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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________
 FORM 10-K
________________________________________________________
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
    ACT OF 1934
 For the fiscal year ended December 31, 2020
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: 1-13283
 _________________________________________________________ 
pva-20201231_g1.jpg
PENN VIRGINIA CORPORATION
(Exact name of registrant as specified in its charter)
Virginia 23-1184320
(State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer
Identification Number)
16285 Park Ten Place, Suite 500
Houston, TX 77084
(Address of principal executive offices)
Registrant’s telephone number, including area code: (713722-6500
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s) Name of exchange on which registered
Common Stock, $0.01 Par ValuePVAC Nasdaq Global Select Market
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.      Yes      No  
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes      No  
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes    No  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerAccelerated filerNon-accelerated filerSmaller 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes      No  
The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was $144,297,933 as of June 30, 2020 (the last business day of its most recently completed second fiscal quarter), based on the last sale price of such stock as quoted on the Nasdaq Global Select Market.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.   Yes       No   
As of March 5, 2021, 15,266,598 shares of common stock of the registrant and 225,481.09 shares of Series A Preferred Stock of the registrant (which are redeemable for 22,548,109 shares of common stock) were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement relating to the registrant’s Annual Meeting of Shareholders, to be held on May 3, 2021, are incorporated by reference in Part III of this Form 10-K.



PENN VIRGINIA CORPORATION
ANNUAL REPORT ON FORM 10-K
 For the Fiscal Year Ended December 31, 2020
 Table of Contents
 Page
Forward-Looking Statements
Glossary of Certain Industry Terminology
Part I
Item  
1.Business
1A.Risk Factors
1B.Unresolved Staff Comments
2.Properties
3.Legal Proceedings
4.Mine Safety Disclosures
Part II
   
5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
6.Selected Financial Data
7.Management’s Discussion and Analysis of Financial Condition and Results of Operations: 
 Overview and Executive Summary
 Key Developments
 Financial Condition
 Results of Operations
 Off-Balance Sheet Arrangements
 Contractual Obligations
 Critical Accounting Estimates
7A.Quantitative and Qualitative Disclosures About Market Risk
8.Financial Statements and Supplementary Data
9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
9A.Controls and Procedures
9B.Other Information
Part III
   
10.Directors, Executive Officers and Corporate Governance
11.Executive Compensation
12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
13.Certain Relationships and Related Transactions, and Director Independence
14.Principal Accountant Fees and Services
Part IV
   
15.Exhibits, Financial Statement Schedules
16.Form 10-K Summary
  
Signatures




Forward-Looking Statements
Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We use words such as “anticipate,” “guidance,” “assumptions,” “projects,” “estimates,” “expects,” “continues,” “intends,” “plans,” “believes,” “forecasts,” “future,” “potential,” “may,” “possible,” “could” and variations of such words or similar expressions to identify forward-looking statements. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: 
risks related to the recently completed transactions with Juniper and its affiliates, including the risk that the benefits of the transactions may not be fully realized or may take longer to realize than expected, and that management attention will be diverted to transaction-related issues;
risks related to completed acquisitions, including our ability to realize their expected benefits;
the decline in, sustained market uncertainty of, and volatility of commodity prices for crude oil, natural gas liquids, or NGLs, and natural gas, including the recent dramatic decline of such prices;
the impact of the COVID-19 pandemic, including reduced demand for oil and natural gas, economic slowdown, governmental actions, stay-at-home orders, interruptions to our operations or our customers operations;
risks related to and the impact of actual or anticipated other world health events;
risks related to acquisitions and dispositions, including our ability to realize their expected benefits;
•     our ability to satisfy our short-term and long-term liquidity needs, including our ability to generate sufficient cash
flows from operations or to obtain adequate financing, including access to the capital markets, to fund our capital expenditures and meet working capital needs;
our ability to access capital, including through lending arrangements and the capital markets, as and when desired;
•     negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;
•     plans, objectives, expectations and intentions contained in this report that are not historical;
•     our ability to execute our business plan in volatile and depressed commodity price environments;
•     our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production;
•     changes to our drilling and development program;
•     our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;
•     our ability to meet guidance, market expectations and internal projections, including type curves
•     any impairments, write-downs or write-offs of our reserves or assets;
•     the projected demand for and supply of oil, NGLs and natural gas;
•     our ability to contract for drilling rigs, frac crews, materials, supplies and services at reasonable costs;
•     our ability to renew or replace expiring contracts on acceptable terms;
•     our ability to obtain adequate pipeline transportation capacity or other transportation for our oil and gas production at reasonable cost and to sell our production at, or at reasonable discounts to, market prices;
•     the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from that estimated in our proved oil and gas reserves;
•     use of new techniques in our development, including choke management and longer laterals;
•     drilling, completion and operating risks, including adverse impacts associated with well spacing and a high concentration of activity;
•     our ability to compete effectively against other oil and gas companies;
•     leasehold terms expiring before production can be established and our ability to replace expired leases;
•     environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance;
•     the timing of receipt of necessary regulatory permits;
•     the effect of commodity and financial derivative arrangements with other parties and counterparty risk related to the ability of these parties to meet their future obligations;
•     the occurrence of unusual weather or operating conditions, including force majeure events;
•     our ability to retain or attract senior management and key employees;
our reliance on a limited number of customers and a particular region for substantially all of our revenues and production;
•     compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters;
•     physical, electronic and cybersecurity breaches;
•     uncertainties relating to general domestic and international economic and political conditions;
•     the impact and costs associated with litigation or other legal matters;
•     sustainability initiatives; and
•     other factors set forth in our periodic filings with the Securities and Exchange Commission, or SEC, including the risks set forth in Part I, Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2020.
The effects of the COVID-19 pandemic may give rise to risks that are currently unknown or amplify the risks associated with many of these factors.
Additional information concerning these and other factors can be found in our press releases and public filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable law.
1


Glossary of Certain Industry Terminology
 
The following abbreviations, terms and definitions are commonly used in the oil and gas industry and are used within this Annual Report on Form 10-K.
Bbl. A standard barrel of 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
BOE. One barrel of oil equivalent with six thousand cubic feet of natural gas converted to one barrel of crude oil based on the estimated relative energy content.
BOEPD. Barrels of oil equivalent per day.
Borrowing base. The value assigned to a collection of borrower’s assets used by lenders to determine an initial and/or continuing amount for loans. In the case of oil and gas exploration and development companies, the borrowing base is generally based on proved developed reserves.
Completion. A process of treating a drilled well, including hydraulic fracturing among other stimulation processes, followed by the installation of permanent equipment for the production of oil or gas.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface temperature and pressure.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil or gas in sufficient commercial quantities to justify completion of the well.
EBITDAX. A measure of profitability utilized in the oil and gas industry representing earnings before interest, income taxes, depreciation, depletion, amortization and exploration expenses. EBITDAX is not a defined term or measure in generally accepted accounting principles, or GAAP (see below).
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.
EUR. Estimated ultimate reserves, the sum of reserves remaining as of a given date and cumulative production as of that date.
GAAP. Accounting principles generally accepted in the Unites States of America.
Gas lift. A method of artificial lift that uses an external source of high-pressure gas for supplementing formation gas for lifting the well fluids.
Gross acre or well. An acre or well in which a working interest is owned.
HBP. Held by production is a provision in an oil and gas or mineral lease that perpetuates the leaseholder’s right to operate the property as long as the property produces a minimum paying quantity of oil or gas.
Henry Hub. The Erath, Louisiana settlement point price for natural gas.
LIBOR. London Interbank Offered Rate.
LLS. Light Louisiana Sweet, a crude oil pricing index reference.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet of natural gas.
MEH. Magellan East Houston, a crude oil pricing index reference.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units, a measure of energy content.
MMcf. One million cubic feet of natural gas.
Nasdaq. The Nasdaq Global Select Market.
Net acre or well. The number of gross acres or wells multiplied by the owned working interest in such gross acres or wells.
NGL. Natural gas liquid.
NYMEX. New York Mercantile Exchange.
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Operator. The entity responsible for the exploration and/or production of a lease or well.
Play. A geological formation with potential oil and gas reserves.
Productive wells. Wells that are not dry holes.
Proved reserves. Those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved developed reserves. Proved reserves that can be expected to be recovered: (a) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (b) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
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. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled.
PV10. A non-GAAP measure representing the present value of estimated future oil and gas revenues, net of estimated direct costs, discounted at an annual discount rate of 10%. PV10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for any GAAP measure. PV10 does not purport to represent the fair value of oil and gas properties.
Reservoir. A porous and permeable underground formation containing a natural accumulation of hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Revenue interest. An economic interest in production of hydrocarbons from a specified property.
Royalty interest. An interest in the production of a well entitling the owner to a share of production generally free of the costs of exploration, development and production.
SEC. United States Securities and Exchange Commission.
Service well. A well drilled or completed for the purpose of supporting production in an existing field.
Standardized measure. The present value, discounted at 10% per year, of estimated future cash inflows from the production of proved reserves, computed by applying prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves (except for consideration of future price changes to the extent provided by contractual arrangements in existence at year-end), reduced by estimated future development and production costs, computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year (including the settlement of asset retirement obligations), based on year-end costs and assuming continuation of existing economic conditions, further reduced by estimated future income tax expenses, computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the proved oil and gas reserves, less the tax basis of the properties involved and giving effect to the tax deductions and tax credits and allowances relating to the proved oil and gas reserves.
Unconventional. Generally refers to hydrocarbon reservoirs that lack discrete boundaries that typically define conventional reservoirs. Examples include shales, tight sands or coal beds.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves. Under appropriate circumstances, undeveloped acreage may not be subject to expiration if properly held by production, as that term is defined above.
WTI. West Texas Intermediate, a crude oil pricing index reference.
Working interest. A cost-bearing interest under an oil and gas lease that gives the holder the right to develop and produce the minerals under the lease.
3


RISK FACTOR SUMMARY
The following summarizes the principal factors that make an investment in Penn Virginia speculative or risky, all of which are more fully described in Part I, Item 1A. “Risk Factors” below. This summary should be read in connection with the Risk Factors section and should not be relied upon as an exhaustive summary of the material risks facing our business.
The following factors could materially adversely affect our business, results of operations, financial condition, cash flows, liquidity and the trading price of our common stock.
Risks Associated with our General Business
The direct and indirect effects of the COVID-19 pandemic on our business, financial position, results of operations and/or cash flows, which will depend on future developments that are highly uncertain and cannot be predicted
Prices for crude oil, NGLs and natural gas, which are dependent on many factors that are beyond our control
Risks associated with drilling and operations activities, which are high-risk activities with many uncertainties and may not result in commercially productive reserves
Risks associated with multi-well pad drilling and project development, which may result in volatility in our operating results
Adverse impacts associated with a high concentration of activity and tighter drilling spacing
Our ability to adhere to our proposed drilling schedule
Our dependence on gathering, processing, refining and transportation facilities owned by others
The unavailability, high cost or shortage of drilling rigs, frac crews, equipment, raw materials, supplies, oilfield services or personnel, which may restrict our operations
Our ability to find or acquire additional oil and gas reserves that are economically recoverable
Our ability to attract and retain key members of management, qualified Board members and other key personnel
Our ability to establish production on the acreage of certain of our undeveloped leasehold assets that are subject to leases that will expire over the next several years unless production is developed
Actions we or other operators may take when drilling, completing, or operating wells that they own that may adversely affect certain of our wells
Our exposure to the credit risk of our customers
Our participation in oil and gas leases with third parties, who may not be able to fulfill their commitments to our projects
The accuracy of our estimates of oil and gas reserves and future net cash flows, which are not precise, and undeveloped reserves, which may not ultimately be converted into proved producing reserves
The incurrence of impairments on our oil and gas properties
Our ability to obtain sufficient capital
Risks associated with property acquisitions
Losses resulting from title deficiencies
Difficulties associated with being a small company competing in a larger market
Our lack of diversification and risks associated with operating primarily in one major contiguous area
Operating risks, including risks associated with hydraulic fracturing
Financial and Related Risks
Our substantial indebtedness
A reduction in our borrowing base
Restrictive covenants under the Credit Facility and the Second Lien Facility, which could limit our financial flexibility
Derivative transactions, which may limit our potential gains and involve other risks
Investor sentiment towards the oil and gas industry, which could adversely affect our ability to raise equity and debt capital
Legal and Regulatory Risks
Various laws and regulations that could adversely affect the cost, manner or feasibility of doing business, including climate change legislation, laws and regulations restricting emissions of greenhouse gases or prohibiting, restricting, or delaying oil and gas development on public lands, and federal state and local legislation and regulatory initiatives relating to hydraulic fracturing
Our ability to access water to drill and conduct hydraulic fracturing and difficulties associated with disposing of produced water gathered from drilling and production activities
Risks associated with legal proceedings

4


Tax-Related Risks
Our ability to use net operating loss carryforwards to offset future taxable income, which may be subject to certain limitations
The continued availability of certain federal income tax deductions with respect to oil and gas exploration and development
Technology-Related Risks
Our ability to keep pace with technological developments in our industry
Risks relating to cybersecurity incidents

Risks Related to Ownership of Our Common Stock
Risks associated with Juniper’s control of the Company, including potential conflicts between Juniper’s interests and the interests of the Company and its stockholders
Certain provisions of our certificate of incorporation and our bylaws that may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial
The volatility of the market price of our common stock
The actions of so-called “activist” shareholders, which could impact the trading value of our securities
Future sales or other dilution of our equity, which may adversely affect the market price of our common stock

5


Part I
Item 1    Business
Unless the context requires otherwise, references to the “Company,” “Penn Virginia,” “we,” “us” or “our” in this Annual Report on Form 10-K refer to Penn Virginia Corporation and its subsidiaries.
Description of Business
General
We are an independent oil and gas company engaged in the onshore exploration, development and production of crude oil, NGLs and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale, or the Eagle Ford, in Gonzales, Lavaca, Fayette and DeWitt Counties in South Texas.
We were incorporated in the Commonwealth of Virginia in 1882. Our common stock is publicly traded on the Nasdaq under the symbol “PVAC.” Our headquarters and corporate office is located in Houston, Texas. We also have a field operations office near our Eagle Ford assets in South Texas.
We operate in and report our financial results and disclosures as one segment, which is the exploration, development and production of crude oil, NGLs and natural gas.
Juniper Transactions
At a special meeting held on January 13, 2021, the Company’s shareholders approved the potential issuance of up to 22,597,757 shares of our common stock, par value $0.01 per share, or the Common Stock, upon the redemption or exchange of up to 225,977.57 shares of Series A Preferred Stock, par value $0.01 per share, of the Company, or the Series A Preferred Stock, together with up to 22,597,757 common units representing limited partner interests (the “Common Units”) of PV Energy Holdings, L.P. (the “Partnership”). On January 14, 2021, the Company amended its articles of incorporation (the “Articles of Amendment”) creating a series of the Company’s preferred stock consisting of 300,000 shares and designated as the Series A Preferred Stock, as well as establishing the powers, preferences and rights of the preferred stock series and the qualifications, limitations and restrictions thereof.
On January 15, 2021, or the Closing Date, the Company consummated the previously announced transactions,(collectively, the “Juniper Transactions”), contemplated by: (i) the Contribution Agreement, dated November 2, 2020 (the “Contribution Agreement”), by and among the Company, the Partnership, and JSTX Holdings, LLC, or JSTX, an affiliate of Juniper Capital Advisors, L.P. (“Juniper Capital”), and, together with its affiliates (“Juniper”); and (ii) the Contribution Agreement, dated November 2, 2020 (the “Asset Agreement”, and, together with the Contribution Agreement, the Juniper Transaction Agreements), by and among Rocky Creek Resources, LLC, an affiliate of Juniper Capital (“Rocky Creek”), the Company and the Partnership.
In connection with the consummation of the Juniper Transactions, the Company completed a reorganization into an up-C structure, or the Reorganization (which is intended to, among other things, result in the holders of the Series A Preferred Stock, having a voting interest in the Company that is commensurate with such holders’ economic interest in the Partnership), including (i) the conversion of each of the Company’s corporate subsidiaries into limited liability companies which are disregarded for U.S. federal income tax purposes, including the conversion of Penn Virginia Holding Corp. into Penn Virginia Holdings, LLC, a Delaware limited liability company, or Holdings, and (ii) the Company’s contribution of all of its equity interests in Holdings to the Partnership in exchange for 15,268,686 newly issued Common Units.
On the Closing Date, (i) pursuant to the terms of the Contribution Agreement, JSTX contributed to the Partnership, as a capital contribution, $150 million in cash in exchange for 17,142,857 newly issued Common Units and the Company issued to JSTX 171,428.57 shares of Series A Preferred Stock at a price equal to the par value of the shares acquired, and (ii) pursuant to the terms of the Asset Agreement, Rocky Creek contributed to our operating subsidiary certain oil and gas assets in exchange for 5,405,252 newly issued Common Units and the Company issued to Rocky Creek 54,052.52 shares of Series A Preferred Stock at a price equal to the par value of the shares acquired, including 495,900 Common Units and 4,959 shares of Series A Preferred Stock placed in an indemnity escrow to support post-closing indemnification claims, 50% of such escrowed amount to be disbursed on July 14, 2021 and the remainder on January 15, 2022.

6


On the Closing Date, in connection with and upon the consummation of the Juniper Transactions, the general partner of the Partnership, entered into that certain Amended and Restated Agreement of Limited Partnership of the Partnership, dated January 15, 2021, or the A&R Partnership Agreement, with the Company, JSTX, and Rocky Creek, as limited partners, to provide for or reflect, among other things:
the admission of JSTX and Rocky Creek as limited partners;
the recapitalization of the Partnership into the Common Units; and
the redemption right of each limited partner (other than the Company), which entitles such limited partner to cause the Partnership to redeem, from time to time on or after the date that is 180 days after the Closing Date, all or a portion of its Common Units (together with one one-hundredth (1/100th) of a share of Series A Preferred Stock for each Common Unit to be redeemed), in exchange for, at the Partnership’s option, shares of Common Stock, on a one-for-one basis or a cash payment equal to the average of the volume-weighted closing price of one share of Common Stock for the five trading days prior to the date the limited partner delivers a notice of redemption for each the Common Unit redeemed (subject to customary adjustments, including for stock splits, stock dividends and reclassifications).
On the Closing Date, in connection with the consummation of the Juniper Transactions, the Company, JSTX and Rocky Creek entered into that certain Investor and Registration Rights Agreement, dated January 15, 2021, or the Investor Agreement, providing for, together with the Articles of Amendment, certain rights and obligations with respect to the governance of the Company, including rights to nominate a number of members of the Company’s board of directors, or the Board, based on Juniper’s beneficial ownership of the Company, and certain registration rights with respect to the Common Stock issuable upon redemption of the Common Units and Series A Preferred Stock pursuant to the A&R Partnership Agreement.
On the Closing Date, in accordance with the Articles of Amendment and the Investor Agreement, the Board was increased from four members to nine members, and Juniper designated five new members to the Board (the directors from time to time appointed to the Board pursuant to Juniper’s rights under the Investor Agreement and Articles of Amendment, the “Investor Directors”).
Juniper and its permitted transferees shall continue to have the right to appoint Investor Directors to the Board and to have Investor Directors sit on certain committees of the Board for so long as Juniper continuously owns Common Stock (or Common Units and shares of Series A Preferred Stock redeemable or exchangeable therefor), subject to applicable law, stock exchange rules and step-downs in the number of directors Juniper may designate based on Juniper’s beneficial ownership of the Company’s voting power. Pursuant to the Investor Agreement, Juniper has also agreed to vote in favor of the nominees proposed by the Nominating & Governance Committee of the Board at the Company’s 2021 Annual Meeting of Shareholders.
Concurrent with the closing of the Juniper Transactions, on the Closing Date, the following transactions occurred: (i) the Agreement and Amendment No. 9 to Credit Agreement, or the Ninth Amendment, to the credit agreement, or Credit Facility, became effective and a prepayment of $80.5 million of outstanding borrowings under the Credit Facility was made plus accrued interest of $0.1 million, (ii) the amendment dated November 2, 2020 (the “Second Lien Amendment”) to the Second Lien Credit Agreement dated as of September 29, 2017, or the Second Lien Facility, became effective and a prepayment of $50.0 million of outstanding advances under the Second Lien Facility was made plus accrued interest of $0.2 million in accordance with the Second Lien Amendment, (iii) total payments of $17.8 million in cash were completed for transaction and debt issue costs, including (A) $16.0 million associated with the Juniper Transactions, (B) $1.4 million associated with the Second Lien Amendment and (C) $0.4 million associated with the Ninth Amendment and (iv) a combined payment of $1.3 million including principal and accrued interest was made to liquidate the outstanding advances attributable to a single participant lender.

7


On March 5, 2021, the Company had outstanding 15,266,598 shares of Common Stock and 225,481.09 shares of Series A Preferred Stock. Holders of the Company’s Common Stock owned approximately 40 percent of the total voting power and economic interest in the Company, and Juniper, through JSTX and Rocky Creek, owned approximately 60 percent of the total voting power and economic interest in the Company through the Series A Preferred Stock and Common Units.
pva-20201231_g2.jpg
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(1)    The Common Units are economic interests of the Partnership and the Series A Preferred Stock are non-economic voting interests in the Company.
(2)    Represented by JSTX and Rock Creek.
Each 1/100th of a share of Series A Preferred Stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Common Stock and Series A Preferred Stock vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our Articles of Incorporation, as amended. As discussed above, under the A&R Partnership Agreement, each holder of Common Units has the right to cause the Company to redeem on or after the date that is 180 days after the Closing Date, all or a portion of its Common Units (together with one one-hundredth (1/100th) of a share of Series A Preferred Stock for each Common Unit to be redeemed), in exchange for, at the Partnership’s option, shares of Common Stock, on a one-for-one basis, or cash. However, because Penn Virginia is a holding company with no independent means of generating revenues and the assets of the consolidated Company all reside in operating subsidiaries, the holders of Common Units would be entitled to participate in any cash distribution from the Company’s operating subsidiaries whether or not they convert their Common Units into Common Stock.
For additional information regarding the Juniper Transactions, the Ninth Amendment, the Second Lien Amendment and the transaction costs associated therewith, see Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7 that follows and Notes 2 and 9 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” Additionally, for a discussion of certain risks relating to our organizational structure following the Juniper Transactions, see Risk Factors - Penn Virginia is a holding company. Penn Virginia’s only material asset is its equity interest in the Partnership, and Penn Virginia is accordingly dependent upon distributions from the Partnership to pay taxes and cover its operating expenses and other obligations. in Part I, Item 1A that follows.

8


Current Operations
Including the properties contributed by Rocky Creek in connection with the Asset Agreement, we lease a highly contiguous position of approximately 102,100 gross (90,100 net) acres as of March 5, 2021 in the core liquids-rich area or “volatile oil window” of the Eagle Ford in Gonzales, Lavaca, Fayette and Dewitt Counties in Texas, which we believe contains a substantial number of drilling locations that will support a multi-year drilling inventory.
In 2020, our total sales volume was comprised of 77 percent crude oil, 13 percent NGLs and 10 percent natural gas. Crude oil accounted for 93 percent of our product revenues. We generally sell our crude oil, NGL and natural gas products using short-term floating price physical and spot market contracts.
As of December 31, 2020, our total proved reserves were approximately 126 MMBOE, of which 40 percent were proved developed reserves and 78 percent were crude oil. As of December 31, 2020, we had 532 gross (451.3 net) productive wells, approximately 98 percent of which we operate, and leased approximately 98,300 gross (86,300 net) acres of leasehold and royalty interests, approximately 7 percent of which were undeveloped. Approximately 93 percent of our total acreage was HBP and included a substantial number of undrilled locations. During 2020, we drilled, completed and turned to sales 23 gross (20.6 net) wells. For additional information regarding our production, reserves, drilling activities, wells and acreage, see Part I, Item 2, “Properties.”
In 2018, we completed the acquisition of certain oil and gas assets from Hunt Oil Company, or Hunt, including oil and gas leases covering approximately 9,700 net acres located primarily in Gonzales and Lavaca Counties, Texas, or the Hunt Acquisition. For additional information regarding this transaction, see Note 4 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
Key Contractual Arrangements
In the ordinary course of operating our business, we enter into a number of key contracts for services that are critical with respect to our ability to develop, produce, store and bring our production to market. The following is a summary of our most significant contractual arrangements.
Drilling and Completion. From time to time we enter into drilling, completion and materials contracts in the ordinary course of business to ensure availability of rigs, frac crews and materials to satisfy our development program. As of December 31, 2020, there were no drilling, completion or materials agreements with terms that extended beyond one year.
Crude oil gathering and transportation service contracts. We have long-term agreements that provide us with field gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production through February 2041 and February 2026, respectively, as well as volume capacity support for certain downstream interstate pipeline transportation.
Crude oil storage. Through April 2021, we have access of up to a maximum of 520,000 barrels of tank capacity at a number of locations in the South Texas region with three vendors including up to approximately 250,000 barrels (180,000 barrels as a component of the crude oil gathering agreement referenced above) at the service provider’s central delivery point facility, or CDP, in Lavaca County, Texas, up to 90,000 barrels with a downstream interstate pipeline at their facility in DeWitt County, Texas and up to 62,000 barrels with a marketing affiliate of the aforementioned downstream interstate pipeline within their system on a firm basis and an additional 120,000 barrels, if available, on a flexible basis through April 2021. For additional information relating to crude oil storage see Note 14 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
Natural gas service contracts. We have an agreement that provides us with field gathering, compression and short-haul transportation services for a substantial portion of our natural gas production and gas lift for all of our hydrocarbon production until 2039.
Natural gas processing contracts. We have two agreements that provide us with services to process our wet gas production into NGL products and dry, or residue, gas. The more significant of these agreements extends through June 2029 while the other agreement, which represents a minor portion of our total processing requirements, is evergreen in term with either party having the right to terminate with 30-days’ notice to the counterparty.
Major Customers
We sell a significant portion of our oil and gas production to a relatively small number of customers. For the year ended December 31, 2020, approximately 56 percent of our consolidated product revenues were attributable to three customers, each of whom accounted for at least 10 percent: Phillips 66 Company; BP Products North America Inc. and Shell Trading (US) Company. There were no other customers that individually accounted for more than 10 percent of our consolidated product revenues.

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Seasonality
Our sales volumes of crude oil and natural gas are dependent upon the number of producing wells and, therefore, are not seasonal by nature. We do not believe that the pricing of our crude oil and NGL production is subject to any meaningful seasonal effects. Historically, the pricing of natural gas is seasonal, typically with higher pricing in the winter months.
Competition
The oil and gas industry is very competitive, and we compete with a substantial number of other companies, many of which are large, well-established and have greater financial and operational resources than we do. Some of our competitors not only engage in the acquisition, exploration, development and production of oil and gas reserves, but also carry on refining operations, electricity generation and the marketing of refined products. In addition, the oil and gas industry in general competes with other industries supplying energy and fuel to industrial, commercial and individual consumers. Competition is particularly intense in the acquisition of prospective oil and gas properties. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. We also compete with other oil and gas companies to secure drilling rigs, frac fleets, sand and other equipment and materials necessary for the drilling and completion of wells and in the recruiting and retaining of qualified personnel. Such materials, equipment and labor may be in short supply from time to time. Shortages of equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed. Many of our larger competitors may have a competitive advantage when responding to commodity price volatility and overall industry cycles.
Government Regulation and Environmental Matters
Our operations are subject to extensive federal, state and local laws and regulations that govern oil and gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. These laws, rules and regulations may, among other things:
require the acquisition of various permits before drilling commences;
require notice to stakeholders of proposed and ongoing operations;
require the installation of expensive pollution control equipment;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling and production and saltwater disposal activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources; and
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities for failure to comply. Violations and liabilities with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and cash flows. In certain instances, citizens or citizen groups also have the ability to bring legal proceedings against us if we are not in compliance with environmental laws or to challenge our ability to receive environmental permits that we need to operate. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of December 31, 2020, we have recorded asset retirement obligations of $5.5 million attributable to these activities. The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general.
We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition, results of operations or cash flows. Nevertheless, changes in existing environmental laws or regulations or the adoption of new environmental laws or regulations, including any significant limitation on the use of hydraulic fracturing or the ability to conduct oil and gas development could have the potential to adversely affect our financial condition, results of operations and cash flows. Federal, state or local administrative decisions, developments in the federal or state court systems or other governmental or judicial actions may influence the interpretation or enforcement of environmental laws and regulations and may thereby increase compliance costs. Environmental regulations have historically become more stringent over time, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation.
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The following is a summary of the significant environmental laws to which our business operations are subject.
CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, is also known as the “Superfund” law. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on parties that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Such “responsible parties” may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own or lease properties that have been used for the exploration and production of oil and gas for a number of years. Many of these properties have been operated by third parties whose treatment or release of hydrocarbons or other wastes was not under our control. These properties, and any wastes that may have been released on them, may be subject to CERCLA, and we could potentially be required to investigate and remediate such properties, including soil or groundwater contamination by prior owners or operators, or to perform remedial plugging or pit closure operations to prevent future contamination. States also have environmental cleanup laws analogous to CERCLA, including Texas.
RCRA. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, the individual states administer some or all of the provisions of RCRA. While there is currently an exclusion from RCRA for drilling fluids, produced waters and most of the other wastes associated with the exploration and production of oil or gas, it is possible that some of these wastes could be classified as hazardous waste in the future and therefore be subject to more stringent regulation under RCRA. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes if such wastes have hazardous characteristics.
Oil Pollution Act. The Oil Pollution Act of 1990, or the OPA, contains numerous restrictions relating to the prevention of and response to oil spills into waters of the United States. The term “waters of the United States” has been interpreted broadly to include inland water bodies, including wetlands and intermittent streams. The OPA imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs, and certain other damages arising from a spill. As such, a violation of the OPA has the potential to adversely affect our business, financial condition, results of operations and cash flows.
Clean Water Act. The Federal Water Pollution Control Act, or the Clean Water Act, and comparable state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into regulated waters, such as waters of the United States. The discharge of pollutants, including dredge or fill materials in regulated wetlands, into regulated waters or wetlands without a permit issued by the EPA, the U.S. Army Corps of Engineers, or the Corps, or the state is prohibited. The Clean Water Act has been interpreted by these agencies to apply broadly. The EPA and the Corps released a rule to revise the definition of “waters of the United States,” or WOTUS, for all Clean Water Act programs, which went into effect in August 2015. However, the EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule in 2020. The Navigable Waters Protection Rule defined what waters qualify as navigable waters of the United States and are under Clean Water Act jurisdiction. This new rule has generally been viewed as narrowing the scope of waters of the United States as compared to the 2015 rule, but litigation in multiple federal district courts is currently challenging the rescission of the 2015 rule and the promulgation of the Navigable Waters Protection Rule.
The Clean Water Act also requires the preparation and implementation of Spill Prevention, Control and Countermeasure Plans in connection with on-site storage of significant quantities of oil. In 2016, the EPA finalized new wastewater pretreatment standards that would prohibit onshore unconventional oil and gas extraction facilities from sending wastewater to publicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste may result in increased costs. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

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Safe Drinking Water Act. The Safe Drinking Water Act, or the SDWA, and the Underground Injection Control Program promulgated under the SDWA, establish the requirements for salt water disposal well activities and prohibit the migration of fluid-containing contaminants into underground sources of drinking water. The Underground Injection Well Program requires that we obtain permits from the EPA or delegated state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities of fluids that may be injected and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources, and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages, and personal injuries. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells, and regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the Texas Railroad Commission, or TRC, adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. TRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismic activity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays.
We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells in which we act as operator. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional plays like the Eagle Ford formation, and is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The EPA also released the results of its comprehensive research study to investigate the potential adverse impacts of hydraulic fracturing on drinking water and ground water in December 2016, finding that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. These developments could establish an additional level of regulation, including a removal of the exemption for hydraulic fracturing from the SDWA, and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating and compliance costs and additional regulatory burdens that could make it more difficult or commercially impracticable for us to perform hydraulic fracturing. Such costs and burdens could delay the development of unconventional gas resources from shale formations, which are not commercially feasible without the use of hydraulic fracturing.
Chemical Disclosures Related to Hydraulic Fracturing. Texas has implemented chemical disclosure requirements for hydraulic fracturing operations. We currently disclose hydraulic fracturing additives we use on www.FracFocus.org, a website created by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission.
Prohibitions and Other Regulatory Limitations on Hydraulic Fracturing. There have been a variety of regulatory initiatives at the state level to restrict oil and gas drilling operations in certain locations.
In addition to chemical disclosure rules, some states have implemented permitting, well construction or water withdrawal regulations that may increase the costs of hydraulic fracturing operations. For example, Texas has water withdrawal restrictions allowing suspension of withdrawal rights in times of shortages while other states require reporting on the amount of water used and its source.

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Increased regulation of and attention given by environmental interest groups, as well as state and federal regulatory authorities, to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. These developments could also lead to litigation challenging proposed or existing wells. The adoption of federal, state or local laws or the implementation of regulations regarding hydraulic fracturing that are more stringent could cause a decrease in the completion of new oil and gas wells, as well as increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows. We use hydraulic fracturing extensively and any increased federal, state, or local regulation of hydraulic fracturing could reduce the volumes of oil and gas that we can economically recover.
Clean Air Act. Our operations are subject to the Clean Air Act, or the CAA, and comparable state and local requirements. In 1990, the U.S. Congress adopted amendments to the CAA containing provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have developed, and continue to develop, regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Further, stricter requirements could negatively impact our production and operations. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.
On April 17, 2012, for example, the EPA issued final rules to subject oil and gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. Further, in May 2016, the EPA issued final NSPS governing methane emissions from the oil and gas industry as well as source determination standards for determining when oil and gas sources should be aggregated for CAA permitting and compliance purposes. However, in August 2020 the EPA rescinded methane and volatile organic compound emissions standards for new and modified oil and gas transmission and storage infrastructure, as well as methane limits for new and modified oil and gas production and processing equipment. The EPA also relaxed requirements for oil and gas operators to monitor emissions leaks. In President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis, President Biden directed the EPA to consider suspending, rescinding, or revising the Trump Administration’s NSPS rule for the oil and gas sector. The U.S. Bureau of Land Management, or BLM, finalized its own rules in November 2016 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements. The BLM subsequently announced a revised rule which would scale back the waste-prevention requirements of the 2016 rule, but this revised rule was vacated by a California federal district court in 2020, a decision which BLM has appealed to the Ninth Circuit Court of Appeals. However, separately, the federal district court of Wyoming vacated the original 2016 rule in October 2020. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA had announced in 2016 an intent to impose methane emission standards for existing sources, but the agency was sued by multiple states for failing to implement these standards following the agency’s withdrawal of information collection requests for oil and gas facilities. These rules would result in an increase to our operating costs and change to our operations. As a result of this continued regulatory focus, future federal and state regulations of the oil and gas industry remain a possibility and could result in increased compliance costs on our operations.
In November 2015, the EPA revised the existing National Ambient Air Quality Standards for ground level ozone to make the standard more stringent. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as non-attainment, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. Generally, it will take the states several years to develop compliance plans for their non-attainment areas. While we are not able to determine the extent to which this new standard will impact our business at this time, it has the potential to have a material impact on our operations and cost structure.
In June 2016, the EPA finalized a rule “aggregating” individual wells and other facilities and their collective emissions for purposes of determining whether major source permitting requirements apply under the CAA. These changes may introduce uncertainty into the permitting process and could require more lengthy and costly permitting processes and more expensive emission controls.

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Collectively, these rules and proposed rules, as well as any future laws and their implementing regulations, may require a number of modifications to our operations. We may, for example, be required to install new equipment to control emissions from our well sites or compressors at initial startup or by the applicable compliance deadline. We may also be required to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
Greenhouse Gas Emissions. In response to findings that emissions of carbon dioxide, methane and other GHGs, present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of GHGs under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources.
Both in the United States and worldwide, there is increasing attention being paid to the issue of climate change and the contributing effect of GHG emissions. Most recently in April 2016, the United States signed the Paris Agreement, which requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. In 2020, the Trump administration withdrew the United States from the Paris Agreement, but under the direction of President Biden, the United States rejoined the Paris Agreement in February 2021. President Biden is likely to update the U.S.’s nationally determined contributions and take executive action or support legislation in furtherance of achieving the U.S.’s GHG emissions goals.
In August 2015, the EPA issued new regulations limiting carbon dioxide emissions from existing power generation facilities. Under this rule, nationwide carbon dioxide emissions would be reduced by approximately 30 percent from 2005 levels by 2030 with a flexible interim goal. Several industry groups and states challenged the rule. On February 9, 2016, the U.S. Supreme Court stayed the implementation of this rule pending judicial review. In August 2019, the EPA finalized the repeal of the 2015 regulations and replaced them with the Affordable Clean Energy rule, or ACE, that designates heat rate improvement, or efficiency improvement, as the best system of emissions reduction for carbon dioxide from existing coal-fired electric utility generating units. However, in January 2020, the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE rule and ruled that the repeal of the Obama-era regulations should also be vacated; the court is delaying issuing the latter vacatur mandate until such time that the EPA responds to the court’s decision through a new rulemaking action. Thus, the Biden Administration’s EPA is likely to promulgate a new replacement for the 2015 regulations.
The EPA has issued the “Final Mandatory Reporting of Greenhouse Gases” Rule and a series of revisions to it, which requires operators of oil and gas production, natural gas processing, transmission, distribution and storage facilities and other stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions occurring in the prior calendar year on a facility-by-facility basis. These rules do not require control of GHGs. However, the EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG limits.
In certain circumstances, large sources of GHG emissions are subject to preconstruction permitting under the EPA’s Prevention of Significant Deterioration program. This program historically has had minimal applicability to the oil and gas production industry. However, there can be no assurance that our operations will avoid applicability of these or similar permitting requirements, which impose costs relating to emissions control systems and the efforts needed to obtain the permit.
Additional GHG regulations potentially affecting our industry include those described above under the subheading “Clean Air Act” which relate to methane.
Future federal GHG regulations of the oil and gas industry remain a possibility. Also, many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities. Many states have established GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. While it is not possible to predict how any regulations to restrict GHG emissions may come into force, these and other legislative and regulatory proposals for restricting GHG emissions or otherwise addressing climate change could require us to incur additional operating costs or curtail oil and gas operations in certain areas and could also adversely affect demand for the oil and gas we sell.

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President Biden and the Democratic Party, which currently controls Congress, have identified climate change as a priority, and it is likely that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, delaying or restricting oil and gas development activities in certain areas, will be proposed and/or promulgated during the Biden Administration. For example, the acting Secretary of the Department of the Interior recently issued an order preventing staff from producing any new fossil fuel leases or permits without sign-off from a top political appointee, and President Biden recently announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. President Biden’s order also established climate change as a primary foreign policy and national security consideration, affirms that achieving net-zero greenhouse gas emissions by or before midcentury is a critical priority, affirms President Biden’s desire to establish the United States as a leader in addressing climate change, generally further integrates climate change and environmental justice considerations into government agencies’ decision making, and eliminates fossil fuel subsidies, among other measures.
Finally, 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, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.
OSHA. We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations, and the provision of such information to employees, state and local government authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations.
Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered species or their habitats. While some of our facilities are in areas that may be designated as a habitat for endangered species, we believe that we are in substantial compliance with the Endangered Species Act. The presence of any protected species or the final designation of previously unprotected species as threatened or endangered in areas where we operate could result in increased costs from species protection measures or could result in limitations, delays, or prohibitions on our exploration and production activities that could have an adverse effect on our ability to develop and produce our reserves. Similar protections are given to bald and golden eagles under the Bald and Golden Eagle Protection Act and to migratory birds under the Migratory Bird Treaty Act, and similar protections may be available to certain species protected under state laws.
National Environmental Policy Act. Oil and gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the U.S. Department of Interior, 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 of 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. This process has the potential to delay or even halt development of some of our oil and gas projects.
Employees
We had a total of 87 employees as of December 31, 2020, all of whom were full-time employees. The total as of December 31, 2020 represented a decline from 94 employees as of December 31, 2019 due primarily to a limited reduction-in-force, or RIF, during the third quarter of 2020.
Available Information
Our internet address is http://www.pennvirginia.com. We make available free of charge on or through our website our Corporate Governance Principles, Code of Business Conduct and Ethics, Audit Committee Charter, Compensation and Benefits Committee Charter, Nominating and Governance Committee Charter and Reserves Committee Charter, and we will provide copies of such documents to any shareholder who so requests. We also make available free of charge on or through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Investors can obtain current and important information about the company from our website on a regular basis. The 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 or any other report that we furnish or file with the SEC. We intend for our website to serve as a means of public dissemination of information for purposes of Regulation FD.
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Item 1A    Risk Factors
Our business and operations are subject to a number of risks and uncertainties as described below; however, the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we may currently deem immaterial, may become important factors that harm our business, financial condition, results of operations and cash flows in the future. If any of the following risks actually occur, our business, financial condition, results of operations and cash flows could suffer and the trading price of our common stock could decline.
Risks Associated with our General Business
The COVID-19 pandemic has adversely affected our business, and the ultimate effect on our business, financial position, results of operations and/or cash flows will depend on future developments, which are highly uncertain and cannot be predicted.
The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, and created significant volatility and disruption of financial and commodity markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. As a result, there has been a significant reduction in demand for and prices of oil, NGLs and natural gas, which has adversely impacted, and is expected to continue to adversely impact, our business, financial position, results of operations and cash flows. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including how the pandemic and measures taken in response to the pandemic impact demand for oil, NGLs and natural gas, the availability of personnel, equipment and services critical to our ability to operate our properties and the impact of potential governmental restrictions on travel, transports and operations.
There is uncertainty around the extent and duration of the disruption. The degree to which the COVID-19 pandemic continues to adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, including the impact of coronavirus mutations and resurgences, its severity, the actions to contain the virus or treat its impact, the development, availability and public acceptance of effective treatments or vaccines, its impact on the U.S. and world economies, the U.S. capital markets and market conditions, the availability of federal, state, or local funding programs, and how quickly and to what extent normal economic and operating conditions can resume.
Prices for crude oil, NGLs and natural gas are dependent on many factors that are beyond our control and strongly affect our financial condition, results of operations and cash flows.
Prices for crude oil, NGLs and natural gas are dependent on many factors that are beyond our control, including:
domestic and foreign supplies of crude oil, NGLs and natural gas;
domestic and foreign consumer demand for crude oil, NGLs and natural gas;
political and economic conditions in oil or gas producing regions;
the extent to which the members of the Organization of Petroleum Exporting Countries and other oil exporting nations (“OPEC+”) agree upon and maintain production constraints and oil price controls;
overall domestic and foreign economic conditions, including adverse conditions driven by political, health or weather events;
prices and availability of, and demand for, alternative fuels;
the effect of energy conservation efforts, alternative fuel requirements and climate change-related initiatives;
shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil, natural gas and NGLs so as to minimize emissions of carbon dioxide and methane GHGs;
volatility and trading patterns in the commodity-futures markets;
technological advances or social attitudes and policies affecting energy consumption and energy supply;
political and economic events that directly or indirectly impact the relative strength or weakness of the United States dollar, on which crude oil prices are benchmarked globally, against foreign currencies;
changes in trade relations and policies, including the imposition of tariffs by the United States or China;
risks related to the concentration of our operations in the Eagle Ford Shale field in South Texas;
speculation by investors in oil and gas;
the availability, cost, proximity and capacity of gathering, processing, refining and transportation facilities;
the cost and availability of products and personnel needed for us to produce oil and gas;
weather conditions;
the impact and uncertainty of world health events, including the COVID-19 pandemic; and
domestic and foreign governmental relations, regulation and taxation, including limits on the United States’ ability to export crude oil.

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For example, oil and natural gas prices continued to be volatile in 2020, as the slowdown in global economic activity attributable to COVID-19 resulted in a dramatic decline in the demand for energy, including significantly reduced demand for our products. The NYMEX oil prices in 2020 ranged from a high of $63.27 to a low of $(37.63) per Bbl while the spot market prices for natural gas prices in 2020 ranged from a high of $3.08 to a low of $1.34 per MMBtu. Further, these prices ranged from highs to lows of $66.40 to $47.47 per Bbl and $23.86 to $2.45 per MMBtu, respectively, during the period from January 1, 2021 to March 5, 2021. Though declining U.S. production has helped mitigate the supply and demand imbalance experienced during 2020, we expect that oil prices in the near term will continue to be influenced by the duration and severity of the COVID-19 pandemic and its resulting impact on oil and natural gas demand, the extent to which countries abide by the OPEC+ production agreement and U.S. production levels.
The long-term effects of these and other conditions on the prices of oil and natural gas are uncertain, and there can be no assurance that the demand or pricing for our products will follow historic patterns or recover meaningfully in the near term. Any substantial or extended decline, or sustained market uncertainty, in the actual prices of crude oil, NGLs or natural gas would have a material adverse effect on our business, financial position, results of operations, cash flows and borrowing capacity, stock price, the quantities of oil and gas reserves that we can economically produce, the quantity of estimated proved reserves that may be attributed to our properties and our ability to fund our capital program.
It is impossible to predict future commodity price movements with certainty; however, many of our projections and estimates are based on assumptions as to the future prices of crude oil, NGLs and natural gas. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future will likely differ from our estimates.
Drilling and operations activities are high-risk activities with many uncertainties and may not result in commercially productive reserves.
Our future financial condition and results of operations depend on the success of our exploration and production activities. Oil and gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and gas production. The costs of drilling, completing and operating wells are often substantial and uncertain, and drilling and completion operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including:
unexpected drilling conditions;
the use of multi-well pad drilling that requires the drilling of all of the wells on a pad until any one of the pad’s wells can be brought into production;
risks associated with drilling horizontal wells and extended lateral lengths, such as deviating from the desired drilling zone or not running casing or tools consistently through the wellbore, particularly as lateral lengths get longer;
risks associated with downspacing and multi-well pad drilling;
fracture stimulation accidents or failures;
reductions in oil, natural gas and NGL prices;
elevated pressure or irregularities in geologic formations;
loss of title or other title related issues;
equipment failures or accidents;
costs, shortages or delays in the availability of drilling rigs, frac fleets, crews, equipment and materials;
shortages in experienced labor;
crude oil, NGLs or natural gas gathering, transportation, processing, storage and export facility availability
restrictions or limitations;
surface access restrictions;
delays imposed by or resulting from compliance with regulatory requirements, including any hydraulic fracturing regulations and other applicable regulations, and the failure to secure or delays in securing necessary regulatory, contractual and third-party approvals and permits;
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
limited availability of financing at acceptable terms;
limitations in the market for crude oil, natural gas and NGLs;
fires, explosions, blow-outs and surface cratering;
adverse weather conditions; and
actions by third-party operators of our properties.

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The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. The type curves we use in our development plans from time to time are only estimates of performance of the acreage we might develop and actual production can differ materially. Furthermore, the cost of drilling, completing, equipping and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical or less economical than forecasted. In addition, limitations on the use of hydraulic fracturing could have an adverse effect on our ability to develop and produce oil and gas from new wells, which would reduce our rate of return on these wells and our cash flows. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling costs.
Our future drilling activities may not be successful, and we cannot be sure that our overall drilling success rate or our drilling success rate within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on our business, financial condition, results of operations and cash flows. Also, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or gas from all of them.
Our business involves many operating risks, including hydraulic fracturing, that may result in substantial losses for which insurance may be unavailable or inadequate.
Our operations are subject to all of the risks and hazards typically associated with the exploitation, development and exploration for and the production and transportation of oil and gas, including well stimulation and completion activities such as hydraulic fracturing. These operating risks include:
fires, explosions, blowouts, cratering and casing collapses;
formations with abnormal pressures or structures;
pipeline ruptures or spills;
mechanical difficulties, such as stuck oilfield drilling and service tools;
uncontrollable flows of oil, natural gas or well fluids;
migration of fracturing fluids into surrounding groundwater;
spills or releases of fracturing fluids including from trucks sometimes used to deliver these materials;
spills or releases of brine or other produced water that may go off-site;
subsurface conditions that prevent us from (i) stimulating the planned number of stages, (ii) accessing the entirety of the wellbore with our tools during completion or (iii) removing all fracturing-related materials from the wellbore to allow production to begin;
environmental hazards such as natural gas leaks, oil or produced water spills and discharges of toxic gases; and
natural disasters and other adverse weather conditions, terrorism, vandalism and physical, electronic and cyber security breaches.
Any of these risks could result in substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, clean up responsibilities, regulatory investigations and penalties, loss of well location, acreage, expected production and related reserves and suspension of operations. In addition, under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.
If we experience any problems with well stimulation and completion activities, such as hydraulic fracturing, our ability to explore for and produce oil or natural gas may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations as a result of:
delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements, which may include limitations on hydraulic fracturing or the discharge of GHGs;
the need to shut down, abandon and relocate drilling operations;
the need to sample, test and monitor drinking water in particular areas and to provide filtration or other drinking water supplies to users of water supplies that may have been impacted or threatened by potential contamination from fracturing fluids;
the need to modify drill sites to ensure there are no spills or releases off-site and to investigate and/or remediate any spills or releases that might have occurred; or
suspension of our operations.

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In accordance with industry practice, we maintain insurance at a level that balances the cost of insurance with our assessment of the risk and our ability to achieve a reasonable rate of return on our investments. We cannot assure you that our insurance will be adequate to cover losses or liabilities or that we will purchase insurance against all possible losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Multi-well pad drilling and project development may result in volatility in our operating results.
We utilize multi-well pad drilling and project development where practical. Project development may involve more than one multi-well pad being drilled and completed at one time in a relatively confined area. Wells drilled on a pad or in a project may not be brought into production until all wells on the pad or project are drilled and completed. Problems affecting one pad or a single well could adversely affect production from all of the wells on the pad or in the entire project. As a result, multi-well pad drilling and project development can cause delays in the scheduled commencement of production, or interruptions in ongoing production. These delays or interruptions may cause declines or volatility in our operating results due to timing as well as declines in oil and natural gas prices. Further, any delay, reduction or curtailment of our development and producing operations, due to operational delays caused by multi-well pad drilling or project development, or otherwise, could result in the loss of acreage through lease expirations.
Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity.
We could experience adverse impacts associated with a high concentration of activity and tighter drilling spacing.
We are subject to drilling, completion and operating risks, including our ability to efficiently execute large-scale project development, as we could experience delays, curtailments and other adverse impacts associated with a high concentration of activity and tighter drilling spacing. A higher concentration of activity and tighter drilling spacing may increase the risk of unintentional communication with other adjacent wells and the potential to reduce total recoverable reserves from the reservoir. If these risks materialize and negatively impact our results of operations relative to guidance or market expectations, the research analysts who cover us may downgrade our common stock or change their recommendations or earnings or performance estimates, which may result in a decline in the market price of our common stock.
We may not adhere to our proposed drilling schedule.
Our final determination of whether to drill any wells will be dependent on a number of factors, including:
the results of our exploration efforts and the acquisition, review and analysis of the seismic data;
the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
the approval of the prospects by the other participants after additional data has been compiled;
economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and gas and the availability and prices of drilling rigs and crews, frac crews, and related equipment and material; and
the availability of leases and permits on reasonable terms for the prospects.
For example, we temporarily suspended our drilling program from April 2020 through September 2020 to mitigate the impact of the adverse economic conditions attributable to COVID-19 as well as the impact of the precipitous decline in crude oil prices.
Although we have identified numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. There can be no assurance that these projects can be successfully developed or that any identified drill sites will, if drilled, encounter reservoirs of commercially productive oil or gas or that we will be able to complete such wells on a timely basis, or at all. We may seek to sell or reduce all or a portion of our interest in a project area or with respect to prospects wells within such project area.
Our business depends on gathering, processing, refining and transportation facilities owned by others.
We deliver substantially all of our oil and gas production through pipelines and trucks that we do not own. The marketability of our production depends upon the availability, proximity and capacity of these pipelines and trucks, as well as gathering systems, gas processing facilities and downstream refineries. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells, the reduction in wellhead pricing or the delay or discontinuance of development plans for properties. Federal, state and local regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather, process, refine and market our oil and gas.

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The unavailability, high cost or shortage of drilling rigs, frac crews, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
Where we are the operator of a property, we rely on third-party service providers to perform necessary drilling and completion operations. The ability and availability of third-party service providers to perform such drilling and completion operations will depend on those service providers’ ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, NGLs and natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third-party service provider to adequately perform operations on a timely basis could delay drilling or completion operations, reduce production from the property or cause other damage to operations, each of which could adversely affect our business, financial condition, results of operations and cash flows.
Moreover, the oil and gas industry is cyclical, which can result in shortages of drilling rigs, frac crews, equipment, raw materials (particularly sand and other proppants), supplies and personnel, including geologists, geophysicists, engineers and other professionals. When shortages occur, the costs and delivery times of drilling rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig and frac crews also rise with increases in demand. The prevailing prices of crude oil, NGLs and natural gas also affect the cost of and the demand for drilling rigs, frac crews, materials (including sand) and other equipment and related services. The availability of drilling rigs, frac crews, materials (including sand) and equipment can vary significantly from region to region at any particular time. Although land drilling rigs and frac crews can be moved from one region to another in response to changes in levels of demand, an undersupply in any region may result in drilling and/or completion delays and higher well costs in that region.
We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third-party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs and frac crews at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. Shortages of drilling rigs, frac crews, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Our future performance depends on our ability to find or acquire additional oil and gas reserves that are economically recoverable.
Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and gas production and lower revenues and cash flows from operating activities. We must make substantial capital expenditures to find, acquire, develop and produce new oil and gas reserves. We may not be able to make the necessary capital investments to maintain or expand our oil and gas reserves with our cash flows from operating activities. Furthermore, external sources of capital may be limited.
The ability to attract and retain key members of management, qualified Board members and other key personnel is critical to the success of our business and may be challenging.
Our success will depend to a large extent upon the efforts and abilities of our management team and having experienced individuals serving on our Board who are also knowledgeable about our operations and our industry. We experienced significant turnover on our executive team and Board in 2019 through first quarter 2021. If we experience similar turnover in the future, we may be unable to timely replace the talents and skills of our management team or directors if one or more did not continue serving. The success of our business also depends on other key personnel. The ability to attract and retain these key personnel may be difficult in light of the volatility of our business. We may need to enter into retention or other arrangements that could be costly to maintain. We do not maintain key-man life insurance with respect to any of our employees. Acquiring and keeping personnel could prove more difficult or cost substantially more than estimated. These factors could cause us to incur greater costs or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them adequately or in a timely manner and we could experience significant declines in productivity.
Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on the acreage.
Leases on oil and gas properties typically have a term after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. While we seek to actively manage our leasehold inventory through drilling wells to hold the leasehold acreage that we believe is material to our operations, our drilling plans for these areas are subject to change and subject to the availability of capital.
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Certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that they own.
The drilling and production of potential locations by us or other operators could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells by us or other operators could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
We are exposed to the credit risk of our customers, and nonpayment or nonperformance by these parties would reduce our cash flows.
We are subject to risk from loss resulting from our customers’ nonperformance or nonpayment. We depend on a limited number of customers for a significant portion of our revenues. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly affect our overall credit risk. Recently, many of our customers’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payments or perform on their obligations to us. In 2020, approximately 56 percent of our total consolidated product revenues resulted from three of our customers. Any nonpayment or nonperformance by our customers would reduce our cash flows.
We participate in oil and gas leases with third parties and these third parties may not be able to fulfill their commitments to our projects.
We frequently own less than 100 percent of the working interest in the oil and gas leases on which we conduct operations, and other parties own the remaining portion of the working interest under joint venture arrangements. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one party. We could be held liable for joint venture obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of the other working interest owners. In addition, the volatility in commodity prices increases the likelihood that some of these working interest owners may not be able to fulfill their joint venture obligations. Some of our project partners have experienced liquidity and cash flow problems. These problems have led and may lead our partners to attempt to delay the pace of project development in order to preserve cash. A partner may be unable or unwilling to pay its share of project costs. In some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial condition, results of operations and cash flows.
Estimates of oil and gas reserves and future net cash flows are not precise, and undeveloped reserves may not ultimately be converted into proved producing reserves.
This Annual Report on Form 10-K contains estimates of our proved oil and gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various factors and assumptions, including assumptions relating to crude oil, NGL and natural gas prices, drilling and operating expenses, capital expenditures, development costs and workover and remedial costs, the quantity, quality and interpretation of relevant data, taxes and availability of funds. The process of estimating oil and gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent on many variables and inherently uncertain, therefore, changes often occur as these variables evolve and commodity prices fluctuate. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data, and improvements or other changes in geological, geophysical and engineering evaluation methods may cause reserve estimates to change over time. Any material inaccuracies in these reserve estimates, cash flow estimates or underlying assumptions could materially affect the estimated quantities and present value of our reserves.
Actual future production, crude oil, NGL and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by us. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil, NGL and natural gas prices and other factors, many of which are beyond our control.

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At December 31, 2020 and December 31, 2019, approximately 60 percent and 58 percent, respectively, of our estimated proved reserves were proved undeveloped. Estimation of proved undeveloped reserves is based on volumetric calculations and adjacent reserve performance data. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve data assumes that we can and will make these significant expenditures to develop our reserves and conduct these drilling operations successfully. These assumptions, however, may not prove correct, and our estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated.
The reserve estimation standards under SEC rules provide that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These standards may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not develop those reserves within the required five-year time frame or cannot demonstrate that we could do so. Accordingly, our reserve report at December 31, 2020, includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $898 million. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write-off these reserves. During the year ended December 31, 2020, we wrote-off 34.0 MMBOE of proved undeveloped reserves because they are no longer expected to be developed within five years of their initial recording. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our securities.
You should not assume that the present value of estimated future net cash flows (standardized measure) referred to herein is the current fair value of our estimated oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual current and future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. As a result, net present value estimates using actual prices and costs may be significantly less than the SEC estimate that is provided herein. Actual future net cash flows may also be affected by the amount and timing of actual production, availability of financing for capital expenditures necessary to develop our undeveloped reserves, supply and demand for oil and gas, increases or decreases in consumption of oil and gas and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. With all other factors held constant, if commodity prices used in the reserve report were to decrease by 10%, our standardized measure and PV-10 would have decreased to approximately $449 million and $454 million, respectively. Any adjustments to the estimates of proved reserves or decreases in the price of our commodities may decrease the value of our securities.
We may record impairments on our oil and gas properties.
Quantities of proved reserves are estimated based on economic conditions in existence in the period of assessment. Lower crude oil, NGL and natural gas prices may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all reserves within such fields, thus reducing proved property reserve estimates. If such revisions in the estimated quantities of proved reserves occur, it will have the effect of increasing the rates of depreciation, depletion and amortization, or DD&A, on the affected properties, which would decrease earnings or result in losses through higher DD&A expense. The revisions may also be significant enough to result in a write-down that would further decrease reported earnings.
The full cost method of accounting for oil and gas properties under GAAP requires that at the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated after tax discounted future net revenues from proved properties adjusted for costs excluded from amortization, or a Ceiling Test. The estimated after tax discounted future net revenues are determined using the prior 12-month’s average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development. In addition to revisions to reserves and the impact of lower commodity prices, Ceiling Test write-downs may occur due to increases in estimated operating and development costs and other factors. During fiscal 2020, we recorded impairments of our oil and gas properties of $392 million. Because the Ceiling Test utilizes commodity prices based on a trailing twelve month average, as of December 31, 2020, it does not fully reflect the substantial decline in commodity prices that accelerated early in the second quarter of 2020 due to the COVID-19 pandemic and the ongoing disruption in global energy markets. Accordingly, we may incur an additional impairment during the first quarter of 2021.

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If we cannot obtain sufficient capital when needed, we will not be able to continue with our business strategy.
The oil and gas industry is capital intensive. We incur and expect to continue to incur substantial capital expenditures for the acquisition, exploration and development of oil and gas reserves. We incurred approximately $135.3 million in acquisition, exploration and development costs during the year ended December 31, 2020. We intend to finance our future capital expenditures, other than significant acquisitions, through cash flow from operations and, if necessary, through borrowings under our credit agreement (as defined below). However, our cash flow from operations and access to capital are subject to a number of variables, including: (i) the volume of oil and gas we are able to produce from existing wells, (ii) our ability to transport our oil and gas to market, (iii) the prices at which our commodities are sold, (iv) the costs of producing oil and gas, (v) global credit and securities markets, (vi) the ability and willingness of lenders and investors to provide capital and the cost of the capital, (vii) our ability to acquire, locate and produce new reserves, (viii) the impact of potential changes in our credit ratings and (ix) our proved reserves. Additionally, a negative shift in investor sentiment towards the oil and gas industry could adversely affect our ability to raise equity and debt capital.
We may not generate expected cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or anticipated levels. A decline in cash flow from operations or our financing needs may require us to revise our capital program or alter or increase our capitalization substantially through the issuance of debt or equity securities. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. Additional borrowings under our credit agreement or the issuance of additional debt securities will require that a greater portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. In addition, our credit agreements impose certain limitations on our ability to incur additional indebtedness. If we desire to issue additional debt securities other than as expressly permitted under our credit agreements, we will be required to seek the consent of the lenders in accordance with the requirements of our credit agreements, which consent may be withheld by the lenders at their discretion. In the future, we may not be able to obtain financing in sufficient amounts or on acceptable terms when needed, which could adversely affect our operating results and prospects. If we cannot raise the capital required to implement our business strategy, we may be required to curtail operations, which could adversely affect our financial condition, results of operations and cash flows.
Our property acquisitions carry significant risks.
Acquisition of oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive candidates, we may not be able to complete the acquisition or do so on commercially acceptable terms. In the event we do complete an acquisition, such as the recently completed acquisition of certain oil and gas assets from Rocky Creek, its success will depend on a number of factors, many of which are beyond our control. These factors include future crude oil, NGL and natural gas prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties and future abandonment, possible future environmental or other liabilities and the effect on our liquidity or financial leverage of using available cash or debt to finance acquisitions. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates and associated costs and the assumption of potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.
Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems, that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results, and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.

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Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.
Our initial technical reviews of properties we acquire are necessarily limited because an in-depth review of every individual property involved in each acquisition generally is not feasible. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well and environmental problems, such as soil or ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may assume certain environmental and other risks and liabilities in connection with acquired properties, or discover unknown liabilities after the acquisition, and such risks and liabilities could have a material adverse effect on its results of operations and financial condition.
We may incur losses as a result of title deficiencies.
We purchase working and revenue interests in the oil and gas leasehold interests upon which we will perform our exploration activities from third parties or directly from the mineral fee owners. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations, financial condition and cash flows. Title insurance covering mineral leaseholds is not generally available and, in all instances, we forgo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. Even then, the cost of performing detailed title work can be expensive. We may choose to forgo detailed title examination by title lawyers on a portion of the mineral leases that we place in a drilling unit or conduct less title work than we have traditionally performed. As is customary in our industry, we generally rely upon the judgment of oil and gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract. We, in some cases, perform curative work to correct deficiencies in the marketability or adequacy of the title to us. The work might include obtaining affidavits of heirship or causing an estate to be administered. In cases involving more serious title problems, the amount paid for affected oil and gas leases can be generally lost and the target area can become undrillable. The failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
As a small company, we face unique difficulties competing in the larger market.
We operate in a highly competitive environment for acquiring properties, marketing oil and gas and securing trained personnel, and we may face difficulties in competing with larger companies. The costs of doing business in the exploration and production industry, including such costs as those required to explore new oil and gas plays, to acquire new acreage, and to develop attractive oil and gas projects, are significant. We face intense competition in all areas of our business from companies with greater and more productive assets, greater access to capital, substantially larger staffs and greater financial and operating resources than we have. Those companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Also, there is substantial competition for capital available for investment in the oil and gas industry. Our limited size has placed us at a disadvantage with respect to funding our capital and operating costs, and means that we are more vulnerable to commodity price volatility and overall industry cycles (such as the volatility and general economic challenges attributable to COVID-19), are less able to absorb the burden of changes in laws and regulations, and that poor results in any single exploration, development or production play can have a disproportionately negative impact on us. We also compete for people, including experienced geologists, geophysicists, engineers and other professionals. Our limited size has placed us at a disadvantage with respect to attracting and retaining management and other professionals with the technical abilities necessary to successfully operate our business.
Our lack of diversification increases the risk of an investment in us and we are vulnerable to risks associated with operating primarily in one major contiguous area.
All of our operations are in the Eagle Ford Shale in South Texas, making us vulnerable to risks associated with operating in one geographic area. Due to the concentrated nature of our business activities, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that are more diversified. In particular, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in which we have an interest that are caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, water shortages or other drought related conditions, plant closures for scheduled maintenance or interruption of transportation of crude oil or natural gas produced from wells in the Eagle Ford. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations and cash flows.

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Financial and Related Risks
We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.
We had $377.6 million of outstanding debt at March 5, 2021, including $228.9 million under the Credit Facility, and $148.7 million, excluding unamortized discount and issuance costs, under the Second Lien Facility.
Our indebtedness and any increase in our level of indebtedness could have adverse effects on our financial condition, results of operations and cash flows, including (i) imposing additional cash requirements on us in order to support interest payments, which reduces the amount we have available to fund our operations and other business activities, (ii) increasing the risk that we may default on our debt obligations, (iii) increasing our vulnerability to adverse changes in general economic and industry conditions, economic downturns and adverse developments in our business, (iv) increasing our exposure to a rise in interest rates, which will generate greater interest expense, (v) limiting our ability to engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes and (vi) limiting our flexibility in planning for or reacting to changes in our business and industry in which we operate. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are out of our control.
Additionally, we may incur substantially more debt in the future. Our Credit Facility and the Second Lien Facility contain restrictions that limit our ability to incur indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. If we were to incur additional indebtedness without retiring existing debt, the risks described above could be magnified.
The borrowing base under our credit facility may be reduced in the future if commodity prices decline.
The borrowing base under the Credit Facility, was $375 million as of December 31, 2020 with borrowings limited to a maximum of $350 million. As of March 5, 2021, we had $228.9 million outstanding under the Credit Facility. Our borrowing base is generally redetermined at least twice each year and is scheduled to next be redetermined in October 2021 assuming we continue to meet certain conditions under the Credit Facility thereby foregoing a Spring 2021 redetermination. During a borrowing base redetermination, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Credit Facility. In the event of a decline in crude oil, NGL or natural gas prices or for other reasons deemed relevant by our lenders, the borrowing base under the Credit Facility may be reduced. Additionally, the lenders typically may, at their discretion, initiate a redetermination at any time during the six-month period between scheduled redeterminations. As a result, we may be unable to obtain funding under the Credit Facility. If funding is not available when or in the amounts needed, or is available only on unfavorable terms, it might adversely affect our development plan and our ability to make new acquisitions. Furthermore, a determination to lower the borrowing base in the future to a level less than our outstanding indebtedness thereunder would require us to repay any indebtedness in excess of the redetermined borrowing base. Any such repayment or reduced access to funds could have a material adverse effect on our production, financial condition, results of operations and cash flows.
The Credit Facility and the Second Lien Facility have restrictive covenants that could limit our financial flexibility.
The Credit Facility and Second Lien Facility contain financial and other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under the Credit Facility is subject to compliance with certain financial covenants, including leverage, interest coverage and current ratios.
The Credit Facility and the Second Lien Facility include other restrictions that, among other things, limit our ability to incur indebtedness; grant liens; engage in mergers, consolidations and liquidations; make asset dispositions, restricted payments and investments; enter into transactions with affiliates; and amend, modify or prepay certain indebtedness.
Our business plan and our compliance with these covenants are based on a number of assumptions, the most important of which is relatively stable oil and gas prices at economically sustainable levels. If the price that we receive for our oil and gas production deteriorates significantly from current levels it could lead to lower revenues, cash flows and earnings, which in turn could lead to a default under certain financial covenants contained in our Credit Facility. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period as the amounts outstanding under our Credit Facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings. Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our debts. We may not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

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Derivative transactions may limit our potential gains and involve other risks.
In order to achieve more predictable cash flows and manage our exposure to commodity price risks in the sale of our crude oil, NGLs and natural gas, we periodically enter into commodity price hedging arrangements with respect to a portion of our expected production. Our hedges are limited in duration, usually for periods of three years or less. While intended to reduce the effects of volatile crude oil, NGL and natural gas prices, such transactions may limit our potential gains if crude oil, NGL or natural gas prices were to rise over the price established by the hedging arrangements. In trying to maintain an appropriate balance, we may end up hedging too much or too little, depending upon how commodity prices fluctuate in the future, which could have the effect of reducing our net income.
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;
there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
the counterparty to a derivatives instrument fails to perform under the contract; or
a sudden, unexpected event materially impacts commodity prices.
In addition, we may enter into derivative instruments that involve basis risk. Basis risk in a derivative contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production.
The adoption of derivatives legislation and implementing rules could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC, to promulgate rules and regulations implementing the Dodd-Frank Act. While some of these rules have been finalized, some have not been finalized or implemented, and it is not possible at this time to predict when this will be accomplished. In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents; however, this initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. The CFTC has subsequently issued proposals for new rules that would place position limits on certain core futures contracts and equivalent swap contracts for or linked to certain physical commodities, subject to certain exceptions for bona fide hedging transactions, though these rules have not been finalized and the impact of those provisions on us is uncertain at this time.
While the CFTC has designated certain interest rate swaps and credit default swaps subject to mandatory clearing, and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. The CFTC has not yet proposed rules subjecting any other classes of swaps, including physical commodity swaps, to mandatory clearing. Although we believe we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If our swaps do not qualify for the end-user exception from mandatory clearing, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or our ability to hedge may be impacted. The ultimate effect of the rules and any additional regulations on our business is uncertain at this time.
In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to be exempt from such requirements for the mandatory exchange of margin for uncleared swaps, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. Further, if we did not qualify for an exemption and were required to post collateral for our swaps, it could reduce our liquidity and cash available for capital expenditures and our ability to manage commodity price volatility and the volatility in cash flows.
The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. When fully implemented, the Dodd-Frank Act and any new regulations could increase the operational and transactional cost of derivatives contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize and restructure our existing derivatives contracts and affect the number and/or creditworthiness of available counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.
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In addition, we may transact with counterparties based in the European Union, Canada or other jurisdictions which, like the U.S., are in the process of implementing regulations to regulate derivatives transactions, some of which are currently in effect and impose operational and transactional costs on our derivatives activities.
A negative shift in investor sentiment towards the oil and gas industry could adversely affect our ability to raise equity and debt capital.
Certain segments of the investor community have recently developed negative sentiment towards investing in our industry. The negative sentiment toward our sector versus other industry sectors has led to lower oil and gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and gas sector based on social and environment considerations. Such development could result in a reduction of available capital funding for potential development projects or diminution of capital to fund our business which could impact our future financial results.
Legal and Regulatory Risks
We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Exploration, development, production and sale of oil and gas are subject to extensive federal, state and local laws and regulations, including complex environmental laws. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations, inability to obtain necessary regulatory approvals or a failure to comply with existing legal requirements may harm our business, results of operations, financial condition or cash flows. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations or other environmental, health or safety impacts, we may be charged with remedial costs and land owners may file claims for alternative water supplies, property damage or bodily injury. Laws and regulations protecting the environment have become more stringent in recent years, and may, in some circumstances, result in liability for environmental damage regardless of negligence or fault. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Moreover, these risks are likely to be enhanced with President Biden taking office and Democrats gaining control of Congress. For example, see Part I, Item 1, “Business - Government Regulation and Environmental Matters - Greenhouse Gas Emissions” for information about certain actions the Biden Administration has taken targeting greenhouse gas emissions. No assurance can be given that continued compliance with existing or future environmental laws and regulations will not result in a curtailment of production or processing activities or result in a material increase in the costs of production, development, exploration or processing operations. In addition, pollution and similar environmental risks generally are not fully insurable. These liabilities and costs could have a material adverse effect on our business, financial condition, results of operations and cash flows. See Part I, Item 1, “Business - Government Regulation and Environmental Matters.”
Access to water to drill and conduct hydraulic fracturing may not be available if water sources become scarce, and we may face difficulty disposing of produced water gathered from drilling and production activities.
The availability of water is crucial to conduct hydraulic fracturing. A significant amount of water is necessary for drilling and completing each well with hydraulic fracturing. In the past, Texas has experienced severe droughts that have limited the water supplies that are necessary to conduct hydraulic fracturing. Although we have taken measures to secure our water supply, we can make no assurances that sufficient water resources will be available in the short or long term to carry out our current activities. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and gas, which could have an adverse effect on our financial condition, results of operations and cash flows.
In addition, we must dispose of the fluids produced from oil and natural gas production operations, including produced water. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern arises from recent seismic events near underground disposal wells that are used for the disposal by injection of produced water resulting from oil and natural gas activities. In March 2016, the United States Geological Survey identified Texas and Colorado as being among the states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and natural gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells to assess any relationship between seismicity and the use of such wells. For example, in Texas, the RRC adopted new rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or
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terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. States may issue orders to temporarily shut down or to curtail the injection depth of existing wells in the vicinity of seismic events. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil and natural gas activities utilizing injection wells for produced water disposal.
Climate change legislation, laws and regulations restricting emissions of greenhouse gases or prohibiting, restricting, or delaying oil and gas development on public lands, or legal or other action taken by public or private entities related to climate change could force us to incur increased capital and operating costs and could have a material adverse effect on our financial condition, results of operations and cash flows, as well as our reputation.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs endanger 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 changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. For example, the EPA issued rules restricting methane emissions from hydraulically fractured and refractured gas wells, compressors, pneumatic controls, storage vessels, and natural gas processing plants. For more information on GHG regulation, see Part I, Item 1, “Business - Government Regulation and Environmental Matters.”
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of Congressional action, many states have established rules aimed at reducing GHG emissions, including GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In the future, the United States may also choose to adhere to international agreements targeting GHG reductions. The adoption of legislation or regulatory programs or other government action to reduce emissions of GHGs or restrict, delay or prohibit oil and gas development on public lands could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements, or prevent us from conducting operations in certain areas. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. These risks are likely to be enhanced with President Biden taking office and Democrats gaining control of Congress. See Part I, Item 1, “Business - Government Regulation and Environmental Matters -Greenhouse Gas Emissions.” Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, results of operations and cash flows. Reduced demand for the oil and gas that we produce could also have the effect of lowering the value of our reserves.
In addition, 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, floods and other climatic events. If such climactic events were to occur more frequently or with greater intensity, our exploration and development activities and ability to transport our production to market could be adversely affected, as these events could cause a loss of production from temporary cessation of activity or damaged facilities and equipment. If any such events were to occur, they could have an adverse effect on our financial condition, results of operations and cash flows. For a more complete discussion of environmental laws and regulations intended to address climate change and their impact on our business and operations, see Part I, Item 1, “Business - Government Regulation and Environmental Matters.”
There have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, as well as other stakeholders, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital and adversely impact our reputation. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and gas companies in connection with their GHG emissions. Should we be targeted by any such litigation or investigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

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Federal state and local legislation and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect our production.
Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate oil and gas production. We routinely use hydraulic fracturing to complete wells. The EPA released the final results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources in December 2016. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. The results of the EPA’s study could spur action towards federal legislation and regulation of hydraulic fracturing or similar production operations. In past sessions, Congress has considered, but did not pass, legislation to amend the SDWA to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and gas companies in the hydraulic fracturing process. The EPA has issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. The EPA has also issued final regulations under the CAA establishing performance standards, including standards for the capture of VOCs and methane released during hydraulic fracturing; an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and final rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, a number of states and local regulatory authorities and federal politicians are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans/moratoria on drilling that effectively prohibit further production of oil and gas through the use of hydraulic fracturing or similar operations. Texas has adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process, and the RRC has also adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Moreover, the legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, Texas regulators have asserted regulatory authority to limit injection activities in certain wells in an effort to reduce seismic activity. A 2015 U.S. Geological Survey report identified areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil, natural gas and natural gas liquids activities utilizing injection wells for produced water disposal.
The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. These risks are likely to be enhanced with President Biden taking office and Democrats gaining control of Congress.
Restrictions on drilling activities intended to protect certain species of wildlife or their habitat may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Various federal and state statutes prohibit certain actions that harm endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Bald and Golden Eagle Protection Act, the Clean Water Act, CERCLA and the OPA. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling, construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, may seek criminal penalties.

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We may be involved in legal proceedings that could result in substantial liabilities.
Like many oil and gas companies, from time to time, we expect to be involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
Tax-Related Risks
Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations.
Our ability to utilize U.S. net operating loss, or NOL, carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended, or the Code. As disclosed in Note 10 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data,” we have substantial NOL carryforwards. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of our stock by 5 percent shareholders and our offering of stock during any three-year period resulting in an aggregate change of more than 50 percent in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. As of December 31, 2020, we do not believe that an ownership change has occurred; however, to the extent an ownership change has occurred or were to occur in the future, it is possible that the limitations imposed on our ability to use pre-ownership change losses could cause a significant net increase in our U.S. federal income tax liability and could cause U.S. federal income taxes to be paid earlier than they otherwise would be paid if such limitations were not in effect. In addition, U.S. NOLs generated on or after January 1, 2018, can be limited to 80 percent of taxable income. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.
Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated. Additional state taxes on oil and gas extraction may be imposed, as a result of future legislation.
In recent years, lawmakers and Treasury have proposed certain significant changes to U.S. tax laws applicable to oil and gas companies. These changes include, but are not limited to: (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or if enacted, when such changes could be effective. If such proposed changes are ever made, as well as any similar changes in state law, it could eliminate or postpone certain tax deductions that are currently available to us with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition, results of operations and cash flows.
Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our crude oil, NGLs and natural gas.
Technology-Related Risks
We may not be able to keep pace with technological developments in our industry.
The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations and cash flows could be adversely affected.
A cybersecurity incident could result in theft of confidential information, data corruption or operational disruption.
The oil and gas industry is increasingly dependent on digital technologies to conduct certain exploration, development and production activities. Software programs are used for, among other things, reserve estimates, seismic interpretation, modeling and compliance reporting. In addition, the use of mobile communication is widespread. Increasingly, we must protect our business against potential cyber incidents including attacks as we have experienced and will continue to experience varying degrees of cyber incidents in the normal conduct of our business.
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If our systems for protecting against cyber incidents prove insufficient, we could be adversely affected by unauthorized access to our digital systems which could result in theft of confidential information, data corruption or operational disruption. These cybersecurity threat actors are becoming more sophisticated and coordinated in their attempts to access a company’s information technology systems and data, including the information technology systems of cloud providers and third parties with which a company conducts business. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities.
Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. A cyber attack involving our information systems and related infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways, including but not limited to, the following:
Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;
Data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;
Data corruption or operational disruptions of production-related infrastructure could result in a loss of production, or accidental discharge;
A cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects;
A cyber attack on third-party gathering, pipeline, or other transportation systems could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;
A cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
A cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market;
A cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
A cyber attack on our automated and surveillance systems could cause a loss in production and potential environmental hazards;
A deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and
A cyber attack resulting in the loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
Additionally, certain cyber incidents may remain undetected for an extended period. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operations or cash flows. Furthermore, the growth of cyber attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.
Risks Related to the Ownership of Our Common Stock
Juniper controls the Company, and their interests may conflict with the Company’s and its shareholders’ interests in the future.
Juniper beneficially owns approximately 60% of our voting securities. As a result, Juniper is able to control the election and removal of our directors and thereby control our policies and operations and its interests may not in all cases be aligned with other shareholders’ interests. In addition, Juniper may have an interest in pursuing acquisitions, divestitures and other transactions that, in its judgment, could enhance its investment, even though such transactions might involve risks to other shareholders. For example, Juniper could cause us to make acquisitions that increase our indebtedness or cause us to sell revenue-generating assets. Additionally, Juniper and its designated directors are not obligated to present any business opportunities (other than those presented to such directors in their roles as directors of the Company) to us.
In addition, Juniper is able to determine the outcome of all matters requiring shareholder approval and is able to cause or prevent a change of control of the Company or a change in the composition of our Board of Directors and could preclude any acquisition of the Company. This concentration of voting control could deprive shareholders of an opportunity to receive a premium for their shares of Common Stock as part of a sale of the Company and ultimately might affect the market price of our Common Stock.

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Moreover, Juniper has certain director designation rights entitling them to designate up to five members of the Board out of a total of nine directors, with such designation rights being subject to certain step-downs.
We are a “controlled company” within the meaning of the Nasdaq rules and, as a result, expect to qualify for exemptions from certain corporate governance requirements.
Juniper controls a majority of the voting power of our capital stock. As a result, we are a “controlled company” within the meaning of the corporate governance standards of Nasdaq. As a result, we are not required to comply with certain corporate governance requirements, including the requirement to have a majority of the board of directors be independent directors and the requirement to have compensation and nominating committees that are composed entirely of independent directors. While we have not elected to utilize these exemptions, in the future we could elect to do so. If we were to utilize any such exemptions, our shareholders would not have the same protections afforded to shareholders of companies that are subject to all of the corporate governance rules for Nasdaq-listed companies.
Penn Virginia is a holding company. Penn Virginia’s only material asset is its equity interest in the Partnership, and Penn Virginia is accordingly dependent upon distributions from the Partnership to pay taxes and cover its operating expenses and other obligations.
Following the Juniper Transactions, Penn Virginia is a holding company and has no material assets other than its equity interest in the Partnership. Penn Virginia has no independent means of generating revenue. To the extent the Partnership has available cash, Penn Virginia intends to cause the Partnership to make (i) pro rata distributions to its limited partners, including Penn Virginia, in an amount sufficient to allow Penn Virginia to pay its taxes and (ii) payments to Penn Virginia to cover its operating expenses and other obligations. To the extent that Penn Virginia needs funds and the Partnership or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any future financing arrangements, or are otherwise unable to provide such funds, Penn Virginia’s liquidity and financial condition could be materially adversely affected.
Moreover, because Penn Virginia has no independent means of generating revenue, Penn Virginia’s ability to pay dividends will be dependent on the ability of the Partnership to make cash distributions. This ability, in turn, may depend on the ability of the Partnership’s subsidiaries to make distributions to it. The ability of the Partnership, its subsidiaries and other entities in which it directly or indirectly holds an equity interest to make such distributions will be subject to, among other things, (i) applicable laws or regulations that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments issued by the Partnership or its subsidiaries and other entities in which it directly or indirectly holds an equity interest.
In certain circumstances, the Partnership will be required to make tax distributions to its unitholders, including us, and the tax distributions that the Partnership will be required to make may be substantial.
Pursuant to the A&R Partnership Agreement, the Partnership will make generally pro rata cash distributions, or tax distributions, to its unitholders, including us, in an amount generally intended to allow the unitholders to satisfy their respective income tax liabilities with respect to their allocable share of the income of the Partnership, based on certain assumptions and conventions, provided that the distribution will be sufficient to allow us to satisfy our actual tax liabilities. Because tax distributions will be made pro rata based on ownership and based on an assumed tax rate, the Partnership could be required to make tax distributions that, in the aggregate, exceed the amount of taxes that the Partnership would have paid if it were taxed on its net income at its effective tax rate.
Funds used by the Partnership to satisfy its tax distribution obligations will not be available for reinvestment in the business. Moreover, the tax distributions the Partnership will be required to make may be substantial and may exceed the unitholder’s tax liabilities if the unitholder has an overall effective tax rate that is lower than the assumed rate.
Certain provisions of our certificate of incorporation and our bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of our Certificate of Incorporation and our Bylaws may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Certificate of Incorporation and Bylaws include, among other things, those that:
authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and
limit the persons who may call special meetings of stockholders.

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While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management.
The market price of our common stock is subject to volatility.
The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading of our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our limited trading volume, the concentration of holdings of our common stock, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this report. Significant sales of our common stock, or the expectation of these sales, by significant shareholders, officers or directors could materially and adversely affect the market price of our common stock.
Our business and the trading prices of our securities could be negatively affected as a result of actions of so-called “activist” shareholders, and such activism could impact the trading value of our securities.
Shareholders may from time to time attempt to effect changes, engage in proxy solicitations or advance shareholder proposals. Activist shareholders may make strategic proposals, suggestions or requested changes concerning our operations, strategy, management, assets or other matters. If we become the subject of activity by activist shareholders, responding to such actions could be costly and time-consuming, diverting the attention of our management and employees. Furthermore, activist campaigns can create perceived uncertainties as to our future direction, strategy, or leadership and may result in the loss of potential business opportunities and cause our stock price to experience periods of volatility.
There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.
We are not restricted from issuing additional common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. Any issuance of additional shares of our common stock or convertible securities will dilute the ownership interest of our common stockholders. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market, or the perception that these sales could occur, could depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.
As of March 5, 2021, Juniper beneficially owns 225,481.09 shares of Series A Preferred Stock, which are exchangeable for shares of our common stock at the election of the holder for no additional consideration. Although Juniper is restricted from selling any of its equity securities in the Company and the Partnership prior to July 14, 2021, Juniper may decide to reduce its investment in the Company at any time thereafter. Any such sales of our equity securities, or expectations thereof, could have the effect of depressing the market price for our common stock.
Item 1B    Unresolved Staff Comments
None.
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Item 2     Properties
As of December 31, 2020, our oil and gas assets were located in Gonzales, Lavaca, Fayette and Dewitt Counties in South Texas.
Facilities
Our corporate headquarters and field office facilities are leased and we believe that they are adequate for our current needs.
Title to Oil and Gas Properties
Prior to completing an acquisition of producing oil and gas assets, we review title opinions on all material leases. As is customary in the oil and gas industry; however, we make a cursory review of title when we acquire farmout acreage or undeveloped oil and gas leases. Prior to the commencement of drilling operations, a thorough title examination is conducted. To the extent the title examination reflects defects, we cure such title defects. If we are unable to cure any title defect of a nature such that it would not be prudent to commence drilling operations on a property, we could suffer a loss of our investment in the property. Our oil and gas properties are subject to customary royalty interests, liens for debt obligations, current taxes and other burdens that we believe do not materially interfere with the use or materially affect the value of such properties. We believe that we have satisfactory title to all of our properties and the associated oil and gas in accordance with standards generally accepted in the oil and gas industry.
Summary of Oil and Gas Reserves
Proved Reserves
The following tables summarize certain information regarding our estimated proved reserves as of December 31 for each of the years presented:
 Crude OilNGLsNatural
Gas
Oil
Equivalents
Standardized
Measure
PV10 1
 (MMBbl)(MMBbl)(Bcf)(MMBOE)$ in millions$ in millions
2020     
Developed
Producing36.4 8.0 37.6 50.6 
Non-producing— — — — 
36.4 8.0 37.6 50.6 
Undeveloped62.1 7.6 36.1 75.8 
98.5 15.6 73.7 126.4 $650.3 $657.5 
Price measurement used$39.54/Bbl$7.51/Bbl$1.99/MMBtu
2019
Developed
Producing40.1 8.7 41.0 55.6 
Non-producing0.5 0.2 0.8 0.8 
40.6 8.9 41.8 56.4 
Undeveloped58.3 10.3 48.6 76.7 
98.9 19.2 90.4 133.1 $1,488.9 $1,600.1 
Price measurement used$55.67/Bbl$13.36/Bbl$2.58/MMBtu
2018
Developed
Producing35.2 6.3 31.8 46.8 
Non-producing— — — — 
35.2 6.3 31.8 46.8 
Undeveloped54.5 11.7 59.7 76.2 
89.7 18.0 91.5 123.0 $1,623.9 $1,769.4 
Price measurement used$65.56/Bbl$23.60/Bbl$3.10/MMBtu
_____________________________________________
1 PV10 represents a non-GAAP measure that is most directly comparable to the Standardized Measure as defined in GAAP. The Standardized Measure represents the discounted future net cash flows from our proved reserves after future income taxes discounted at 10% in accordance with SEC criteria. PV10 represents the Standardized Measure without regard to income taxes of $7.0 million, $111.2 million and $145.5 million for 2020, 2019 and 2018, respectively. We believe that PV10 is a meaningful supplemental disclosure to the Standardized Measure as the PV10 concept is widely used within the industry and by the financial and investment community to evaluate the proved reserves on a comparable basis across companies without regard to the individual owner’s unique income tax position. We utilize PV10 to evaluate the potential return on investment in our oil and gas properties as well as evaluating properties for potential purchases and sales.
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A discussion and analysis of the changes in our total proved reserves is provided in “Supplemental Information on Oil and Gas Producing Activities (Unaudited)” included in Part II, Item 8, “Financial Statements and Supplementary Data.”
Proved Undeveloped Reserves
The proved undeveloped reserves included in our reserve estimates relate to wells that are forecasted to be drilled within the next five years. The following table sets forth the changes in our proved undeveloped reserves during the year ended December 31, 2020:
Crude OilNGLsNatural GasOil Equivalents
(MMBbl)(MMBbl)(Bcf)(MMBOE)
Proved undeveloped reserves at beginning of year 58.3 10.3 48.6 76.7 
Revisions of previous estimates(19.2)(4.7)(22.5)(27.6)
Extensions and discoveries 29.9 3.2 15.4 35.7 
Conversion to proved developed reserves(6.9)(1.2)(5.4)(9.0)
Proved undeveloped reserves at end of year 62.1 7.6 36.1 75.8 
The marginal decrease in our proved undeveloped oil equivalent reserves over the quantities at the end of 2019 is due primarily to the combined effect of largely offsetting changes as described below.
In light of significantly different economic conditions due to the ongoing COVID-19 pandemic and their impact on our capital resources, we undertook a review of our drilling plans and available site inventory that resulted in a substantial shift in the focus of our near-term drilling schedule to our core, oilier prospects. This process resulted in an increase to extensions and discoveries of 35.7 MMBOE that was largely offset by 34.0 MMBOE of negative revisions due primarily to certain wells that are now beyond our five-year drilling window schedule. In addition, our revision of previous estimates reflect: (i) favorable revisions of 6.2 MMBOE attributable to changes in lateral lengths and type curves, (ii) favorable revisions of 0.7 MMBOE due to improved performance partially offset by (iii) 0.3 MMBOE due to a decline in pricing.
During 2020, we incurred capital expenditures of $102.5 million attributable to drilling and completing 21 gross (19.7 net) wells in connection with the conversion of proved undeveloped reserves to proved developed reserves. Our conversion rates for quantities of proved undeveloped reserves were 12 percent, 22 percent and 33 percent in 2020, 2019 and 2018, respectively. The conversion rate decline experienced in 2020 was adversely impacted by the temporary suspension of our drilling and completion program from April through September of 2020 in response to the economic downturn associated with the global COVID-19 pandemic.
Preparation of Reserves Estimates and Internal Controls
The proved reserve estimates were prepared by DeGolyer and MacNaughton, Inc., our independent third party petroleum engineers. For additional information regarding estimates of proved reserves and other information about our oil and gas reserves, see “Supplemental Information on Oil and Gas Producing Activities (Unaudited)” in our Notes to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data” and the report of DeGolyer and MacNaughton, Inc., dated January 29, 2021, which is included as an Exhibit to this Annual Report on Form 10-K. We did not file any reports during the year ended December 31, 2020 with any federal authority or agency with respect to our estimate of oil and gas reserves.
Our policies and practices regarding the recording of reserves are structured to objectively and accurately estimate our oil and gas reserve quantities and present values in compliance with the SEC’s regulations and GAAP. Our Senior Vice President, Development is primarily responsible for overseeing the preparation of the reserve estimate by DeGolyer and MacNaughton, Inc. Our Senior Vice President, Development has over 25 years of industry experience in the estimation and evaluation of reserve information, holds a B.S. degree in Petroleum Engineering from the Colorado School of Mines and is registered by the States of Colorado and Wyoming as a Petroleum Engineer. Our internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation. In addition to conducting these internal reviews and external reserves audits, we also have a Reserves Committee that consists four members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process.
There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. For additional information about the risks inherent in our estimates of proved reserves, see Part I, Item 1A, “Risk Factors.”

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Qualifications of Third Party Petroleum Engineers
The technical person primarily responsible for review of our reserve estimates at DeGolyer and MacNaughton, Inc. meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton, Inc. is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
Oil and Gas Production, Production Prices and Production Costs
Oil and Gas Production by Region
The following tables set forth by region our total sales volume and average daily sales volume for the periods presented:
Total Sales Volume
Year Ended December 31,
Region202020192018
 (MBOE) 
South Texas8,887 10,121 7,780 
Mid-Continent 1
— — 165 
8,887 10,121 7,944 
Average Daily Sales Volume
Year Ended December 31,
Region202020192018
(BOEPD) 
South Texas24,281 27,730 21,314 
Mid-Continent 1
— — 451 
24,281 27,730 21,765 
_____________________________________________
1 Mid-Continent operations were sold on July 31, 2018 representing a complete divestiture in which we have no retained interests.

Production Prices and Production Costs
The following table sets forth the average sales prices per unit of volume and our average production costs, not including ad valorem and production/severance taxes, per unit of sales volume for the periods presented:
 Year Ended December 31,
 202020192018
Average prices:  
Crude oil ($ per Bbl)$36.86 $58.33 $66.23 
NGLs ($ per Bbl)$7.68 $11.13 $20.99 
Natural gas ($ per Mcf)$1.88 $2.51 $3.08 
Aggregate ($ per BOE)$30.47 $46.34 $55.33 
Average production and lifting cost ($ per BOE):
Lease operating$4.22 $4.26 $4.52 
Gathering processing and transportation2.48 2.29 2.34 
$6.70 $6.55 $6.86 
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Significant Fields
Our properties in the Eagle Ford in South Texas, which contain primarily crude oil reserves, represented all of our total equivalent proved reserves as of December 31, 2020.
The following table sets forth certain information with respect to this field for the periods presented:
 Year Ended December 31,
202020192018
Sales volume:  
Crude oil (MBbl)6,829 7,453 6,050 
NGLs (MBbl)1,165 1,491 944 
Natural gas (MMcf)5,360 7,067 4,713 
Total (MBOE)8,887 10,121 7,780 
Percent of total company sales volume100 %100 %98 %
Average prices:
Crude oil ($ per Bbl)$36.86 $58.33 $66.24 
NGLs ($ per Bbl)$7.68 $11.13 $21.10 
Natural gas ($ per Mcf)$1.88 $2.51 $3.16 
Aggregate ($ per BOE)$30.47 $46.34 $55.99 
Average production and lifting cost ($ per BOE):
Lease operating$4.22 $4.26 $4.47 
Gathering processing and transportation2.48 2.29 2.27 
$6.70 $6.55 $6.74 

Drilling and Other Exploratory and Development Activities
The following table sets forth the gross and net development wells that we completed (regardless of when drilling was initiated), all of which were in the Eagle Ford in South Texas, during the years indicated and wells that were in progress at the end of each year. There were no exploratory wells drilled in any of the years presented.  
 202020192018
 GrossNetGrossNetGrossNet
Development      
Productive23 20.6 48 43.3 53 45.5 
Dry hole— — — — — — 
Total23 20.6 48 43.3 53 45.5 
Wells in progress at end of year 1
6.3 7.3 11 10.2 
_____________________________________________
1 Includes two gross (1.9 net) wells completing, three gross (2.7 net) wells waiting on completion and two gross (1.7 net) wells being drilled as of December 31, 2020.
Present Activities
As of March 5, 2021, three gross (2.8 net) wells were completing and nine gross (7.1 net) wells were in progress.
Delivery Commitments
We generally sell our crude oil, NGL and natural gas products using short-term floating price physical and spot market contracts. We have commitments to provide minimum deliveries of crude oil of 8,000 BOPD (gross) through 2031 under gathering and transportation agreements with Nuevo Dos Gathering and Transportation, LLC and Nuevo Dos Marketing LLC. Our production and reserves are currently sufficient to fulfill the current 8,000 BOPD delivery commitment under these agreements.
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Productive Wells
The following table sets forth our productive wells in which we had a working interest as of December 31, 2020:
 Primarily OilPrimarily Natural GasTotal
GrossNetGrossNetGrossNet
Total productive wells509 429.1 23 22.2 532 451.3 
Of the total wells presented in the table above, we are the operator of 520 gross (497 oil and 23 natural gas) and 449.4 net (427.2 oil and 22.2 natural gas) wells. In addition to the above working interest wells, we own overriding royalty interests in 18 gross wells. During 2020, we formally reclassified 23 gross wells to gas from oil with the Texas Railroad Commission.
Acreage
The following table sets forth our developed and undeveloped acreage as of December 31, 2020 (in thousands):
Developed Undeveloped Total 
Gross Net Gross Net Gross Net 
Total acreage91.079.87.26.598.286.3
The primary terms of our leases generally range from three to five years, and we do not have any concessions. As of December 31, 2020, our net undeveloped acreage is scheduled to expire as shown in the table below, unless the primary lease terms are, where appropriate, extended, HBP or otherwise changed (in thousands):
202120222023Thereafter
Expirations by year1.23.12.2
We anticipate paying options to extend a substantial portion of the acreage scheduled to expire in 2021. We do not believe that the remaining scheduled expirations of our undeveloped acreage will substantially affect our ability or plans to conduct our exploration and development activities.
Item 3    Legal Proceedings
See Note 14 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” We are not aware of any material legal or governmental proceedings against us, or threatened to be brought against us, under the various environmental protection statutes to which we are subject.
Item 4    Mine Safety Disclosures
Not applicable.
38


Part II
 Item 5    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Since December 28, 2016, our common stock has been listed and traded on the Nasdaq under the symbol “PVAC.”
Equity Holders
As of February 12, 2021, there were 113 record holders of our common stock.
Dividends
We have not paid nor do we currently have plans to pay any cash dividends on our common stock in the foreseeable future. Furthermore, we are limited in our ability to pay dividends under the Credit Facility and the Second Lien Facility.
Securities Authorized for Issuance Under Equity Compensation Plans
See Part III, Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” and Note 16 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data” for information regarding shares of common stock authorized for issuance under our stock compensation plans.
Issuer Purchases of Equity Securities
We did not repurchase any shares of our common stock in the fourth quarter of 2020.



39


Item 6    Selected Financial Data
The following selected historical financial and operating information was derived from our Consolidated Financial Statements. The selected financial data should be read in conjunction with Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our Consolidated Financial Statements and the accompanying Notes and Supplementary Data in Part II, Item 8, “Financial Statements and Supplementary Data.”
 (in thousands, except per share amounts, sales volume and reserves)
Successor 1
Predecessor 1
September 13January 1
Year EndedThroughThrough
December 31,December 31,September 12,
 202020192018201720162016
Statements of Operations and Other Data:    
Revenues 2
$273,268 $471,216 $440,832 $160,054 $39,003 $94,310 
Operating income (loss) 3, 4
$(369,175)$176,821 $208,755 $51,872 $11,413 $(20,867)
Net income (loss) 4, 5
$(310,557)$70,589 $224,785 $32,662 $(5,296)$1,054,602 
Preferred stock dividends$— $— $— $— $— $5,972 
Income (loss) attributable to common shareholders 5
$(310,557)$70,589 $224,785 $32,662 $(5,296)$1,048,630 
Income (loss) per common share, basic$(20.46)$4.67 $14.93 $2.18 $(0.35)$11.91 
Income (loss) per common share, diluted$(20.46)$4.67 $14.70 $2.17 $(0.35)$8.50 
Weighted-average shares outstanding:  
Basic15,176 15,110 15,059 14,996 14,992 88,013 
Diluted15,176 15,126 15,292 15,063 14,992 124,087 
Dividends declared per share $— $— $— $— $— $— 
Cash provided by operating activities$221,778 $320,194 $272,132 $81,710 $30,774 $30,247 
Cash paid for capital expenditures$168,565 $362,743 $430,592 $115,687 $4,812 $15,359 
Total sales volume (MBOE)8,887 10,121 7,944 3,779 1,039 3,346 
December 31,September 12,
202020192018201720162016
Balance Sheet and Other Data:
Property and equipment, net$723,549 $1,120,425 $927,994 $529,059 $247,473 $253,510 
Total assets$907,326 $1,218,238 $1,068,954 $629,597 $291,686 $333,974 
Long-term debt, net$509,497 $555,028 $511,375 $265,267 $25,000 $75,350 
Shareholders’ equity$212,838 $520,745 $447,355 $221,639 $185,548 $190,895 
Actual shares outstanding at period-end15,200 15,136 15,081 15,019 14,992 14,992 
Proved reserves as of December 31, (MMBOE)126 133 123 73 49 N/A
_____________________________________________
1    Upon our emergence from bankruptcy, we adopted and applied fresh start accounting. Accordingly, our financial statements for periods after September 12, 2016 are not comparable to those prior to that date. Financial information for the periods up to and including September 12, 2016 are referred to herein as those of the “Predecessor” while those beginning on September 13, 2016 and all periods thereafter are referenced as those of the “Successor.”
2    Revenues for the years ended after December 31, 2017 reflect the application of Accounting Standards Codification, or ASC, Topic 606, Revenues from Contracts with Customers, or ASC Topic 606. The adoption of ASC Topic 606 impacts the presentation and comparability of NGL product revenues between the years beginning after December 31, 2017 with those years ending on that date and all prior periods. See Note 2 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
3    Operating income (loss) for the year ended December 31, 2020 reflects the application of Accounting Standards Update, or ASU, No. 2016-13, Measurement of Credit Losses on Financial Instruments, or ASU 2016-13. The adoption of ASU 2016-13 impacts the presentation and comparability of Other revenues, net between the year ended December 31, 2020 with all prior periods. Operating income (loss) for the year ended December 31, 2019 reflects the application of ASC Topic 842, Leases, or ASC Topic 842. The adoption of ASC Topic 842 impacts the presentation and comparability of lease expense between the years ended December 31, 2020 and 2019 with all prior periods. See “Presentation of Financial Information and Changes in Accounting Principles” included in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 2 and 5 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
4    Includes impairments of our oil and gas properties of $391.8 million for the year ended December 31, 2020.
5    Net income (loss) and Income (loss) attributable to common shareholders for the year ended December 31, 2018 and the period of January 1 through September 12, 2016 includes reorganization items resulting in income attributable to our bankruptcy proceedings of $3.3 million and $1.1 billion, respectively.

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Item 7    Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Part II, Item 8, “Financial Statements and Supplementary Data.” All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Also, due to the combination of different units of volumetric measure and the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables. Certain statistics for years ended December 31, 2019 and 2018 have been reclassified to conform to the 2020 presentation.
 Overview and Executive Summary
We are an independent oil and gas company focused on the onshore exploration, development and production of crude oil, NGLs and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in Gonzales, Lavaca, Fayette and DeWitt Counties in South Texas.
Industry Environment and Recent Operating and Financial Highlights
Commodity Price and Other Economic Conditions
The global public health crisis associated with the novel coronavirus, or COVID-19, has, and is anticipated to continue to have, an adverse effect on the global economy, which may be prolonged, and has resulted in travel restrictions, business closures, limitations to person-to-person contact and the institution of quarantining and other restrictions on movement in many communities. These restrictions resulted in a dramatic decline in the demand for energy in 2020, which directly impacted our industry and the Company. In addition, global crude oil prices experienced significant decline since the beginning of 2020 as a result of the dual impact of demand deterioration and market oversupply caused by disagreements between the Organization of the Petroleum Exporting Countries, or OPEC, and Russia, together with OPEC, collectively OPEC+, with respect to production curtailments. OPEC+ ultimately agreed to specified reductions in production in the Spring of 2020 which, for the most part, held for the remainder of the year and were supplemented by additional voluntary downward adjustments, led primarily by Saudi Arabia. Collectively these curtailments have contributed to a relative stabilization of commodity prices and rebalancing of the global crude oil markets by the end of 2020.
Notwithstanding the relative improvement in global market stability, as a result of several factors including rising infection rates at the beginning of 2021, mutating strains of the virus, the return of stricter lockdown measures and logistical challenges in vaccine distribution, among others, a return to pre-COVID 19 levels of economic activity remain uncertain in their magnitude and eventual timing. Nonetheless, OPEC+ indicated in their January 2021 meeting a commitment to gradually return limited production to the market with the pace being determined by market conditions. An additional meeting is scheduled for early March of 2021 to monitor conditions and progress.
A significant decline in domestic drilling by U.S. producers began in mid-March 2020 and continued through most of the second half of the year. The overall economic decline had an adverse impact on the entire industry, but particularly on smaller upstream producers with limited financial resources as well as oilfield service companies. While a modest recovery in activity began in the fourth quarter of 2020, including a resumption of our own drilling program, domestic supply and demand imbalances continue to stress the market which is further exacerbated by capacity limitations associated with storage, pipeline and refining infrastructure, particularly within the Gulf Coast region.
While there exists encouraging signs for continued recovery due to the aforementioned vaccine development as well as a commitment by the new U.S. Administration to prioritize economic relief efforts, the relative success of such efforts is difficult to predict with respect to timing and the resulting economic impact. Accordingly, the combined effect of the global and domestic factors discussed herein is anticipated to continue to contribute to overall volatility within the industry generally and to our operations specifically.
The combined effect of COVID-19 and the continuing energy industry instability has led to significant volatility in NYMEX WTI crude oil prices throughout 2020 and into 2021. In the beginning of January 2020, prices were approximately $62 per barrel and ended the year at approximately $48 per barrel for a decrease of approximately 23 percent. Prices have continued to rise and since the beginning of 2021 have ranged from approximately $47 to $66 per barrel through March 5, 2021. Despite this recovery, overall crude oil pricing will remain subject to significant volatility consistent with the global and domestic factors discussed above.

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During 2020, we initiated several actions to mitigate the anticipated adverse economic conditions for the immediate future and to support our financial position and liquidity. The more significant actions that we took during that time included: (i) temporarily suspending our drilling program from April through September 30, 2020, (ii) curtailing production through selected well shut-ins for a period of several weeks in April and May, (iii) securing additional crude oil storage capacity, (iv) substantially expanding the scope and range of our commodity derivatives portfolio, (v) utilizing certain provisions of the Coronavirus Aid, Relief and Economic Security Act, or CARES Act, and related regulations, the most significant of which resulted in the receipt in June 2020 of an accelerated refund of our remaining refundable alternative minimum tax, or AMT, credit carryforwards in the amount of $2.5 million and (vi) eliminating annual cost-of-living and similar adjustments to our salaries and wages for 2020, and a limited RIF during the third quarter of 2020.
These actions are described in greater detail in the discussions for Key Developments that follow as well as Notes 2, 6, 10 and 14 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
Capital Expenditures and Development Progress
We temporarily suspended our drilling program from April through September 2020. During that period, we selectively completed and turned our remaining eight gross (7.6 net) wells to sales that were drilled prior to the program suspension. As a result of a modest improvement in commodity prices relative to the first half of 2020, we resumed a limited drilling program in October 2020 with one rig and expanded to two rigs later in November 2020 continuing into 2021.
During 2020, we incurred capital expenditures of approximately $130.6 million with 96 percent directed to drilling and completion projects through which a total of 23 gross (20.6 net) wells were drilled, completed and turned to sales.
Sequential Quarterly Analysis
The following summarizes our key operating and financial highlights for the three months ended December 31, 2020 with comparison to the three months ended September 30, 2020 as presented in the table that follows. The year-over-year highlights for 2020 and 2019 are addressed in further detail in the discussions for Financial Condition and Results of Operations that follow.
Daily sales volume decreased approximately 12 percent to 21,502 BOEPD, from 24,295 BOEPD due primarily to the effect of natural well declines in the absence of an active drilling program that did not resume until October of 2020 as well as the impact of turning only two gross (2.0 net) wells to sales during the fourth quarter of 2020 as compared to five gross (4.8 net) wells during the third quarter of 2020. Total sales volume declined approximately 12 percent to 1,978 MBOE from 2,235 MBOE due to the aforementioned natural well declines and drilling program timing. While overall sales volume declined, the percentage of crude oil volume sold increased to 78 percent from 76 percent during the fourth quarter of 2020.
Product revenues decreased three percent to $66.5 million from $68.6 million due primarily to nine percent lower crude oil volume, or $5.7 million, partially offset by six percent higher crude oil prices, or $3.5 million. NGL revenues declined six percent due to 19 percent lower volume, or $0.6 million, partially offset by 16 percent higher prices, or $0.4 million. Natural gas revenues increased 10 percent due to a 36 percent increase in pricing, or $0.8 million, partially offset by a 19 percent decrease in volume, or $0.5 million.
Production and lifting costs (consisting of LOE and GPT) increased on an absolute and per unit basis to $14.8 million and $7.49 per BOE from $14.0 million and $6.28 per BOE due primarily to higher preventive and other previously deferred maintenance and workover costs, higher environmental compliance costs as well as higher crude oil storage costs partially offset by lower volumetric and variable-based costs attributable to the overall lower sales volume.
Production and ad valorem taxes decreased on an absolute and per unit basis to $3.5 million and $1.75 per BOE from $4.4 million and $1.95 per BOE, respectively, due primarily to the effect of substantially lower estimated valuations for ad valorem tax assessments as well as the effect of overall lower product revenues.
G&A expenses increased on an absolute and per unit basis to $10.0 million and $5.05 per BOE from $8.6 million and $3.84 per BOE, respectively, due primarily to higher costs incurred in connection with the Juniper Transaction.
Our DD&A, decreased on an absolute and per unit basis to $25.8 million and $13.03 per BOE from $37.0 million and $16.57 per BOE due primarily to higher reserve quantity estimates and, to a lesser extent, the reduction to costs attributable to the impairment recorded during the third quarter of 2020.
In the fourth quarter of 2020, we recorded an impairment of our oil and gas properties of $120.3 million as the unamortized cost of our oil and gas properties, net of deferred income taxes, exceeded the sum of discounted future net revenues from proved properties adjusted for costs excluded from amortization and related income taxes, or the Ceiling Test. The impairment is primarily attributable to a decline in the trailing twelve-month average prices of crude oil, NGLs and natural gas. We recorded an impairment of $236.0 million as a result of similar conditions in the third quarter of 2020.
Due to the combined impact of the matters noted in the bullets above, we incurred an operating loss of $107.4 million in the fourth quarter of 2020 compared to $230.6 million in the third quarter of 2020.
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The following table sets forth certain historical summary operating and financial statistics for the periods presented: 
(in thousands except per unit measurements, sales volume, wells and reserves)
Three Months Ended
 December 31,September 30,Year Ended December 31,
 20202020202020192018
Total sales volume (MBOE) 1
1,978 2,235 8,887 10,121 7,944 
Average daily sales volume (BOEPD) 1
21,502 24,295 24,281 27,730 21,765 
Crude oil sales volume (MBbl) 1
1,538 1,691 6,829 7,453 6,077 
Crude oil sold as a percent of total 1
78 %76 %77 %74 %76 %
Product revenues$66,491 $68,614 $270,792 $469,035 $439,530 
Crude oil revenues$61,009 $63,227 $251,741 $434,713 $402,485 
Crude oil revenues as a percent of total92 %92 %93 %93 %92 %
Realized prices:
Crude oil ($ per Bbl)$39.66 $37.39 $36.86 $58.33 $66.23 
NGL ($ per Bbl) $10.71 $9.20 $7.68 $11.13 $20.99 
Natural gas ($ per Mcf)$2.45 $1.80 $1.88 $2.51 $3.08 
Aggregate ($ per BOE)$33.61 $30.70 $30.47 $46.34 $55.33 
Prices, adjusted for derivatives:
Crude oil ($ per Bbl)$48.84 $48.28 $50.55 $56.92 $73.21 
Natural gas ($ per Mcf)$1.95 $1.88 $1.88 $2.51 $3.08 
Aggregate ($ per BOE)$40.46 $38.99 $40.98 $45.30 $60.67 
Production and lifting costs ($ per BOE):
Lease operating$4.83 $3.70 $4.22 $4.26 $4.52 
Gathering, processing and transportation $2.66 $2.58 $2.48 $2.29 $2.34 
Production and ad valorem taxes ($ per BOE)$1.75 $1.95 $1.87 $2.77 $2.96 
General and administrative ($ per BOE) 2
$5.05 $3.84 $3.80 $2.52 $3.28 
Depreciation, depletion and amortization ($ per BOE)$13.03 $16.57 $15.83 $17.25 $16.11 
Capital expenditure program costs 3
$32,627 $8,042 $130,608 $355,851 $418,951 
Cash provided by operating activities 4
$32,055 $60,828 $221,778 $320,194 $272,132 
Cash paid for capital expenditures 5
$29,535 $26,183 $168,565 $362,743 $430,592 
Cash and cash equivalents at end of period$13,020 $20,516 $13,020 $7,798 $17,864 
Debt outstanding, net of discount and issue costs, at end of period 6
$509,497 $518,858 $509,497 $555,028 $511,375 
Credit available under credit facility at end of period 7
$35,200 $50,200 $35,200 $137,200 $128,600 
Net development wells drilled and completed2.0 4.8 20.6 43.3 45.5 
Proved reserves at the end of the period (MMBOE)126 N/A126 133 123 
_____________________________________________
1    All volumetric statistics presented above represent volumes of commodity production that were sold during the periods presented. Volumes of crude oil physically produced in excess of volumes sold are placed in temporary storage to be sold in subsequent periods.
2    Includes combined amounts of $1.93 and $1.20 per BOE for the three months ended December 31, 2020 and September 30, 2020, respectively, and $1.09, $0.48 and $1.11 per BOE for the years ended December 31, 2020, 2019 and 2018, respectively, attributable to share-based compensation and significant special charges, comprised of organizational restructuring and acquisition, divestiture and strategic transaction costs, including costs attributable to the Juniper Transaction during the 2020 periods, as described in the discussion of “Results of Operations - General and Administrative” that follows.
3    Includes amounts accrued and excludes capitalized interest and capitalized labor.
4    Includes net cash received for derivative settlements and premiums (paid) received, net of $12.8 million and $6.4 million for the three months ended December 31, 2020 and September 30, 2020, respectively, and net cash received (paid) for derivative settlements of $78.1 million, $(4.1) million and $(48.3) million for the years ended December 31, 2020, 2019 and 2018, respectively. Reflects changes in operating assets and liabilities of $(12.9) million and $17.8 million for the three months ended December 31, 2020 and September 30, 2020, respectively, and $4.1 million, $0.2 million and $(2.8) million for the years ended December 31, 2020, 2019 and 2018, respectively.
5     Represents actual cash paid for capital expenditures including capitalized interest and capitalized labor.
6     Represents amounts net of unamortized discount and deferred issue costs of $4.9 million, $5.5 million $7.4 million and $9.6 million as of December 31, 2020, September 30, 2020, December 31, 2019 and December 31, 2018, respectively.
7     The borrowing base under the Credit Facility was $375 million as December 31, 2020 with availability further limited to a maximum of $350 million.


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Key Developments
The following general business developments had or may have a significant impact on our results of operations, financial position and cash flows:
Strategic Investment by Juniper
In January 2021, we consummated the previously announced Juniper Transactions whereby affiliates of Juniper contributed $150 million in cash and certain oil and gas assets in Lavaca and Fayette Counties in Texas in exchange for a combination of shares of Series A Preferred Stock of the Company and Common Units of a wholly owned subsidiary. The Juniper Transactions, which were effectuated through an up-C structure, represent a change in control of the Company whereby Juniper now controls approximately 60 percent of the economic and voting interests of the Company. We incurred a total of $18.5 million in transaction and securities issuance costs associated with the Juniper Transactions including $5.0 million in 2020 as well as an additional $13.5 million in January 2021. For additional information regarding the Juniper Transactions, see Part I, Item 1, “Business” and Note 2 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
Amendments to Credit Facility and Affirmation of Borrowing Base
In January 2021, we entered into the Ninth Amendment permitting the Juniper Transactions and affirming our borrowing base at $375 million with borrowings limited to a maximum of $350 million. In addition, the Ninth Amendment provides for: (i) certain minimum hedging conditions, which were initially satisfied in February 2021, allowing for a borrowing base holiday until Fall 2021 assuming we continue to satisfy the conditions, (ii) introduces a first lien leverage ratio covenant of 2.50 times, tested quarterly and (iii) permits amortization payments of up to $1.875 million per quarter to be made under the Second Lien Facility until January 2022 if no default exists both before and after giving effect to the payments and thereafter using available free cash flow upon the satisfaction of certain conditions (including maintaining a leverage ratio of 2.00 to 1.00 and availability of at least 25% under the Credit Facility after giving pro forma effect to the payment). For additional information regarding the Ninth Amendment see the discussion of Financial Condition that follows and Note 9 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” Concurrent with the Ninth Amendment, we paid down $80.5 million of outstanding borrowings under the Credit Facility plus accrued interest of $0.1 million which was funded with the proceeds from the Juniper Transaction. We incurred and capitalized $0.4 million of issue and other costs associated with the Ninth Amendment in January 2021.
Amendment to the Second Lien Facility
On November 2, 2020, we entered into the Second Lien Amendment which became effective upon the Closing of the Juniper Transactions. The Second Lien Amendment (1) extends the maturity date of the Second Lien Facility to September 29, 2024, (2) increases the margin applicable to advances under the Second Lien Facility as further described below; (3) impose certain limitations on capital expenditures, acquisitions and investments if the Asset Coverage Ratio (as defined therein) at the end of any fiscal quarter is less than 1.25 to 1.00 and (4) requires maximum and, in certain circumstances as described therein, minimum hedging arrangements.
Under the Second Lien Amendment, the Company is required to make quarterly amortization payments equal to $1,875,000 and outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime rate plus an applicable margin of 8.25% or (b) a customary London interbank offered rate plus an applicable margin of 7.25%; provided that the applicable margin will increase to 9.25% and 8.25% respectively during any quarter in which the quarterly amortization payment is not made.
We have the right, to the extent permitted under the Credit Facility and an intercreditor agreement between the lenders under the Credit Facility and the lenders under the Second Lien Facility, to prepay loans under the Second Lien Facility at any time, subject to the following prepayment premiums (in addition to customary “breakage” costs with respect to Eurodollar loans): from January 15, 2021 through January 14, 2022, 102% of the amount being prepaid, from January 15, 2022 through January 14, 2023, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following prepayment premiums in the event of a change in control that results in an offer of prepayment that is accepted by the lenders under the Second Lien Facility: from January 15, 2021 through January 14, 2023, 102% of the amount being prepaid, from January 15, 2023 through January 14, 2024, 101% of the amount being prepaid; and thereafter, no premium.
Additionally, on the Closing Date, we entered into the Omnibus Amendment to the Second Lien Facility (the “Omnibus Amendment”) to, among other things, effectuate the release of the Company from its guarantee of the obligations of the Borrower and its grant of a security interest in its assets.

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Additional restrictions and other qualifications associated with the Second Lien Facility, as amended by the Second Lien Amendment and the Omnibus Amendment, or the Amended Second Lien Facility, are described in the discussion of Financial Condition that follows and Note 9 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” We paid down $50.0 million of outstanding loans under the Amended Second Lien Facility plus accrued interest of $0.2 million attributable to lenders and $1.3 million including accrued interest to a non-consenting lender in January 2021 which was funded with the proceeds from the Juniper Transaction. We incurred and capitalized $1.4 million of issue and other costs and wrote-off $1.3 million of unamortized issuance costs in connection with the Second Lien Amendment in January 2021.
Development Plans and Production
In October 2020, we resumed a limited drilling and completion program on a pad-to-pad basis and are currently drilling with two operated rigs. During December 2020, we made prepayments of $13.6 million for drilling and completion materials and services securing locked in rates or discounts in advance of the program for the first quarter of 2021.
We completed and turned two gross (2.0 net) and 23 gross (20.6 net) wells to sales during the quarter and year ended December 31, 2020, respectively. Subsequent to December 31, 2020, we turned an additional five gross (4.5 net) wells to sales through March 5, 2021. As of March 5, 2021, three gross (2.8 net) wells were completing and nine gross (7.1 net) wells were in progress.
Total sales volume for the quarter and year ended December 31, 2020 was 1,978 MBOE and 8,887 MBOE, or 21,502 and 24,281 BOEPD, with approximately 78 percent and 77 percent, or 1,538 MBbls and 6,829 MBbls, of sales volume from crude oil, 12 and 13 percent from NGLs and 10 percent for both periods each from natural gas, respectively.
As of March 5, 2021, we had approximately 102,100 gross (90,100 net) acres in the Eagle Ford, net of expirations. Approximately 92 percent of our acreage is held by production and substantially all is operated by us.
Executive Transition
In August 2020, we appointed Darrin Henke our new president and chief executive officer, or CEO, and director following the retirement of John Brooks. We incurred incremental G&A costs, in connection with Mr. Henke’s appointment and Mr. Brooks’ separation as described in the discussion for Results of Operations that follow.
On January 15, 2021, we announced the departure of Benjamin A. Mathis, Senior Vice President, Operations & Engineering, effective January 4, 2021. Separately, we also announced the appointment of Julia Gwaltney as Senior Vice President, Development, effective January 5, 2021.
In connection with the Juniper Transactions, five new members were appointed to our Board of Directors including: (i) Edward Geiser - Managing Partner of Juniper Capital, (ii) Kevin Cumming - Partner of Juniper Capital, (iii) Tim Gray - General Counsel and Chief Compliance Officer of Juniper Capital, (iv) Joshua Schmidt - Managing Director of Juniper Capital and (v) Temitope Ogunyomi - Director of Juniper Capital.
Actions to Address the Economic Impact of COVID-19 and Industry Decline
During 2020, we initiated and pursued several actions to mitigate the adverse economic conditions and to support our financial position, liquidity and the efficient continuity of our operations as follows:
Drilling Program. We suspended our drilling program beginning in April 2020 through September 2020. See Note 14 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data” for additional information.
Production Curtailment. In April 2020, we shut-in production on selected wells for a period of several weeks extending through mid-May 2020.
Crude Oil Storage. We secured supplemental storage capacity for our crude oil production primarily on a month-to-month basis. See Note 14 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data” for additional information.
Derivatives. We substantially expanded the scope and range of our commodity derivatives portfolio during the early stages of the domestic COVID-19 health crisis. For the year ended December 31, 2020, we received $80.3 million in net cash proceeds from settlements, net of premiums, of our commodity derivatives. A portion of these proceeds were received in the second and third quarters of 2020 from contracts that were either restructured or put into place early in March and April of 2020.
Federal Relief. We utilized a number of liquidity and income tax measures made available under the CARES Act and related regulations, the most significant of which was the application for an accelerated refund of our remaining alternative minimum tax, or AMT, credits of $2.5 million, which was received in June 2020, that would have otherwise been payable to us over the next two years.
Working Capital. We are continuing our increased diligence in collecting and managing our portfolio of joint venture receivables.
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Cost Containment. We eliminated annual cost-of-living and similar adjustments to our salaries and wages for 2020, and in July 2020, we completed a limited RIF. We incurred and paid employee termination and severance benefits in connection with the limited RIF and those costs have been included in G&A. In addition, we implemented protocols and systems, designed to keep our employees safe and our operations at desired capacity during the COVID-19 pandemic.
Commodity Hedging Program
As of February 25, 2021, we have hedged a portion of our estimated future crude oil, natural gas and ethane production through the first half of 2023. The following table, inclusive of January and February 2021 production months, summarizes our hedge positions for the periods presented:
1Q20212Q20213Q20214Q20211Q20222Q20223Q20224Q20221Q20232Q2023
NYMEX WTI Crude Swaps
Average Volume Per Day (barrels)3,889 3,297 815 815 
Weighted Average Swap Price ($/barrel)$54.38 $55.89 $45.54 45.54 
NYMEX WTI Crude Collars
Average Volume Per Day (barrels)10,278 12,088 10,870 8,152 5,417 4,533 4,484 4,484 2,917 2,855 
Weighted Average Purchased Put Price ($/barrel)$40.92 $43.82 $41.80 $40.40 $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 
Weighted Average Sold Call ($/barrel)$46.51 $54.67 $56.09 $52.10 $53.49 $52.47 $52.47 $52.47 $50.00 $50.00 
NYMEX WTI Purchased Puts
Average Volume Per Day (barrels)1,667
Weighted Average Purchased Put Price ($/barrel)$55.00 
NYMEX WTI Sold Puts
Average Volume Per Day (barrels)5564,945 5,7075,707 
Weighted Average Sold Put ($/barrel)$26.50 $29.83 $35.14 35.14 
MEH-NYMEX WTI Crude Basis Swaps
Average Volume Per Day (barrels)8,889
Weighted Average Swap Price ($/barrel)$1.16 
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (barrels)16,11118,132 17,93517,935 
Weighted Average Swap Price ($/barrel)$(0.11)$0.17 $0.17 $0.17 
NYMEX HH Collars
Average Volume Per Day (MMBtus)10,000 9,890 9,783 9,783 
Weighted Average Purchased Put Price ($/MMBtu)$2.607 $2.607 $2.607 $2.607 
Weighted Average Sold Call ($/MMBtu)$3.117 $3.117 $3.117 $3.117 
NYMEX HH Sold Puts
Average Volume Per Day (MMBtus)6,667 6,593 6,522 6,522 
Weighted Average Sold Put Strike ($/MMBtu)$2.000 $2.000