded the 2015 rule that would have set new environmental limitations on hydraulic fracturing, or fracking, on public lands because it believed the 2015 rule imposed administrative burdens and compliance costs that were not justified. Moreover, from time to time, Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition to any actions by Congress, certain states in which we operate, including Pennsylvania and Texas, have adopted, and other states are considering adopting, regulations imposing or that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing operations. States could also elect to prohibit hydraulic fracturing altogether, such as in the State of New York. Local governments also may seek to adopt ordinances within their jurisdiction regulating the time, place or manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we currently or in the future plan to operate, we may incur additional, more significant, costs to comply with such requirements and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

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In addition, certain government reviews are underway that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA issued its final report on the potential of hydraulic fracturing to impact drinking water resources through water withdrawals, spills, fracturing directly into such resources, underground migration of liquids and gases, and inadequate treatment and discharge of wastewater which did not find evidence that these mechanisms have led to widespread, systematic impacts on drinking water resources. However, the EPA’s report did identify future efforts that could be taken to further understand the potential of hydraulic fracturing to impact drinking water resources, including ground water and surface water monitoring in areas with hydraulically fractured oil and gas production wells. Based on the EPA’s study, existing regulations and our practices, we do not believe our hydraulic fracturing operations are likely to impact drinking water resources but the EPA study could result in initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

We believe that our hydraulic fracturing activities follow applicable industry practices and legal requirements for groundwater protection and that our hydraulic fracturing operations have not resulted in material environmental liabilities. We do not maintain insurance policies intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our existing insurance policies would cover any alleged third-party bodily injury and property damage caused by hydraulic fracturing including sudden and accidental pollution coverage.

Air emissions. The Clean Air Act of 1963 (as amended, the “Clean Air Act”), and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or use specific equipment or technologies to control emissions. We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals for emissions of pollutants. For example, pursuant to then President Obama’s Strategy to Reduce Methane Emissions in August 2015, the EPA proposed new regulations that would set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of the Obama Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. The EPA finalized these new regulations on June 3, 2016 to be effective August 2, 2016; however on June 12, 2017 the EPA announced a proposed 2 year stay on these fugitive emissions standards “while the agency reconsiders them”. Therefore, the date when and if these standards may become implemented is still not known. In a second example, in October 2015, the EPA finalized a rulemaking proposal that revises the National Ambient Air Quality Standard for ozone to 70 parts per billion for both the 8-hour primary and secondary standards. Compliance with one or both of these regulatory initiatives could directly impact us by requiring installation of new emission controls on some of our equipment, resulting in longer permitting timelines, and significantly increasing our capital expenditures and operating costs, which could adversely impact our business.

Climate change. In 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA adopted regulations under the existing Clean Air Act establishing Title V and Prevention of Significant Deterioration (“PSD”) permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. We could become subject to these Title V and PSD permitting reviews and be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if such facilities emitted volumes of GHGs in excess of threshold permitting levels. The EPA has also adopted rules requiring the reporting of GHG emissions from specified emission sources in the United States on an annual basis, including certain oil and natural gas production facilities, which include several of our facilities. We believe that our monitoring activities and reporting are in substantial compliance with applicable obligations.

Congress has from time to time considered legislation to reduce emissions of GHGs and there have been a number of federal regulatory initiatives to address GHG emissions in recent years, such as the establishing of Title V and PSD permitting reviews for GHG emissions as described in more detail above. Additionally, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future federal or state laws and regulations, or international compacts, could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements. On an international level, the United States was one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets, which agreement formally entered into force on November 4, 2016. While the United States formally accepted that agreement in September 2016, on June 1, 2017, President Trump determined to withdraw the United States from the Paris Agreement. Under the term of the Paris Agreement, the earliest possible effective date for withdrawal by the United States is November 4, 2020, four years after the

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agreement came into effect. Future United States regulations on GHG emissions designed to meet the Paris Agreement goals could impact us in ways that cannot be determined at this time.

While it is unclear at this time whether President Trump or Congress will pursue legislation or regulation to address GHG emissions in light of the withdrawal of the Paris Agreement, any such legislation or regulatory programs could also increase the cost of consuming, and thereby could reduce demand for the oil and natural gas that we produce. However, President Trump has taken certain actions since taking office that have begun to establish a national policy in favor of energy independence and economic growth. For example, on March 28, 2017, President Trump issued an Executive Order for the purpose of facilitating the development of United States energy resources and reducing unnecessary regulatory burdens associated with the development of those resources. Through the Executive Order, President Trump has directed agencies to review existing regulations that potentially burden the development of domestic energy resources, and appropriately suspend, revise, or rescind regulations that unduly burden the development of United States energy resources beyond what is necessary to protect the public interest or otherwise comply with the law. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Activities on federal lands. Oil and natural gas exploration, development and production activities on federal lands, including Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Currently, we have minimal exploration and production activities on federal lands. However, for those current activities as well as for future or proposed exploration and development plans on federal lands, we will be required to obtain governmental permits or authorizations that are subject to the requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Endangered species. The federal Endangered Species Act of 1973, as amended (the “ESA”), restricts activities that may affect endangered and threatened species or their habitats. If endangered species are located in an area where we wish to conduct seismic surveys, development activities or abandonment operations, or are located in an area where new pipelines are planned; the work could be prohibited or delayed or expensive mitigation may be required. Moreover, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. As a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service (“FWS”) was required to make a determination on the listing of numerous species as endangered or threatened under the Endangered Species Act prior to the completion of the agency’s 2017 fiscal year. For example, while the lesser prairie chicken is not currently designated as threatened or endangered, in November 2016, the FWS issued its 90-day findings in response to a petition to reclassify the lesser prairie chicken under the ESA. In those findings, FWS found that the petition presented substantial information that the petitioned action may be warranted, prompting a thorough status review. We cannot predict the outcome of this review process. The designation of currently unprotected species, including the lesser prairie chicken, as threatened or endangered in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

The Migratory Bird Treaty Act (“MBTA”) implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. In accordance with this law, the taking, killing or possessing of migratory birds covered under this act is unlawful without a permit. If there is the potential to adversely affect migratory birds as a result of our operations, we may be required to obtain necessary permits to conduct those operations, which may result in specified operating restrictions on a temporary, seasonal, or permanent basis in affected areas and an adverse impact on our ability to develop and produce our reserves. However, in December 2017, the U.S. Department of Interior stated in a solicitor’s opinion that it will no longer prosecute oil and gas, wind and solar operators that accidentally kill birds based on a reinterpretation of the MBTA that it does not prohibit accidental takings of migratory birds.

We believe we are in substantial compliance with currently applicable environmental laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2017, nor do we anticipate that such expenditures will be material in 2018. However, we regularly have expenditures to comply with environmental laws and we anticipate those costs will continue to be incurred in the future.

Occupational health and safety. We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees. In addition,

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OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements.


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GLOSSARY OF CERTAIN DEFINED TERMS

The terms defined in this glossary are used in this report.

bbl. One stock tank barrel, or 42 U.S. gallons liquid volumes, used herein in reference to crude oil or other liquid hydrocarbons.

bcf. One billion cubic feet of gas.

bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of 6 mcf for each barrel of oil or NGLs, which reflects relative energy content.

btu. One British thermal unit, an energy equivalence measure. A British thermal unit is the heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing oil or natural gas in sufficient economic quantities.

Exploratory well. A well drilled to find oil or gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of oil and gas in another reservoir or to extend a known reservoir.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Henry Hub price. A natural gas benchmark price quoted at settlement date average.

mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.

mcf. One thousand cubic feet of gas.

mcf per day. One thousand cubic feet of gas per day.

mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6 mcf for each barrel of oil or NGLs, which reflects relative energy content.

mmbbl. One million barrels of crude oil or other liquid hydrocarbons.

mmbtu. One million British thermal units.

mmcf. One million cubic feet of gas.

mmcfe. One million cubic feet of gas equivalents.

NGLs. Natural gas liquids, which are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline that can be collectively removed from produced natural gas, separated into these substances and sold.

Net acres or Net wells. The sum of the fractional working interests owned in gross acres or gross wells.

NYMEX. New York Mercantile Exchange.

Present Value (PV). The present value of future net cash flows, using a 10% discount rate, from estimated proved reserves, using constant prices and costs in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions). The after tax present value is the Standardized Measure.

Productive well. A well that is producing oil or gas or that is capable of production.

Proved developed non-producing reserves. Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved

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reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed reserves. Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extracting equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.

Proved reserves. The quantities of crude oil, natural gas and NGLs that geological and engineering data can estimate with reasonable certainty to be economically producible within a reasonable time from known reservoirs under existing economic, operating and regulatory conditions prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The completion for production an existing well bore in another formation from that in which the well has been previously completed.

Reserve life index. Proved reserves at a point in time divided by the then production rate (annually or quarterly).

Royalty acreage. Acreage represented by a fee mineral or royalty interest which entitles the owner to receive free and clear of all production costs a specified portion of the oil and gas produced or a specified portion of the value of such production.

Royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and natural gas production free of costs of production.

Standardized Measure. The present value, discounted at 10%, of future net cash flows from estimated proved reserves after income taxes, calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the Commission’s rules for inclusion of oil and gas reserve information in financial statements filed with the Commission.

tcfe. One trillion cubic feet of natural gas equivalents, with one barrel of NGLs or crude oil being equivalent to 6,000 cubic feet of natural gas.

Unproved properties. Properties with no proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens, and to all costs of exploration, development and operations, and all risks in connection therewith.

Unconventional play. A term used in the oil and gas industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds or (3) shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation or other special recovery processes in order to achieve economic flow rates.


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ITEM 1A. RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. The following summarizes the known material risks and uncertainties that may adversely affect our business, financial condition or results of operations. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in foregoing pages under “Disclosures Regarding Forward-Looking Statements” and other information included and incorporated by reference into this Annual Report on Form 10-K. These risks are not the only risks we face. Our business could also be impacted by additional risks and uncertainties not currently known to us or that we currently deem to be immaterial.

Risks Related to Our Business

Volatility of natural gas, NGLs and oil prices significantly affects our cash flow and capital resources and could hamper our ability to operate economically. Natural gas, NGLs and oil prices are volatile, and a decline in prices adversely affects our profitability and financial condition. The oil and gas industry is typically cyclical and we expect the volatility to continue. Between 2014 and 2017, the average NYMEX monthly settlement price of natural gas has been as high as $5.56 per Mmbtu and as low as $1.71 per Mmbtu. During that same time frame, the average NYMEX monthly oil settlement price was as high as $105.15 per barrel and as low as $30.62 per barrel. Over the past few months, natural gas and oil prices have increased with the average NYMEX monthly settlement price for natural gas for February 2018 increasing to $3.63 per Mmbtu and the monthly settlement for crude oil increasing to $63.66 per barrel in January 2018. Likewise, NGLs have suffered significant recent declines in realized prices. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs. A further or extended decline in commodity prices could materially and adversely affect our business, cash flow, financial condition and results of operations. Natural gas prices are likely to affect us more than oil prices because approximately 67% of our December 31, 2017 proved reserves are natural gas.

Natural gas, NGLs and oil prices fluctuate in response to changes in supply and demand, market uncertainty and other factors that are beyond our control. Long-term supply and demand for natural gas, NGLs and oil is uncertain and subject to a myriad of factors such as:

 

the domestic and foreign supply of, and demand for, natural gas, NGLs and oil;

 

domestic and world-wide economic conditions;

 

the level and effect of trading in commodity futures markets, including commodity price speculators and others;

 

weather conditions;

 

technological advances affecting energy consumption and production;

 

the price and level of foreign imports;

 

U.S. domestic and worldwide economic conditions;

 

the availability, proximity and capacity of transportation facilities, processing and storage facilities;

 

the effect of worldwide energy conservation efforts;

 

the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations that work together to agree and maintain oil price and production controls;

 

expansion of U.S. exports of oil, NGLs and/or liquefied natural gas;

 

military, economic and political conditions in natural gas and oil producing regions;

 

the cost of exploring for, developing, producing, transporting and marketing natural gas, NGLs and oil: and

 

domestic (federal, state and local) and foreign governmental regulations and taxes.

Lower natural gas, NGLs and oil prices may not only decrease our revenues and cash flow on a per unit basis but also may reduce the amount of natural gas, NGLs and oil that we can economically produce. A reduction in production could result in a shortfall in expected cash flows and require a reduction in capital spending or require additional borrowing. Without the ability to fund capital expenditures, we would be unable to replace reserves which would negatively affect our future rate of growth. Lower natural gas, NGLs and oil prices may also result in a reduction in the borrowing base under our bank credit facility, taking into account the value of our estimated proved reserves, which is adversely affected by declines in natural gas, NGLs and oil prices. The borrowing base under our bank credit facility, which is determined by our lenders at their discretion, is subject to redetermination annually by each May and for event driven unscheduled redeterminations.

Producing natural gas, NGLs and oil may involve unprofitable efforts. As of December 31, 2017, the relationship between the price of oil and the price of natural gas continues to be at a wide spread. Normally, NGLs production is a by-product of natural gas

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production. At times, we and other producers may choose to sell natural gas at below cost, or otherwise dispose of natural gas to allow for the profitable sale of only oil, NGLs and condensate. The prices of NGLs can be unpredictable. For example, over the past four years, the average Mont Belvieu NGL composite price has been as high as $0.98 per gallon and as low as $0.30 per gallon. Such volatility in the pricing of NGLs complicates such decisions and may materially and adversely affect the profitability of such decisions.

Information concerning our reserves and future net cash flow estimates is uncertain. There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves and their values, including many factors beyond our control. Estimates of proved reserves are by their nature uncertain and depend on many assumptions relating to current and further economic conditions and commodity prices. To the extent we experience a sustained period of reduced commodity prices, there is a risk that a portion of our proved reserves could be deemed uneconomic and no longer be classified as proved. Although we believe these estimates are reasonable, actual production, revenues and costs to develop will likely vary from estimates and these variances could be material.

Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of natural gas and oil that cannot be directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may calculate different estimates of reserves and future net cash flows based on the same available data. Because of the subjective nature of natural gas, NGLs and oil reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:

 

the amount and timing of natural gas, NGLs and oil production;

 

the revenues and costs associated with that production;

 

the amount and timing of future development expenditures; and

 

future commodity prices.

The discounted future net cash flows from our proved reserves included in this report should not be considered as the market value of the reserves attributable to our properties. As required by United States generally accepted accounting principles, the estimated discounted future net revenues from our proved reserves are based on a twelve month average price (first day of the month) while cost estimates are based on current year-end economic conditions. Actual future prices and costs may be materially higher or lower. In addition, the ten percent discount factor that is required to be used to calculate discounted future net cash flows for reporting purposes under United States generally accepted accounting principles is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general.

If natural gas, NGLs and oil prices remain depressed or drilling efforts are unsuccessful, we may be required to record writedowns of our proved natural gas and oil properties. We have been required to write down the carrying value of certain of our natural gas and oil properties in the past and there is a risk that we will be required to take additional writedowns in the future. Recent commodity price declines have resulted in an impairment of our proved oil and gas properties. For example, in third quarter 2015, we recorded a $502.2 million impairment of natural gas and oil properties in Northern Oklahoma and our legacy producing assets in Northwest Pennsylvania, and in fourth quarter 2015, we recorded an additional impairment of $87.9 million primarily related to our natural gas and oil properties in the Texas Panhandle. In first quarter 2016, we recorded a $43.0 million proved property impairment in Western Oklahoma. In third quarter 2017, we recorded a $63.7 million proved property impairment related to our natural gas and oil properties in the Texas Panhandle and Northern Oklahoma. These impairments were due to a significant decline in commodity prices and the potential sale of certain of these properties. Writedowns may occur in the future when natural gas and oil prices are low, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs, deterioration in our drilling results or mechanical problems with wells where the cost to redrill or repair is not supported by the expected economics. Because our reserves are predominately natural gas, changes in natural gas prices have a more significant impact on our financial results.

Accounting rules require that the carrying value of natural gas and oil properties be periodically reviewed for possible impairment. Impairment is recognized for the excess of book value over fair value when the book value of a proven property is greater than the expected undiscounted future net cash flows from that property and on acreage when conditions indicate the carrying value is not recoverable. We may be required to write down the carrying value of a property based on natural gas and oil prices at the time of the impairment review, or as a result of continuing evaluation of drilling results, production data, economics, divestiture activity, and other factors. A write down constitutes a non-cash charge to earnings and does not impact cash or cash flows from operating activities; however, it reflects our long-term ability to recover an investment and reduces our reported earnings and increases certain leverage ratios. If commodity prices remain depressed, we may be required to further impair the carrying value of our natural gas and oil properties.

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We evaluate our unproved oil and gas properties for impairment and could be required to recognize noncash charges in the earnings of future periods. At December 31, 2017, our unproved natural gas and oil properties were $2.6 billion. Our analysis of these costs is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of the leases. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success.

We periodically evaluate our goodwill for impairment and could be required to recognize noncash charges in the earnings of future periods. At December 31, 2017, we have goodwill of $1.6 billion. Goodwill is assessed for impairment annually during the fourth quarter or whenever facts or circumstances indicate that the carrying value of our business may be impaired which may require an estimate of the fair values of our assets and liabilities. Those assessments may be affected by:  

 

additional reserve adjustments both positive and negative;

 

results of drilling activities;

 

management’s outlook for commodity prices and costs and expenses;

 

changes in our market capitalization;

 

changes in our weighted average cost of capital; and

 

changes in income taxes.

If the fair value of our net assets is not sufficient to fully support the goodwill balance in the future, we may be required to reduce the carrying value of goodwill for the impaired value and incur a corresponding noncash charge to earnings in the period in which goodwill is determined to be impaired.

Significant capital expenditures are required to replace our reserves. Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flow from operations, our bank credit facility and debt and equity issuances. We have also engaged in asset monetization transactions. Currently, we have set our capital expenditures in 2018 to closely align with our projected cash flows from operations in 2018. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of natural gas, NGLs and oil and our success in developing and producing new reserves. If our access to capital were limited due to various factors, which could include a decrease in revenues due to lower natural gas, NGLs and oil prices or decreased production or deterioration of the credit and capital markets, we would have a reduced ability to replace our reserves. We may not be able to incur additional bank debt, issue debt or equity, engage in asset monetization or access other methods of financing on an economic basis to meet our reserve replacement requirements.

The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by our lenders, at their discretion, taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. Declines in natural gas, NGLs and oil prices adversely impact the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base and could result in a determination to lower our borrowing base. In the past several years, natural gas, NGLs and oil prices declined significantly. A further or extended decline in commodity prices could materially and adversely affect our business, financial condition and results of operations.

Our future success depends on our ability to replace reserves that we produce. Because the rate of production from natural gas and oil properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional natural gas, NGLs and oil reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. Future natural gas, NGLs and oil production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot be certain that we will be able to find or acquire and develop additional reserves at an acceptable cost.

We acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire both producing and unproved properties as well as lease undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot be certain that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells. Low commodity prices may cause us to delay our drilling plans and as a result, we may lose our right to develop the related property.

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Drilling is an uncertain and costly activity. The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough natural gas, NGLs and oil to be commercially viable after drilling, operating and other costs. There is no way to conclusively know in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in commercially viable quantities. Furthermore, our drilling and producing operations may be curtailed, delayed, or canceled as a result of a variety of factors, including, but not limited to:

 

increases in the costs, shortages or delivery delays of drilling rigs, equipment, water for hydraulic fracturing services, labor, or other services;

 

unexpected operational events and drilling conditions;

 

reductions in natural gas, NGLs and oil prices;

 

limitations in the market for natural gas, NGLs and oil;

 

adverse weather conditions and changes in weather patterns;

 

facility or equipment malfunctions;

 

equipment failures or accidents;

 

loss of title and other title-related issues;

 

pipe or cement failures;

 

compliance with, or changes in, environmental, tax and other governmental requirements;

 

environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, and unauthorized discharges of toxic gases;

 

lost or damaged oilfield drilling and service tools;

 

unusual or unexpected geological formations;

 

loss of drilling fluid circulation;

 

pressure or irregularities in formations;

 

fires;

 

natural disasters;

 

surface craterings and explosions;

 

uncontrollable flows of oil, natural gas or well fluids;

 

availability and timely issuance of required governmental permits and licenses; and

 

civil unrest or protest activities.

If any of these factors were to occur, we could lose all or a part of our investment, or we could fail to realize the expected benefits, either of which could materially and adversely affect our revenue and profitability.

Our operations involve utilizing drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

 

landing the wellbore in the desired drilling zone;

 

staying in the desired drilling zone while drilling horizontally through the formation;

 

running casing the entire length of the wellbore; and

 

being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing horizontal wells include, but are not limited to, the following:

 

the ability to fracture stimulate the planned number of stages;

 

the ability to run tools the entire length of the wellbore during completion operations; and

 

the ability to successfully clean out the wellbore after completion of the final fracture stimulation state.

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Drilling in emerging areas is more uncertain than drilling in areas that are more developed and have a longer history of established drilling operations. New discoveries and emerging formations have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are worse than anticipated, the return on investment for a particular project may not be as attractive as anticipated and we may recognize noncash impairment charges to reduce the carrying value of its unproved properties in those areas.

Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory and zoning approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our business and results of operations.

We may incur losses as a result of title defects in the properties in which we invest. It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgement of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.

Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Our producing properties are largely concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in a significant geographic area. Our producing properties are geographically concentrated in the Appalachian Basin in Pennsylvania. At December 31, 2017, 91% of our total estimated proved reserves were attributable to properties located in Pennsylvania. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, state politics, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or interruption of the processing or transportation of crude oil, condensate, natural gas or NGLs.

New technologies may cause our current exploration and drilling methods to become obsolete. There have been rapid and significant advancements in technology in the natural gas and oil industry, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial increase in cost. Further, competitors may obtain patents which might prevent us from implementing new technologies. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.

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Our indebtedness could limit our ability to successfully operate our business. We are leveraged and our exploration and development program will require substantial capital resources depending on the level of drilling and the expected cost of services. Our existing operations will also require ongoing capital expenditures. In addition, if we decide to pursue additional acquisitions, our capital expenditures will increase, both to complete such acquisitions and to explore and develop any newly acquired properties.

The degree to which we are leveraged could have other important consequences, including the following:

 

we may be required to dedicate a substantial portion of our cash flows from operations to the payment of our indebtedness, reducing the funds available for our operations;

 

a portion of our borrowings is at variable rates of interest, making us vulnerable to increases in interest rates;

 

we may be more highly leveraged than some of our competitors, which could place us at a competitive disadvantage;

 

our degree of leverage may make us more vulnerable to a downturn in our business or the general economy;

 

we are subject to numerous financial and other restrictive covenants contained in our existing debt agreements, which restrict our ability to engage in certain activities and could limit our growth, and the breach of such covenants, which could materially and adversely impact our financial performance;

 

our debt level could limit our flexibility to grow the business and in planning for, or reacting to, changes in our business and the industry in which we operate; and

 

we may have difficulties borrowing money in the future.

The risks described above may further increase in the event we incur additional debt. In addition to those risks above, we may not be able to obtain funding on acceptable terms.

Any failure to meet our debt obligations could harm our business, financial condition and results of operations. We expect our earnings and cash flow to fluctuate from year to year due to the cyclical nature of our business. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or restructure our debt. Our ability to restructure our debt will depend on the condition of the capital markets and our financial condition at such time. Any restructuring of debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity.

We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term growth opportunities. Liquidity, asset quality, cost structure, product mix and commodity pricing levels are also considered by the rating agencies. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt and potentially require us to post letters of credit or other forms of collateral for certain obligations.

As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part. The terms of our senior indebtedness, including our revolving credit facility, contain cross-default provisions which provide that we will be in default under such agreements in the event of certain defaults under our indentures or other loan agreements. Accordingly, should an event of default above certain thresholds occur under any of those agreements, we face the prospect of being in default under all of our debt agreements, obliged in such instance to satisfy all of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us, which would negatively affect our ability to implement our business plan, make capital expenditures and finance our operations.

We are subject to financing and interest rate exposure risks. Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in our credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, at December 31, 2017, approximately 71% of our debt is at fixed interest rates with the remaining 29% subject to variable interest rates.

Disruptions or volatility in the global finance markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results. We are

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exposed to some credit risk related to our bank credit facility to the extent that one or more of our lenders may be unable to provide necessary funding to us under our existing revolving line of credit if it experiences liquidity problems.

A financial downturn or negative credit market conditions may have lasting effects on our liquidity, business and financial condition that we cannot predict. Liquidity is essential to our business. Our liquidity could be substantially negatively affected by an inability to obtain capital in the long-term or short-term debt capital markets or equity capital markets or an inability to access bank financing. A prolonged credit crisis or turmoil in the domestic or global financial systems could materially affect our liquidity, business and financial condition. These conditions have adversely impacted financial markets previously and created substantial volatility and uncertainty, and could do so again, with the related negative impact on global economic activity and the financial markets. Negative credit market conditions could materially affect our liquidity and may inhibit our lenders from fully funding our bank credit facility or cause them to make the terms of our bank credit facility costlier and more restrictive. We are subject to annual reviews, as well as unscheduled reviews, of our borrowing base under our bank credit facility, and we do not know the results of future redeterminations or the effect of then-current oil and natural gas prices on that process. A weak economic environment could also adversely affect the collectability of our trade receivables or performance by our suppliers or other third parties that we contract with to operate our properties or provide facilities.  In addition, it may also cause our commodity derivative arrangements to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, negative economic conditions could lead to reduced demand or lower prices for natural gas, NGLs and oil, which could have a negative impact on our revenues.

Derivative transactions may limit our potential gains and involve other risks. To manage our exposure to price risk, we currently and may in the future enter into derivative arrangements, utilizing commodity derivatives with respect to a portion of our future production. Such hedges are designed to lock in prices so as to limit volatility and increase the predictability of cash flow. These transactions limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the hedge. In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

our production is less than expected;

 

the counterparties to our futures contracts fail to perform on their contract obligations; or

 

an event materially impacts natural gas, NGLs or oil prices or the relationship between the hedged price index and the natural gas or oil sales price.

We cannot be certain that any derivative transaction we may enter into will adequately protect us from declines in the prices of natural gas, NGLs or oil. Furthermore, where we choose not to engage in derivative transactions in the future, we may be more adversely affected by changes in natural gas, NGLs or oil prices than our competitors who engage in derivative transactions. Lower natural gas, NGLs and oil prices may also negatively impact our ability to enter into derivative contracts at favorable prices.

We are exposed to a risk of financial loss if a counterparty fails to perform under a derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to mitigate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Many of our current and potential competitors have greater resources than we have and we may not be able to successfully compete in acquiring, exploring and developing new properties. We face competition in every aspect of our business, including, but not limited to, acquiring reserves and leases, obtaining goods, services and employees needed to operate and manage our business and marketing natural gas, NGLs or oil. Competitors include multinational oil companies, independent production companies and individual producers and operators. Many of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address these competitive factors more effectively than we can or withstand industry downturns more easily than we can. For more discussion regarding competition, see Items 1 & 2. Business and Properties – Competition.

The natural gas and oil industry is subject to extensive regulation. The natural gas and oil industry is subject to various types of regulations in the United States by local, state and federal agencies. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Numerous departments and agencies, both state and federal, are authorized by statute to issue rules and regulations binding on participants in the natural gas and oil industry. Compliance with such rules and regulations often increases our cost of doing business, delays our operations and, in turn, decreases our profitability.

Our operations are subject to numerous and increasingly strict federal, state and local laws, regulations and enforcement policies relating to the environment. We may incur significant costs and liabilities in complying with existing or future environmental laws, regulations and enforcement policies and may incur costs arising out of property or natural resource damage or injuries to employees

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and other persons. These costs may result from our current and former operations and may even be caused by previous owners of property we own or lease or relate to third party sites where we have taken materials for recycling or disposal. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as corrective action orders. Matters subject to regulation include, but are not limited to, the following:

 

the amounts and types of substances and materials that may be released into the environment;

 

responding to unexpected releases to the environment;

 

reports and permits concerning exploration, drilling, production and other regulated activities;

 

the spacing of wells;

 

unitization and pooling of properties;

 

calculating royalties on oil and gas produced under federal and state leases; and

 

taxation.

Under such laws and regulations, we could be liable for personal injuries, property damages, oil spills, discharges of hazardous materials, remediation and clean-up costs, natural resource damages and other environmental damages. We also could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. If we incur these costs or damages it may reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

The subject of climate change continues to receive attention from scientists, legislators, governmental agencies and the general public. There is an ongoing debate as to the extent to which our climate is changing, the potential causes of this change and its potential impacts. Some attribute global warming to increased levels of GHGs, including carbon dioxide and methane, which has led to significant legislative and regulatory efforts to limit GHG emissions.

Congress has from time to time considered legislation to reduce emissions of GHGs and there have been a number of federal regulatory initiatives to address GHG emissions in recent years. These include the establishing of Title V and PSD permitting reviews for GHG emissions from certain large stationary sources that are already major potential sources of certain principal, or criteria, pollutant emissions, and the implementation of a GHG monitoring and reporting program for certain sectors of the natural gas and oil industry, including onshore and production, which includes certain of our operations. Additionally, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs, in which major sources of GHG emissions acquire and surrender emission allowances in return for emitting those GHGs. The outcome of federal and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations to control or restrict emissions, taxes or other charges to deter emissions of GHGs, energy efficiency requirements to reduce demand, or other regulatory actions. For example, the EPA finalized new regulations in 2016 that would set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities in an effort to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025; however, on June 12, 2017 the EPA announced a proposed 2 year stay on fugitive emissions standards “while the agency reconsiders them.” Therefore, the date when and if these standards may become implemented is still not known. If these or any other actions to address GHG emissions do become implemented in the future, they could:

 

result in increased costs associated with our operations;

 

increase other costs to our business;

 

affect the demand for natural gas; and

 

impact the prices we charge our customers.

Adoption of additional federal or state requirements mandating a reduction in GHG emissions could have far-reaching and significant impacts on the energy industry and the U.S. economy. We cannot predict the potential impact of such laws or regulations, or international compacts, on our future consolidated financial condition, results of operations or cash flows. For more information regarding the environmental regulation of our business, see Items 1 & 2. Business and Properties – Environment and Occupational Health and Safety Matters.

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Our business is subject to operating hazards that could result in substantial losses or liabilities that may not be fully covered under our insurance policies. Natural gas, NGLs and oil operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, pipe or cement failures, pipeline ruptures or spills, vandalism, pollution, releases of toxic gases, adverse weather conditions or natural disasters, and other environmental hazards and risks. If any of these hazards occur, we could sustain substantial losses as a result of:

 

injury or loss of life;

 

severe damage to or destruction of property, natural resources and equipment;

 

pollution or other environmental damage;

 

investigatory and cleanup responsibilities;

 

regulatory investigations and penalties or lawsuits;