UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________
FORM 10-K
________________________________________________________
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
or
For the transition period from ____ to ____
Commission file number: 1-13283
_________________________________________________________
PENN VIRGINIA CORPORATION
(Exact name of registrant as specified in its charter)
Virginia
(State or other jurisdiction of
incorporation or organization)
23-1184320
(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: (713) 722-6500
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, $0.01 Par Value
Name of exchange on which registered
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 ý
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 ý
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 ý 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 ý No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or 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. (Check One)
Large accelerated filer
Accelerated filer
o
Non-accelerated filer
o
ý
Smaller reporting company
Emerging growth company
o
o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No ý
The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was $1,086,140,215 as of June 29, 2018 (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 ý No ¨
As of February 22, 2019, 15,105,251 shares of common stock of the registrant were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information called for in Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference to the registrant’s definitive proxy statement or will be included
in an amendment to this Annual Report on Form 10-K.
PENN VIRGINIA CORPORATION
ANNUAL REPORT ON FORM 10-K
For the Fiscal Year Ended December 31, 2018
Table of Contents
Forward-Looking Statements
Glossary of Certain Industry Terminology
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Part I
Part II
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Selected Financial Data
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
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Part III
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Part IV
Exhibits, Financial Statement Schedules
Form 10-K Summary
Item
1.
1A.
1B.
2.
3.
4.
5.
6.
7.
7A.
8.
9.
9A.
9B.
10.
11.
12.
13.
14.
15.
16.
Signatures
Page
1
2
4
12
29
29
35
35
36
38
39
42
44
48
60
60
61
65
107
107
107
108
108
108
108
108
109
111
112
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:
•
all of the risks and uncertainty related to our announced merger with Denbury Resources Inc., including the risk that the conditions to
the closing of the transaction are not satisfied and the additional risks discussed in Part I, Item 1A of this report;
•
risks related to completed acquisitions, 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 to fund our capital expenditures and meet working capital
needs;
• 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;
the decline in and volatility of commodity prices for oil, natural gas liquids, or NGLs, and natural
gas;
• our ability to develop, explore for, acquire and replace oil and gas reserves and sustain
production;
• our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and
well
operations;
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 and operating
risks;
• 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;
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, 2018.
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.
Drilling carry. A working interest that will be carried through the drilling and completion of a 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.
IP. Initial production, a measurement of a well’s production at the outset.
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.
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.
2
NYMEX. New York Mercantile Exchange.
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.
Possible reserves. Those additional reserves that are less certain to be recovered than probable reserves. When probabilistic methods are
used, there should be at least a 10 percent probability that the total quantities ultimately recovered will equal or exceed the proved plus probable
plus possible reserves estimates.
Probable reserves. Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved
reserves, are as likely as not to be recovered. When probabilistic methods are used, there should be at least a 50 percent probability that the
actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
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.
Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such
wells customarily are drilled without the intention of being completed for hydrocarbon production.
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
Item 1
Business
Part I
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
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 primarily 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.
Current Operations
We lease a highly contiguous position of approximately 84,200 net acres (as of December 31, 2018) 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 2018, our total production was comprised of 76 percent crude oil, 13 percent NGLs and 11 percent natural gas. Crude oil accounted for
92 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, 2018, our total proved reserves were approximately 123 MMBOE, of which 38 percent were proved developed
reserves and 73 percent were crude oil. As of December 31, 2018, we had 460 gross (377.5 net) productive wells, approximately 97 percent of
which we operate, and owned approximately 98,200 gross (84,200 net) acres of leasehold and royalty interests, approximately 9 percent of
which were undeveloped. Approximately 92 percent of our acreage is HBP and includes a substantial number of undrilled locations. During
2018, we drilled and completed 53 gross (45.5 net) wells, all in the Eagle Ford. For a more detailed discussion of our production, reserves,
drilling activities, wells and acreage, see Part I, Item 2, “Properties.”
On October 28, 2018, Denbury Resources Inc., or Denbury, and Penn Virginia announced that they entered into a definitive merger
agreement, or the Merger Agreement, pursuant to which Denbury will acquire Penn Virginia, or the Merger. The consideration to be paid to
Penn Virginia shareholders will consist of 12.4 shares of Denbury common stock and $25.86 of cash for each share of Penn Virginia common
stock. Penn Virginia shareholders will be permitted to elect to receive either all cash, all stock or a mix of stock and cash, in each case subject to
proration, which will result in the aggregate issuance by Denbury of approximately 191.667 million Denbury shares and payment by Denbury of
$400 million in cash. The transaction was unanimously approved by the board of directors of each company, and certain Penn Virginia
shareholders holding approximately 15 percent of the outstanding shares signed voting agreements to vote “for” the transaction. The transaction
is subject to the approval by the holders of more than two-thirds of the outstanding Company common shares, the approval by the holders of a
majority of the outstanding Denbury common shares of an amendment to the certificate of incorporation to increase the number of authorized
Denbury common shares, the approval of the issuance of Denbury common shares in the Merger by the holders of a majority of the Denbury
common shares represented in person or by proxy at a meeting of Denbury shareholders held to vote on such matter and other customary
closing conditions. The special meeting of shareholders to approve the merger is anticipated in April 2019 and closing is anticipated soon
thereafter, subject to shareholder approval and certain other conditions. The Merger Agreement contains certain termination rights for both
Denbury and the Company, including if the Merger is not consummated by April 30, 2019, and requires Penn Virginia to pay a $45 million
termination fee in certain circumstances.
On July 31, 2018, we sold all of our remaining Mid-Continent oil and gas properties, located primarily in Oklahoma in the Granite Wash.
We realized net proceeds of $5.7 million in connection with the sale and utilized those funds in our Eagle Ford development program.
Subsequent to the sale, our operations are exclusively focused in the Eagle Ford in South Texas.
On March 1, 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 Gonzalez and Lavaca Counties, Texas. For a more detailed discussion of this
acquisition, see “Key Developments” included in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and Note 5 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
4
Emergence from Bankruptcy Proceedings and Fresh Start Accounting
On May 12, 2016, or the Petition Date, we and eight of our subsidiaries, or the Chapter 11 Subsidiaries, filed voluntary petitions ( In re
Penn Virginia Corporation, et al., Case No. 16-32395) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code, or the
Bankruptcy Code, in the United States Bankruptcy Court for the Eastern District of Virginia, or the Bankruptcy Court.
On August 11, 2016, or the Confirmation Date, the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of
Reorganization of Penn Virginia Corporation and its Debtor Affiliates, or the Plan, and we subsequently emerged from bankruptcy on September
12, 2016, or the Emergence Date. On November 20, 2018, the Bankruptcy Court issued a final decree to close the case.
On the Emergence Date, we adopted and applied the relevant guidance with respect to the accounting and financial reporting for entities
that have emerged from bankruptcy proceedings, or Fresh Start Accounting. The adoption of Fresh Start Accounting resulted in a new reporting
entity, the Successor, for financial reporting purposes. To facilitate our discussion and analysis of our properties, financial condition and results
of operations herein, we refer to the reorganized company as the “Successor” for periods subsequent to September 12, 2016, and the
“Predecessor” for periods prior to September 13, 2016. For a more detailed discussion of our bankruptcy proceedings, our emergence from
bankruptcy and Fresh Start Accounting, 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 and bring our production to market. The following is a summary of our most significant contractual arrangements.
Oil gathering and transportation service contracts. We have long-term agreements that provide us with gathering and intermediate
pipeline transportation services for a substantial portion of our crude oil and condensate production through 2041 as well as volume capacity
support for certain downstream interstate pipeline transportation.
Natural gas service contracts. We have an agreement that provides us with gas lift, gathering, compression and short-haul transportation
services for a substantial portion of our natural gas 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. These agreements are evergreen in term with either party having the right to terminate with 30-days’ notice to
the counterparty.
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, 2018, there were no drilling,
completion or materials agreements with terms that extended beyond one year.
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,
2018, approximately 69 percent of our consolidated product revenues were attributable to three customers: Phillips 66 Company; BP Products
North America Inc. and Shell Trading (US) Company.
Seasonality
Our sales volumes of oil and 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.
5
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:
•
•
•
•
•
•
the
to stakeholders of proposed and ongoing
installation of expensive pollution control
the acquisition of various permits before drilling
require
commences;
require notice
operations;
require
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, 2018, we have recorded asset retirement
obligations of $4.3 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.
In addition, the United States Environmental Protection Agency, or the EPA, has designated energy extraction as one of six national
enforcement initiatives, and has indicated that the agency will direct resources towards addressing incidences of noncompliance from natural gas
extraction and production activities. 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, 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.
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.
6
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. For example, in December 2016, the EPA
and certain environmental organizations entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D
criteria regulations exempting certain exploration and production-related oil and gas wastes from regulation as hazardous wastes under RCRA.
The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations
pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. Any such change could result in an
increase in our costs to manage and dispose of wastes, which could have an adverse effect on our results of operations and financial position.
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. In January 2017, the United States Supreme
Court accepted review of the rule to determine whether jurisdiction to hear challenges to the rule rests with the federal district or appellate
courts. In January 2018, the Supreme Court ruled that district courts have jurisdiction over challenges to the rule. EPA has instituted
rulemakings to both delay the effective date of this rule and repeal the rule. Federal district court decisions have preserved the stay of the 2015
Clean Water Rule in Texas, which remains subject to pre-2015 regulated waters regulations, whereas the stay has been enjoined in a minority of
states. Litigation surrounding this rule is ongoing. More recently, on December 11, 2018, the EPA and the Corps released a proposal to revise
the 2015 Clean Water Rule so as to narrow the regulatory definition of waters of the United States, with a 60-day comment period to follow.
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.
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
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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. Certain states in which we operate have adopted regulations requiring the
disclosure of chemicals used in the hydraulic fracturing process. For instance, Texas has implemented chemical disclosure requirements for
hydraulic fracturing operations. We currently disclose all 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.
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.
8
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, 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. The NSPS for methane extends the
2012 NSPS to completions of hydraulically fractured oil wells, equipment leaks, pneumatic pumps and natural gas compressors. In June 2017,
the EPA proposed a two year stay of the fugitive emissions monitoring requirements, pneumatic pump standards and closed vent system
certification requirements in the 2016 NSPS rule for the oil and gas industry while it reconsiders these aspects of the rule. The proposal is still
under consideration. More recently, in September 2018, the EPA proposed targeted improvements to the rule, including amendments to the
rule’s fugitive emissions monitoring requirements, and expects to “significantly reduce” the regulatory burden of the rule in doing so. The U.S.
Bureau of Land Management, or BLM, finalized similar 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 adopted final rules in January 2017; operators generally had one year from the January 2017 effective date of the rule to come into
compliance with the rule’s requirements. However, in December 2017, the BLM temporarily suspended or delayed certain of these requirements
set forth in its Venting and Flaring Rule until January 2019, and in September 2018, the BLM proposed a revised rule which would scale back
the waste-prevention requirements of the 2016 rule. Environmental groups sued in federal district court a day later to challenge the legality of
aspects of the revised rule, and the outcome of this litigation is currently uncertain. 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.
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 “greenhouse gases,” or 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.
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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. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and
to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement
provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United
States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated
agreement are unclear at this time.
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. On March 28, 2017, President Trump signed an Executive Order directing the EPA to review the regulations, and on
April 4, 2017, the EPA announced that it was reviewing the 2015 carbon dioxide regulations. On April 28, 2017, the U.S. Court of Appeals for
the District of Columbia stayed the litigation pending the current administration’s review. That stay was extended for another 60 days on
August 8, 2017. On October 10, 2017, the EPA initiated the formal rulemaking process to repeal the regulations, which has not been finalized.
In August 2018, the EPA proposed the Affordable Clean Energy rule (ACE) as a replacement to the 2015 regulations. ACE primarily addresses
onsite efficiency improvements for power plants and does not require generation-shifting to low- or zero-emitting energy sources. The EPA’s
proposals will be subject to public comment or legal challenge, and as such we cannot predict at this time what impact the rulemakings will have
on the demand for oil and gas production and our operations.
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.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may
produce climate changes that have significant physical effects, such as increased frequency and severity of storms, 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.
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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 and Labor Relations
We had a total of 95 employees as of December 31, 2018. We hire independent contractors on an as needed basis. We consider our current
employee relations to be favorable. We and our employees are not subject to any collective bargaining agreements.
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, Executive and Financial Officer Code of Ethics, Audit Committee Charter,
Compensation and Benefits Committee Charter and Nominating and Governance 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.
Risk Factors Associated with the Merger
There can be no assurance that we will obtain shareholder approval for the Merger or that the Merger will be consummated.
There can be no assurance that the Merger will be consummated and our shareholders will receive the merger consideration. The
completion of the Merger is subject to various closing conditions and termination rights (including if the Merger is not consummated by April
30, 2019). In addition to other conditions that are beyond our control, the Merger is subject to approval by the holders of more than two-thirds of
the outstanding Company common shares, the approval by the holders of a majority of the outstanding Denbury common shares of an
amendment to the certificate of incorporation to increase the number of authorized Denbury common shares, and the approval of the issuance of
Denbury common shares in the Merger by the holders of a majority of the Denbury common shares represented in person or by proxy at a
meeting of Denbury shareholders held to vote on such matters. We cannot guarantee that the closing conditions set forth in the Merger
Agreement will be satisfied or, even if satisfied, that no event of termination will take place. The completion of the Merger is not assured and is
subject to risks, including the risk that the approval of our shareholders or Denbury’s stockholders is not obtained. Activist shareholders may
increase the risk that the requisite votes are not obtained. In that regard, one shareholder of the Company (Mangrove Partners) has engaged in a
public campaign to prevent shareholder approval of the Merger, which campaign includes a preliminary proxy statement filed on January 17,
2019, that solicits votes in opposition to the Merger. Other Company shareholders or Denbury stockholders could oppose the proposals for
approval of the Merger. Any such campaign could result in substantial costs and divert each company’s respective management’s and directors’
attention and resources from each company’s respective business. Moreover, the Merger Agreement contains conditions, some of which are
beyond our control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Merger not occurring.
Because the exchange ratio in the Merger Agreement is fixed and because the market price of Denbury common stock will fluctuate prior to
the completion of the Merger, our shareholders cannot be sure of the market value of the Denbury common stock they will receive as Merger
consideration relative to the value of the cash and shares of common stock they exchange at the closing.
Under the terms of the Merger Agreement, our shareholders will receive the Merger Consideration, consisting of a combination of 12.4
shares of Denbury common stock and $25.86 of cash for each share of Company common stock, subject to election of the Company
shareholders to receive either all cash, all stock or a mix of stock and cash, in each case subject to proration. Based on the closing price of
Denbury common stock on October 26, 2018, the Merger Consideration represented consideration to each Company shareholder of $79.80 per
share. The exchange ratio for the Merger Consideration is fixed, and there will be no adjustment to the Merger Consideration for changes in the
market price of Denbury’s common stock or our common stock prior to the completion of the Merger.
If the Merger is completed, there will be a time lapse between the date of signing of the Merger Agreement and the date on which our
shareholders who are entitled to receive the Merger Consideration actually receive the Merger Consideration. The market value of shares of
Denbury’s common stock and our common stock has fluctuated and may continue to fluctuate during this period as a result of a variety of
factors, including general market and economic conditions, changes in each company’s business, operations and prospects, commodity prices,
regulatory considerations, and the market’s assessment of Denbury’s business and the Merger. Such factors are difficult to predict and in many
cases may be beyond the control of Denbury and us. The actual value of any Merger Consideration received by our shareholders at the
completion of the Merger will depend on the market value of the shares of Denbury common stock at that time. This market value may differ,
possibly materially, from the market value of shares of Denbury common stock at the time the Merger Agreement was entered into or at any
other time. The market value of shares of Denbury Common Stock has declined from $4.35 per share on the trade date immediately prior to the
public announcement of the Merger to $2.14 per share on February 22, 2019, and the market value of the Company common stock per share has
decreased from $67.39 to $56.24 in the same period. If the trading price of Denbury common stock at the closing of the Merger is less than the
trading price of Denbury common stock on the date that the Merger Agreement was signed, particularly if the trading price of the Company
common stock increases, then the market value of the Merger Consideration will be less than contemplated at the time the Merger Agreement
was signed. This could make it more difficult to obtain shareholder approval of and complete the Merger.
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Even if Denbury and the Company complete the Merger, Denbury may fail to realize all of the anticipated benefits of the Merger.
Even if we complete the Merger, the combined company may not realize the benefits and guidance provided by either Denbury or us,
including due to factors beyond the control of the combined company’s management. The success of the Merger will depend, in part, on
Denbury’s ability to realize the anticipated financial benefits from combining Denbury’s and the Company’s businesses, including synergies.
The anticipated financial benefits of the Merger may not be realized fully or at all, may take longer to realize than expected or could have other
adverse effects that neither we nor Denbury currently foresee. Some of the assumptions that we have made, such as the achievement of
synergies, may not be realized. The integration process may, for each of Denbury and the Company, result in the loss of key employees, the
disruption of ongoing businesses or inconsistencies in standards, controls, procedures and policies. There could be potential unknown liabilities
and unforeseen expenses associated with the Merger that were not discovered in the course of performing due diligence.
The Merger involves numerous operational, strategic, financial, accounting, legal, tax and other risks, potential liabilities associated with
the acquired businesses, and uncertainties related to design, operation and integration of the Company’s internal control over financial reporting.
Difficulties in integrating the Company into Denbury may result in the combined company performing differently than expected, in operational
challenges or in the failure to realize anticipated expense-related efficiencies. Denbury’s and the Company’s existing businesses could also be
negatively impacted by the Merger. Potential difficulties that may be encountered in the integration process include, among other factors:
•
•
the inability to successfully integrate the businesses of the Company into Denbury in a manner that permits the combined company
to achieve the full financial benefits anticipated from the Merger;
complexities associated with managing the larger, more complex, integrated
business;
• not realizing anticipated
•
synergies;
integrating personnel from the two companies and the loss of key
employees;
• potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the
•
Merger;
integrating relationships with customers, vendors and business
partners;
• performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing
•
the Merger and integrating the Company’s operations into Denbury; and
the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls,
procedures and policies.
We will incur significant transaction and Merger-related costs in connection with the Merger, which may be in excess of those anticipated by
us.
We have incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the Merger,
obtaining shareholder approval (including responding to any activist shareholders) and combining the operations of the two companies. These
fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs
related to the Merger and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and
benefit costs and filing fees.
We will also incur transaction fees and costs related to formulating and implementing integration plans, including facilities and systems
consolidation costs and employment-related costs. We will continue to assess the magnitude of these costs, and additional unanticipated costs
may be incurred in the Merger and the integration of the two companies’ businesses. Although we expect that the elimination of duplicative
costs, as well as the realization of other efficiencies related to the integration of the businesses, should allow Denbury and the Company to
offset integration-related costs over time, this net benefit may not be achieved in the near term, or at all. The costs described above, as well as
other unanticipated costs and expenses, could have a material adverse effect on the financial condition and operating results of Denbury
following the completion of the Merger. Many of these costs will be borne by us even if the Merger is not completed.
Completion of the Merger may trigger change in control or other provisions in certain agreements to which we are a party.
The completion of the Merger may trigger change in control or other provisions in certain agreements to which we are a party. If we are
unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially
terminating the agreements or seeking monetary damages. Even if we are able to negotiate waivers, the counterparties may require a fee for
such waivers or seek to renegotiate the agreements on terms less favorable to us.
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The Merger Agreement limits our ability to pursue alternatives to the Merger.
The Merger Agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in
greater value to our shareholders than the Merger, or may result in a potential competing acquirer of the Company proposing to pay a lower per
share price to acquire the Company than it might otherwise have proposed to pay. These provisions include a general prohibition on us from
soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by our board, entering into discussions with any third party
regarding any competing proposal or offer for a competing transaction. Even upon termination of the Merger Agreement under certain
circumstances relating to the exercise of fiduciary duties by our board, we may be required to pay Denbury fees and expenses, which may
further deter counterparties to any potential alternative transaction.
Failure to complete the Merger could negatively impact the price of shares of our common stock, as well as our future businesses and
financial results.
The Merger Agreement contains a number of conditions that must be satisfied or waived prior to the completion of the Merger. There can
be no assurance that all of the conditions to the completion of the Merger will be so satisfied or waived. If these conditions are not satisfied or
waived, we will be unable to complete the Merger. If the Merger is not completed for any reason, including the failure to receive the required
approval of our shareholders or Denbury’s stockholders, our businesses and financial results may be adversely affected, including as follows:
• we may experience negative reactions from the financial markets, including negative impacts on the market price of our common
•
stock;
the manner in which customers, vendors, business partners and other third parties perceive the Company may be negatively
impacted, which in turn could affect our marketing operations or our ability to compete for new business or obtain renewals in the
marketplace more broadly;
• we may experience negative reactions from employees;
and
• we will have expended time and resources that could otherwise have been spent on our existing businesses and the pursuit of other
opportunities that could have been beneficial to the Company, and our ongoing business and financial results may be adversely
affected.
In addition to the above risks, if the Merger Agreement is terminated and our board seeks an alternative transaction, our shareholders
cannot be certain that we will be able to find a party willing to engage in a transaction on more attractive terms than the Merger. If the Merger
Agreement is terminated under specified circumstances, we may be required to pay Denbury a $45 million termination fee.
We will be subject to business uncertainties while the Merger is pending, which could adversely affect our businesses.
Uncertainty about the effect of the Merger on employees and customers may have an adverse effect on the Company. These uncertainties
may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter and could
cause customers and others that deal with us to seek to change their existing business relationships with us. Employee retention at the Company
may be particularly challenging during the pendency of the Merger, as employees may experience uncertainty about their roles. In addition, the
Merger Agreement restricts us from entering into certain corporate transactions, entering into material contracts, changing our capital budget,
incurring certain indebtedness and taking other specified actions without the consent of Denbury, and generally requires us to continue our
operations in the ordinary course of business, until completion of the Merger. These restrictions may prevent us from pursuing attractive
business opportunities or adjusting our capital plan prior to the completion of the Merger.
We may be a target of securities class action and derivative lawsuits that could result in substantial costs and may delay or prevent the
Merger from being completed.
Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger
agreements. For example, on February 25, 2019, a shareholder of the Company filed a lawsuit against us, the members of our board, Denbury
and the other entities involved in the Merger in the U.S. District Court for the Southern District of Texas, Houston Division. The plaintiff
alleges that the registration statement filed by the defendants omitted material information with respect to the Merger, which renders such
registration statement false and misleading, and is seeking, among other things, injunctive relief to prohibit the completion of the Merger and
monetary damages in the form of plaintiff's costs to bring the lawsuit. Even if the lawsuits are without merit, such as the recently filed lawsuit
described in the preceding sentence, defending against these claims can result in substantial costs and divert management time and resources. An
adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Additionally,
if a plaintiff is successful in obtaining an injunction prohibiting completion of the Merger, then that injunction may delay or prevent the Merger
from being completed, which may adversely affect our and Denbury’s business, financial position and results of operation.
14
Uncertainties associated with the Merger may cause a loss of management personnel and other key employees, which could adversely affect
the future business and operations of the combined company.
We and Denbury are dependent on the experience and industry knowledge of our officers and other key employees to execute our
business plans. Each company’s success until the Merger and the combined company’s success after the Merger will depend in part upon the
ability of us and Denbury to retain key management personnel and other key employees. Current and prospective employees of Denbury and the
Company may experience uncertainty about their roles within the combined company following the Merger, which may have an adverse effect
on the ability of each of us and Denbury to attract or retain key management and other key personnel. Accordingly, no assurance can be given
that the combined company will be able to attract or retain key management personnel and other key employees of Denbury and the Company to
the same extent that we and Denbury have previously been able to attract or retain their own employees.
Risk Factors Associated with our General Business
Prices for crude oil, NGLs and natural gas are dependent on many factors that are beyond our control.
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 agree upon
and maintain production constraints and oil price controls;
• overall domestic and foreign economic
conditions;
• prices and availability of, and demand for, alternative
•
•
fuels;
the effect of energy conservation
efforts;
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 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;
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;
and
• domestic and foreign governmental relations, regulation and taxation, including limits on the United States’ ability to export crude
oil.
Oil and natural gas prices continued to be volatile in 2018. For example, the NYMEX oil prices in 2018 ranged from a high of $60.42 to a
low of $42.53 per Bbl and the NYMEX natural gas prices in 2018 ranged from a high of $3.72 to a low of $2.56 per MMBtu. Further, the
NYMEX oil prices and NYMEX natural gas prices reached highs of approximately $57 per Bbl and $3.60 per MMBtu, respectively, during the
period from January 1, 2019, to February 22, 2019. 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. Any substantial or extended decline 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, 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.
15
Exploration and development drilling 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;
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.
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.
16
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.
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.
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.
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.
17
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 personnel is critical to the success of our business and may be challenging.
The success of our business depends on 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. 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.
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
2018, approximately 69 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 continue 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.
18
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. 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.
At December 31, 2018, approximately 62 percent of our estimated proved reserves were proved undeveloped, compared to 56 percent at
December 31, 2017. Estimation of proved undeveloped reserves and proved developed non-producing 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, 2018, includes estimates of total future development costs over the next five years associated
with our proved undeveloped reserves of approximately $1,175 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, 2018, we wrote-off 21.1 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 for us. 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 $1,325.7 million and $1,444.4 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.
19
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 discounted future net
revenues from proved properties adjusted for costs excluded from amortization and related income taxes, or a Ceiling Test. The estimated
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 the past several years, we have been required to write
down the value of certain of our oil and gas properties and related assets. We could experience additional write-downs in the future.
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 $533 million in acquisition, exploration and development costs
during the year ended December 31, 2018. 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 facility. 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 and (viii) our proved reserves.
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 facility 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 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, its success will depend on a number of factors, many of which are beyond our control. These factors include the purchase price,
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.
20
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, 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.
21
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 $521 million of outstanding debt at December 31, 2018, including $321 million under the Credit Agreement as amended, or the
Credit Facility, and $200 million, excluding unamortized discount and issuance costs, under the $200 million Second Lien Credit Agreement, or
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) limiting our ability to engage in strategic transactions or obtain additional financing for working capital, capital expenditures,
general corporate and other purposes and (v) 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.
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 $450 million as of December 31, 2018. Our borrowing base is redetermined at least
twice each year and is scheduled to next be redetermined in April 2019. If crude oil, NGL or natural gas prices decline, the borrowing base
under the Credit Facility may be reduced. 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, each of which 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.
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.
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.”
22
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.
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.
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.
23
Climate change legislation, laws and regulations restricting emissions of greenhouse gases 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.
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 to reduce emissions of GHGs 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. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil
and gas we produce. 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
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 - Environmental Regulation - Climate Change.”
There have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign
wealth, pension and endowment funds 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. 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.
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 are considering or have implemented more stringent regulatory
requirements applicable to hydraulic
24
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.
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 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.
Derivative transactions may limit our potential gains and involve other risks.
In order to achieve more predictable cash flows and manage our exposure to 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
25
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 expect to 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
commercial 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 do not qualify for an exemption and are 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.
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.
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 11 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, 2018, 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.
26
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.
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.
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.
27
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.
We emerged from bankruptcy in September 2016, which could adversely affect our business and relationships.
It is possible that our having filed for bankruptcy and our emergence could adversely affect our business and relationships with
customers, employees and suppliers. Due to uncertainties, many risks exist, including the following:
• key suppliers could terminate their relationship or require financial assurances or enhanced
performance;
• our ability to renew existing contracts and compete for new business may be adversely
affected;
• our ability to attract, motivate and/or retain key executives and employees may be adversely
affected;
• employees may be distracted from performance of their duties or more easily attracted to other employment
opportunities;
• our ability to obtain credit and raise capital on terms acceptable to us or at all;
and
• our ability to attract and retain customers may be negatively
impacted.
The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and
reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the
implementation of the plan of reorganization and the transactions contemplated thereby and our adoption of fresh start accounting and the
full cost method of accounting for oil and gas properties.
Upon our emergence from bankruptcy, we adopted Fresh Start Accounting and the full cost method of accounting for oil and gas
properties. Accordingly, our financial condition and results of operations after September 2016 may not be comparable to the financial condition
or results of operations reflected in the Predecessor’s historical financial statements. The lack of comparable historical financial information
may discourage investors from purchasing our common stock. The adoption of Fresh Start Accounting established a new basis for our assets and
liabilities on the Emergence Date. The adoption of the full cost method of accounting for oil and gas properties, as compared to the successful
efforts method utilized by the Predecessor, results in the capitalization of additional costs as well as different methodologies to determine
depletive write-offs and impairments. For a more detailed discussion of Fresh Start Accounting and the full cost method of accounting for oil
and gas properties, see the discussion of “Critical Accounting Estimates” included in Part II, Item 7, “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” as well as Notes 3, 4 and 8 to the Consolidated Financial Statements included in Part II, Item 8,
“Financial Statements and Supplementary Data.”
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.
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, the lack of comparable historical financial information due to our adoption of Fresh
Start Accounting and the full cost method of accounting for oil and gas properties, 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. The
pending
28
Merger may also cause volatility in the trading of our common stock. 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.
Because we have no plans to pay dividends on or repurchase our common stock, investors must look solely to stock appreciation for a return
on their investment in us.
We do not anticipate paying any cash dividends on or repurchasing our common stock in the foreseeable future. We currently intend to
retain all future earnings to fund the development and growth of our business. Any payment of future dividends or repurchase of our common
stock will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital
requirements, level of indebtedness, statutory and contractual restrictions and other considerations that our board of directors deems relevant.
Covenants contained in the Credit Facility and the Second Lien Facility restrict the payment of dividends and share repurchases. Investors must
rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.
Investors seeking cash dividends should not purchase our common stock.
Item 1B
Unresolved Staff
Comments
None.
Item 2
Properties
As of December 31, 2018, 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.
29
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:
2018
Developed
Producing
Non-producing
Undeveloped
Crude Oil
(MMBbl)
NGLs
(MMBbl)
Natural
Gas
(Bcf)
Oil
Equivalents
(MMBOE)
Standardized
Measure
$ in millions
PV10 1
$ in millions
35.2
—
35.2
54.5
89.7
6.3
—
6.3
11.7
18.0
31.8
—
31.8
59.7
91.5
46.8
—
46.8
76.2
123.0 $
1,623.9 $
1,769.4
Price measurement used
$65.56/Bbl
$23.60/Bbl
$3.10/MMBtu
2017
Developed
Producing
Non-producing
Undeveloped
22.4
—
22.4
33.4
55.8
4.9
—
4.9
4.0
8.9
27.2
—
27.2
20.1
47.3
Price measurement used
$51.34/Bbl
$18.48/Bbl
$2.98/MMBtu
2016
Developed
Producing
Non-producing
Undeveloped
17.5
0.2
17.7
18.9
36.6
4.3
0.1
4.4
2.4
6.8
24.8
0.1
24.9
11.8
36.7
31.8
—
31.8
40.8
72.6 $
25.9
0.3
26.2
23.3
49.5 $
590.5 $
609.0
317.5 $
317.5
Price measurement used
$42.75/Bbl
$12.33/Bbl
$2.48/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. Our Standardized Measures for 2016 did not include any income tax effect. Accordingly, our PV10 and Standardized Measure
values were equivalent as of that date. 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.
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.”
30
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, 2018:
Proved undeveloped reserves at beginning of year
Revisions of previous estimates
Extensions and discoveries
Purchase of reserves
Conversion to proved developed reserves
Proved undeveloped reserves at end of year
Crude Oil
(MMBbl)
NGLs
(MMBbl)
Natural Gas
(Bcf)
Oil Equivalents
(MMBOE)
33.4
(13.9 )
42.0
3.7
(10.7 )
54.5
4.0
(1.4)
10.4
0.2
(1.4)
11.8
20.1
(7.2)
52.7
1.2
(7.1)
59.7
40.8
(16.5 )
61.1
4.1
(13.3 )
76.2
In 2018, our proved undeveloped reserves increased by 35.4 MMBOE. The overall increase over our proved undeveloped reserves at the
end of 2017 is due primarily to a significant shift in our development plans from the northwest portion of our acreage position in the Eagle Ford
to the southeast region. The performance of our wells drilled in the southeast region in the first half of the year was the impetus to our
redirecting of resources and replication, to the extent practical, of our drilling and completion design techniques for the second half of 2018. Of
the 53 gross wells we drilled in 2018, 19 gross wells were not proved undeveloped locations at the end of 2017. Accordingly, our five-year
drilling plan is currently heavily weighted to the southeast region.
The shift in focus is reflected in the changes as follows: we experienced net negative revisions of 16.5 MMBOE including: (i) 21.1
MMBOE due to the loss of certain locations resulting from changes in the drilling locations and timing attributable to our development plans as
discussed above partially offset by (ii) 4.1 MMBOE due to improved treatable lateral lengths in certain locations due primarily to
reconfiguration of the planned drilling units and (iii) 0.5 MMBOE of other changes, primarily price-related. Extensions and discoveries of 61.1
MMBOE are substantially attributable to geographical shift in our development plan, greater utilization of extended reach laterals, increasing
the length of such laterals, higher EUR estimates per lateral foot and higher net revenue interests due to the Hunt Acquisition. We acquired 4.1
MMBOE in connection with the Hunt Acquisition. In addition, we converted 13.3 MMBOE from proved undeveloped to proved developed
reserves in the Eagle Ford. During 2018, we incurred capital expenditures of $204.2 million attributable to 34 gross (28.7 net) wells in
connection with the conversion of proved undeveloped reserves to proved developed reserves. While our conversion rate for proved
undeveloped reserves improved to 33 percent in 2018 from 21 percent in 2017, it was nonetheless impacted by the aforementioned shift in the
focus of the development plan during 2018.
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 28, 2019, 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, 2018 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 Vice President, Engineering is primarily responsible for
overseeing the preparation of the reserve estimate by DeGolyer and MacNaughton, Inc. Our Vice President, Engineering has over 30 years of
industry experience in the estimation and evaluation of reserve information, holds a B.S. degree in Petroleum Engineering from Texas A&M
University and is licensed by the State of Texas as a Professional Engineer. Our internal controls over reserve estimates include reconciliation
and review controls, including an independent internal review of assumptions used in the estimation.
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.”
31
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
In the tables that follow, we have presented our former operations in the Mid-Continent, which were sold in 2018, as “Divested
properties.” The sale of those operations represented a complete divestiture and we have retained no interests therein. The production associated
with our former Marcellus Shale properties through August 2016 is also included within “Divested properties.” Our remaining operations are
exclusively represented in the Eagle Ford in South Texas.
Oil and Gas Production by Region
The following tables set forth by region our total production and average daily production for the periods presented:
Year Ended December 31,
Region
2018
South Texas
Divested properties 1
2017
(MBOE)
3,487
292
3,779
7,780
165
7,944
Total Production
Successor
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12
2016
(MBOE)
937
103
1,039
3,071
276
3,346
Year Ended December 31,
Region
2018
South Texas
Divested properties 1
2017
(BOEPD)
9,553
800
10,353
21,314
451
21,765
Average Daily Production
Successor
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12
2016
(BOEPD)
8,515
934
9,449
11,995
1,076
13,071
_____________________________________________
1 Represents total production and average daily production of our former Mid-Continent operations for all periods presented and approximately 10 MBOE (48 BOEPD) for
2016 attributable to our then active Marcellus Shale wells.
32
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 production for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12
2016
66.23 $
20.99 $
3.08 $
55.33 $
4.52 $
2.34
6.86 $
50.96 $
19.25 $
2.89 $
42.20 $
5.76 $
2.84
8.60 $
46.68 $
16.56 $
2.81 $
37.19 $
5.13 $
2.93
8.06 $
35.21
11.37
2.06
27.99
4.67
3.96
8.63
Average prices:
Crude oil ($ per Bbl)
NGLs ($ per Bbl)
Natural gas ($ per Mcf)
Aggregate ($ per BOE)
Average production and lifting cost ($
per BOE):
Lease operating
Gathering processing and
transportation
$
$
$
$
$
$
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, 2018.
The following table sets forth certain information with respect to this field for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12
2016
Production:
Crude oil (MBbl)
NGLs (MBbl)
Natural gas (MMcf)
Total (MBOE)
Percent of total company production
Average prices:
Crude oil ($ per Bbl)
NGLs ($ per Bbl)
Natural gas ($ per Mcf)
Aggregate ($ per BOE)
Average production and lifting cost ($
per BOE):
Lease operating
Gathering processing and
transportation
$
$
$
$
$
$
6,050
944
4,713
7,780
2,716
418
2,120
3,487
695
130
674
937
98%
92%
90 %
66.24
21.10
3.16
55.99
$
$
$
$
4.47
$
2.27
6.74
$
51.08
18.13
2.95
43.74
$
$
$
$
5.79
$
2.49
8.28
$
33
46.73
14.82
2.79
38.71
$
$
$
$
5.39
$
2.58
7.97
$
2,265
449
2,141
3,071
92 %
35.24
10.34
2.05
28.94
4.58
3.50
8.08
Drilling and Other Exploratory and Development Activities
The following table sets forth the gross and net development wells that we drilled, all of which were in the Eagle Ford in South Texas,
during the years ended December 31, 2018, 2017 and 2016, respectively, and wells that were in progress at the end of each year. There were no
exploratory wells drilled in any of the years presented. The number of wells drilled refers to the number of wells completed at any time during
the year, regardless of when drilling was initiated.
Development
Productive
Dry well 1
Total
2018
2017
2016
Gross
Net
Gross
Net
Gross
Net
53
—
53
45.5
—
45.5
29
1
30
16.9
0.7
17.6
5
—
5
Wells in progress at end of year 2
_____________________________________________
1 Represents the Zebra Hunter 05H well in the northern portion of our Eagle Ford acreage.
2 Includes two gross (2.0 net) wells completing, four gross (3.8 net) wells waiting on completion and five gross (4.4 net) wells being drilled as of December 31, 2018.
Present Activities
10.2
8.2
11
11
5
2.9
—
2.9
2.6
As of December 31, 2018, we had 11 gross (10.2 net) wells in progress. As of February 22, 2019, four gross (4.0 net) wells were
completing and six gross (5.4 net) wells were in process of being drilled by three operated rigs.
Delivery Commitments
We generally sell our 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) in our South Texas region through 2031 under gathering and
transportation agreements with Republic Midstream, LLC, or Republic Midstream. Our production and reserves are currently sufficient to fulfill
the current 8,000 BOPD delivery commitment under these agreements. In 2016, following the suspension of our drilling program, we incurred
charges for deficiencies of $0.4 million as a result of our inability to satisfy the 15,000 BOPD delivery commitment under such agreements prior
to their August 2016 amendments in connection with our emergence from bankruptcy.
Productive Wells
The following table sets forth our productive wells in which we had a working interest as of December 31, 2018:
Primarily Oil
Primarily Natural Gas
Total
Gross
Net
Gross
Net
Gross
Net
Total productive wells
458
375.5
2
2.0
460
377.5
Of the total wells presented in the table above, we are the operator of 448 gross (446 oil and two natural gas) and 375.6 net (373.6 oil and
2.0 natural gas) wells. In addition to the above working interest wells, we own overriding royalty interests in 13 gross wells.
Acreage
The following table sets forth our developed and undeveloped acreage as of December 31, 2018 (in thousands):
Developed
Undeveloped
Total
Gross
Net
Gross
Net
Gross
Net
Total
acreage
89.9
76.9
8.3
7.3
98.2
84.2
The primary terms of our leases generally range from three to five years and we do not have any concessions. As of December 31, 2018,
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:
Expirations by year
2019
2020
2021
Thereafter
0.7
5.5
0.9
0.2
We anticipate paying options to extend a substantial portion of the acreage scheduled to expire in 2019. 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.
34
Item 3
Legal
Proceedings
On May 12, 2016, or the Petition Date, we and the Chapter 11 Subsidiaries filed voluntary petitions ( In re Penn Virginia Corporation, et
al., Case No. 16-32395) seeking relief under the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia.
On August 11, 2016, the Bankruptcy Court confirmed the Plan, and we subsequently emerged from bankruptcy on September 12, 2016.
On November 20, 2018, the Bankruptcy Court issued a final decree to close the case. See Note 4 to our Consolidated Financial Statements
included in Part II, Item 8, “Financial Statements and Supplementary Data,” for a more detailed discussion of our bankruptcy proceedings and
emergence.
See Note 15 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.
35
Item 5
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Part II
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 19, 2019, there were 91 record holders of our common stock.
Dividends
We have not paid nor do we intend in the foreseeable future to pay any cash dividends on our common stock. Furthermore, we are
restricted from paying 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 17
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 2018.
36
Performance Graph
The following graph compares our cumulative total shareholder return with the cumulative total return of the Standard & Poor’s 600 Oil
& Gas Exploration and Production Index and the Standard & Poor’s SmallCap 600 Index for the period from November 15, 2016 (the date that
our common shares became publicly tradeable) through December 31, 2018. As of December 31, 2018, there were nine exploration and
production companies in the Standard & Poor’s 600 Oil & Gas Exploration and Production Index: Bonanza Creek Energy Inc., Carrizo Oil &
Gas, Inc., Denbury Resources Inc., Gulfport Energy Corporation, Highpoint Resources Corporation, Laredo Petroleum Inc., PDC Energy Inc.,
Ring Energy Inc. and SRC Energy Inc. The graph assumes $100 is invested on November 15, 2016 in us and each index at November 15, 2016
closing prices.
The following table represents the actual data points for the dates indicated on the graph above:
Penn Virginia Corporation
S&P SmallCap 600 Index
S&P 600 Oil & Gas Exploration & Production Index
November 15,
2016
$
$
$
100.00 $
100.00 $
100.00 $
2016
120.62 $
116.34 $
115.64 $
December 31,
2017
96.27 $
131.74 $
81.84 $
2018
133.05
120.56
45.36
37
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, production and reserves)
Successor
Predecessor
Year Ended
December 31,
September 13
Through
January 1
Through
December 31,
September 12,
Year Ended
December 31,
2018
2017
2016
2016
2015
2014
440,832 $
208,755 $
224,785 $
— $
224,785 $
14.93 $
14.70 $
15,059
15,292
— $
272,132 $
430,592 $
160,054 $
51,872 $
32,662 $
— $
32,662 $
2.18 $
2.17 $
14,996
15,063
— $
81,710 $
115,687 $
39,003 $
11,413 $
(5,296) $
— $
(5,296) $
(0.35 ) $
(0.35 ) $
14,992
14,992
— $
30,774 $
4,812 $
94,310 $
305,298 $
(20,867 ) $ (1,564,976 ) $
1,054,602 $ (1,582,961 ) $
22,789 $
5,972 $
636,773
(615,920)
(409,592)
17,148
1,048,630 $ (1,605,750 ) $
(21.81) $
(21.81) $
11.91 $
8.50 $
(430,996)
(6.26 )
(6.26 )
88,013
124,087
— $
30,247 $
15,359 $
73,639
73,639
— $
169,303 $
364,844 $
68,887
68,887
—
282,724
774,139
7,944
3,779
1,039
3,346
7,923
7,934
December 31,
September 12,
December 31,
2018
927,994 $
1,068,954 $
511,375 $
447,355 $
2017
529,059 $
629,597 $
265,267 $
221,639 $
2016
247,473 $
291,686 $
25,000 $
185,548 $
2016
2014
253,510 $
333,974 $
2015
344,395 $ 1,825,098
517,725 $ 2,201,810
75,350 $ 1,224,383 $ 1,085,429
(915,121) $
675,817
190,895 $
15,081
15,019
14,992
14,992
81,253
71,569
123
73
49
N/A
44
115
Statements of Operations and Other Data:
Revenues
Operating income (loss)1, 2
Net income (loss) 3
Preferred stock dividends 4
Income (loss) attributable to common
shareholders
Income (loss) per common share, basic
Income (loss) per common share, diluted
Weighted-average shares outstanding:
Basic
Diluted
Dividends declared per share
Cash provided by operating activities
Cash paid for capital expenditures
Total production (MBOE)
Balance Sheet and Other Data:
Property and equipment, net
Total assets
Total debt
Shareholders’ equity (deficit)
Actual shares outstanding at period-end
Proved reserves as of December 31,
(MMBOE)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
_____________________________________________
1 Operating loss for 2015 and 2014 included impairment charges of $1.4 billion and $791.8 million, respectively.
2 Operating income (loss) for all periods prior to 2018 reflects the retrospective application of Accounting Standards Update 2017–07,
Improving the Presentation of Net
Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU 2017-07. See “ Overview and Executive Summary ” included in Part II, Item 7,
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2 to our Consolidated Financial Statements included in Part II, Item
8, “Financial Statements and Supplementary Data.”
3 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 attributable to our bankruptcy proceedings of $3.3 million and $1.1 billion, respectively.
4 Excludes inducements paid for the conversion of preferred stock of $4.3 million in 2014.
38
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item
7
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.
Overview and Executive Summary
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 primarily of drilling unconventional horizontal development wells and operating our producing wells
in the Eagle Ford, in Gonzales, Lavaca, Fayette and DeWitt Counties in South Texas.
Presentation of Financial Information and Changes in Accounting Principles
Emergence from Bankruptcy
As discussed in further detail in Note 4 to our Consolidated Financial Statements, we have adopted and applied Fresh Start Accounting as
a result of our emergence from bankruptcy in 2016. Accordingly, our Consolidated Financial Statements and Notes after September 12, 2016 are
not comparable to the Consolidated Financial Statements and Notes prior to that date. To facilitate the discussion and analysis of our financial
condition and results of operations herein, we refer to the reorganized company as the “Successor” for periods subsequent to September 12,
2016, and the “Predecessor” for periods prior to September 13, 2016. Furthermore, our presentations herein include a “black line” division to
delineate the lack of comparability between the Predecessor and Successor. In order to enhance our discussion herein, we have addressed the
Successor and Predecessor periods discretely and have provided comparative analysis, to the extent practical, where appropriate. In addition, and
as referenced in Note 2 to the Consolidated Financial Statements, we have adopted the full cost method of accounting for our oil and gas
properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations and financial position for the Successor
periods will be substantially different from our historic trends.
Adoption of New Accounting Standards
As discussed in further detail in Notes 2 and 6 to the Consolidated Financial Statements, we have adopted two new accounting standards:
Accounting Standards Codification Topic 606, Revenues from Contracts with Customers, or ASC Topic 606, and ASU 2017–07, effective
January 1, 2018. The adoption of these standards impacts the presentation and comparability of (i) NGL product revenues and Gathering,
processing and transportation, or GPT, expense; and (ii) General and administrative, or G&A, expenses and Other income (expense), net. We
adopted ASC Topic 606 utilizing the cumulative effect transition method. Accordingly, our NGL revenues and GPT expense for the year ended
December 31, 2017 are not comparable to the 2018 presentation of these items. Our discussion and analysis of these items in the Results of
Operations that follow address the effects of changes directly attributable to the adoption of ASC Topic 606. We adopted ASU 2017–07
utilizing the modified retrospective method. Accordingly, certain retiree benefits costs that were previously reported as a component of G&A
are being reported as a component of Other, net (expenses), as required by ASU 2017–07, for all periods presented.
Industry Environment and Recent Operating and Financial Highlights
Crude oil prices continued rising in the second half of 2017 throughout the first half of 2018 and then declined precipitously in the fall of
2018. Global economic conditions as well as domestic supply are anticipated to maintain downward pressure on crude oil prices for the near
term. Despite these challenges, we continue to benefit from the proximity of our operating region to the Gulf Coast markets whereby we sell
substantially all of our crude oil production based on the Light Louisiana Sweet, or LLS, price index. The LLS index has exceeded that of the
West Texas Intermediate, or WTI, price index, providing us with a strong revenue stream compared to certain of our domestic peers and
competitors located at a greater distance from the Gulf Coast markets. Subsequent to 2016, domestic production has increased, including that in
the broader Eagle Ford region in which we operate. This environment has expanded opportunities in our principal operating region. In addition,
there has been a consolidation of holdings within the Eagle Ford, including our own, through recent acquisitions. Collectively, these and other
factors have led, at times, to higher pricing for certain oilfield products and services, including drilling services. At this time we do not
anticipate any significant declines in such costs for 2019.
39
The following summarizes certain key operating and financial highlights for the three months ended December 31, 2018 with comparison
to the three months ended September 30, 2018 as presented in the table that follows. The year-over-year highlights for 2018 and 2017 are
addressed in further detail in the discussions for Financial Condition and Results of Operations that follow.
•
•
•
•
•
•
•
Production increased approximately 12 percent to 2,363 MBOE, from 2,108 MBOE due primarily to incremental production from the
10 gross (8.9 net) wells turned to sales during the quarter, the majority of which were turned to sales in the first month of the quarter.
Product revenues decreased approximately two percent to $124.6 million from $126.8 million due primarily to approximately $18.0
million of which relates to 14 percent and three percent lower crude oil and NGL pricing, partially offset by $14.7 million due to the
effect of higher overall production volume, and $1.1 million from 26 percent higher natural gas pricing.
Production and lifting costs, which include LOE and GPT, increased on an absolute basis to $15.7 million from $14.8 million, but
decreased on a per unit basis to $6.65 per BOE, from $7.04 per BOE due primarily to lower surface maintenance costs as well as the
effect of the increase in production volume.
Production and ad valorem taxes decreased on an absolute and per unit basis to $6.5 million and $2.75 per BOE from $7.2 million and
$3.39 per BOE, respectively, due primarily to lower crude oil and NGL pricing partially offset by the effect of higher production
volume.
General and administrative expenses increased on an absolute and per unit basis to $8.1 million and $3.43 per BOE from $6.2 million
and $2.92 per BOE, respectively, due primarily to transaction costs associated with the Merger partially offset by the effect of higher
production volume.
Our DD&A increased to $39.6 million, or $16.75 per BOE from $35.0 million, or $16.61 per BOE due primarily to $4.2 million from
the effect of higher production volume, as well as $0.4 million attributable to the effect of higher rates, resulting from higher
capitalized costs for oil and gas properties.
Our operating income declined to $54.9 million from $64.0 million due to the combined impact of the matters noted in the bullets
above.
40
The following table sets forth certain historical summary operating and financial statistics for the periods presented:
(in thousands except per unit measurements, production, wells and reserves)
Three Months Ended
Successor
September 13
Through
Predecessor
January 1
Through
December 31,
September 30,
Year Ended December 31,
December 31,
September 12,
2018
2018
2018
2017
2016
2016
Total production (MBOE)
Average daily production (BOEPD)
Crude oil production (MBbl)
Crude oil production as a percent of total
Product revenues
Crude oil revenues
Crude oil revenues as a percent of total
Realized prices:
Crude oil ($ per Bbl)
NGL ($ per Bbl) 1
Natural gas ($ per Mcf)
Aggregate ($ per BOE)
Prices, adjusted for derivatives::
Crude oil ($ per Bbl)
Aggregate ($ per BOE)
Production and lifting costs ($ per BOE):
Lease operating
Gathering, processing and transportation 1
Production and ad valorem taxes ($ per BOE)
General and administrative ($ per BOE) 2
Depreciation, depletion and amortization ($
per BOE) 3
Capital expenditure program costs 4
Cash provided by operating activities 5
Cash paid for capital expenditures 6
Cash and cash equivalents at end of period
Debt outstanding, net of discount and issue
costs, at end of period
Credit available under credit facility at end of
period
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2,363
25,686
1,818
77 %
124,572
112,452
$
$
90 %
2,108
22,912
1,633
77 %
126,803
117,059
$
$
92 %
7,944
21,765
6,077
76 %
439,530
402,485
$
$
92 %
3,779
10,353
2,764
73 %
159,469
140,886
$
$
88 %
61.84
21.79
3.80
52.72
54.64
47.17
4.21
2.44
2.75
3.43
16.75
105,099
79,227
107,333
17,864
511,375
128,600
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
71.67
22.41
3.02
60.16
62.36
52.94
4.70
2.34
3.39
2.92
16.61
104,589
72,487
121,909
8,011
472,344
57,100
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
66.23
20.99
3.08
55.33
58.28
49.25
4.52
2.34
2.96
3.28
16.11
418,951
272,132
430,592
17,864
511,375
128,600
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
50.96
19.25
2.89
42.20
49.69
41.27
5.76
2.84
2.33
4.82
12.87
129,827
81,710
115,687
11,017
265,267
159,745
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,039
9,449
710
68 %
38,654
33,157
$
$
86 %
46.68
16.56
2.81
37.19
47.22
37.56
5.13
2.93
2.40
4.88
11.21
5,454
30,774
4,812
6,761
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
25,000
$
102,233
$
3,346
13,071
2,311
69 %
93,649
81,377
87 %
35.21
11.37
2.06
27.99
55.98
42.33
4.67
3.96
1.04
11.64
10.04
4,113
30,247
15,359
31,414
75,350
51,883
Net development wells drilled and completed
Proved reserves at the end of the period
(MMBOE)
_____________________________________________
1 The effects of the adoption of ASC Topic 606, if applied to the three months ended December 31, 2017 and the year ended December 31, 2017, would have resulted in
N/A
16.9
45.5
N/A
123
123
8.9
9.7
2.9
49
73
—
realized prices for NGLs of $19.27 and $16.40 per BOE and GPT of $2.43 and $2.45 per BOE, respectively.
2 Includes combined amounts of $1.56 and $0.51 per BOE for the three months ended December 31, 2018 and September 30, 2018, respectively, and
$1.11 , $1.36 and
$6.98 per BOE for the Successor periods ended December 31, 2018 and 2017 and the Predecessor period in 2016, respectively, attributable to equity- and liability-
classified share-based compensation and significant special charges, including acquisition, divestiture and strategic transaction costs and strategic and financial advisory
costs prior to our bankruptcy filing, among others costs, as described in the discussion of “Results of Operations - General and Administrative ” that follows.
3 Determined using the full cost method for the Successor periods and the successful efforts method for the Predecessor period.
4 Includes amounts accrued and excludes capitalized interest and capitalized
labor.
5 Includes net cash paid for derivative settlements of $13.1 million and $15.2 million for the three months ended December 31, 2018 and September 30, 2018, respectively,
and $48.3 million and $3.5 million for the years ended December 31, 2018 and 2017, respectively, and cash received from derivative settlements of $0.4 million and $48.0
million for the Successor and Predecessor periods ended in 2016, respectively. Reflects changes in operating assets and liabilities of $(0.7) million and $(6.1) million for
the three months ended December 31, 2018 and September 30, 2018, respectively, and $(2.8) million, $(15.0) million and $7.0 million for the Successor periods ended
December 31, 2018, 2017 and 2016 and $35.2 million for the Predecessor period in 2016, respectively.
6 Represents actual cash paid for capital expenditures including capitalized interest and capitalized labor.
41
Key Developments
The following general business developments and corporate actions had or may have a significant impact on our results of operations,
financial position and cash flows:
Merger with Denbury
On October 28, 2018, Denbury and Penn Virginia announced the Merger in which Denbury will acquire Penn Virginia. The consideration
to be paid to Penn Virginia shareholders will consist of 12.4 shares of Denbury common stock and $25.86 of cash for each share of Penn
Virginia common stock. Penn Virginia shareholders will be permitted to elect to receive either all cash, all stock or a mix of stock and cash, in
each case subject to proration, which will result in the aggregate issuance by Denbury of approximately 191.667 million Denbury shares and
payment by Denbury of $400 million in cash. The transaction was unanimously approved by the board of directors of each company, and
certain Penn Virginia shareholders holding approximately 15 percent of the outstanding shares signed voting agreements to vote “for” the
transaction. The transaction is subject to the approval by the holders of more than two-thirds of the outstanding Company common shares, the
approval by the holders of a majority of the outstanding Denbury common shares of an amendment to the certificate of incorporation to increase
the number of authorized Denbury common shares, the approval of the issuance of Denbury common shares in the Merger by the holders of a
majority of the Denbury common shares represented in person or by proxy at a meeting of Denbury shareholders held to vote on such matter
and other customary closing conditions. The special meeting of shareholders to approve the merger is anticipated in April 2019 and closing is
anticipated soon thereafter, subject to shareholder approval and certain other conditions. The Merger Agreement contains certain termination
rights for both Denbury and the Company, including if the Merger is not consummated by April 30, 2019, and requires Penn Virginia to pay a
$45 million termination fee in certain circumstances.
Production and Development Plans
Total production for the quarter and year ended December 31, 2018 was 2,363 MBOE and 7,944, or 25,686 and 21,765 BOEPD, with
approximately 77 percent and 76 percent, or 1,818 MBbls and 6,077 MBbls, of production from crude oil, 13 percent from NGLs for each
period and 10 percent and 11 percent from natural gas. Production from our Eagle Ford operations during the annual period was 7,780 MBOE or
21,314 BOEPD while all of our production was derived from this region during the fourth quarter of 2018 following the sale of our Mid-
Continent operations in July of 2018.
We drilled and turned 10 and 53 gross (8.9 and 45.5 net) Eagle Ford wells to sales during the quarter and year ended December 31, 2018,
respectively. Subsequent to December 31, 2018, we drilled and turned an additional four gross (2.9 net) wells to sales. As of February 22, 2019,
we were in the process of drilling six gross (5.4 net) wells with our three operated drilling rigs and four gross (4.0 net) wells were completing.
As of December 31, 2018, we had approximately 98,200 gross (84,200 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.
Amendment to Credit Facility
In October 2018, we entered into the Borrowing Base Agreement and Amendment No. 5 to the Credit Facility, or the Fifth Amendment,
to our credit agreement, or Credit Facility, increasing the borrowing base from $340.0 million to $450.0 million, among other things.
Acquisition of Producing Properties
In December 2017, we entered into a purchase and sale agreement with Hunt, to acquire certain oil and gas assets in the Eagle Ford Shale,
primarily in Gonzales and Lavaca Counties, Texas for $86.0 million in cash, subject to adjustments, or the Hunt Acquisition. The Hunt
Acquisition had an effective date of October 1, 2017, and closed on March 1, 2018, at which time we paid cash consideration of $84.4 million.
We received $1.4 million from Hunt, primarily attributable to suspended revenues, in a final settlement that occurred in July 2018. In
connection with the Hunt Acquisition, we also acquired working interests in certain wells that we previously drilled as operator, and in which
Hunt had rights to participate prior to the transaction closing. Accumulated costs, net of suspended revenues for these wells was $13.8 million,
which we have reflected as a component of the total net assets acquired. The Hunt Acquisition expanded our net leasehold position by
approximately 9,700 net acres, substantially all of which is held by production, in the northwestern portion of our Eagle Ford acreage.
42
Commodity Hedging Program
As of February 22, 2019, we have hedged a portion of our estimated future crude oil production through the end of 2020 with a mix of
WTI- and LLS- indexed swaps. We are currently unhedged with respect to NGL and natural gas production. The following table summarizes
our hedge positions for the periods presented:
Remainder of 2019
2020
Divestiture of Mid-Continent Properties
WTI Volumes
(Barrels per day)
WTI Average Swap Price
($ per barrel)
LLS Volumes
(Barrels per day)
LLS Average Swap Price
($ per barrel)
6,407 $
6,000 $
54.49
54.09
5,000 $
—
59.17
—
In June 2018, we entered into a purchase and sale agreement with a third party to sell all of our remaining Mid-Continent oil and gas
properties, located primarily in Oklahoma in the Granite Wash, for $6 million in cash, subject to customary adjustments. The sale had an
effective date of March 1, 2018, and closed on July 31, 2018, and we received proceeds of $6.2 million. In November 2018, we paid $0.5
million, including $0.2 million of suspended revenues, to the buyer in connection with the final settlement.
43
Financial Condition
Liquidity
Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility.
The Credit Facility provides us with up to $450 million in borrowing commitments. The current borrowing base under the Credit Facility is also
$450 million. As of February 22, 2019, we had $136.6 million of availability under the Credit Facility.
Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for crude oil, NGL and
natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our
control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other
supply chain dynamics, among other factors. The level of our hedging activity and duration of the financial instruments employed depend on
our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy. In order to mitigate
this volatility, we entered into derivative contracts hedging a portion of our estimated future crude oil production through the end of 2020.
Capital Resources
We plan to fund our 2019 capital spending primarily with cash from operating activities and, to the extent necessary, borrowings under the
Credit Facility. Based upon current price and production expectations for 2019, we believe that our cash from operating activities and
borrowings under our Credit Facility will be sufficient to fund our operations through year-end 2019; however, future cash flows are subject to a
number of variables and significant additional capital expenditures may be required to more fully develop our properties. For a detailed analysis
of our historical capital expenditures, see the “Cash Flows” discussion that follows.
Cash on Hand and Cash From Operating Activities. As of February 22, 2019, we had approximately $14 million of cash on hand. For
additional information and an analysis of our historical cash flows from operating activities, see the “Cash Flows” discussion that follows.
Credit Facility Borrowings. During 2018, we borrowed $244 million, under the Credit Facility. For additional information regarding the
terms and covenants under the Credit Facility, see the “Capitalization” discussion that follows.
The following table summarizes our borrowing activity under the Credit Facility for the periods presented:
Borrowings Outstanding
Three months ended December 31, 2018
Year ended December 31, 2018
Weighted-
Average Rate
6.25%
5.76%
Proceeds from Sales of Assets. We continually evaluate potential sales of non-core assets, including certain oil and gas properties and
non-strategic undeveloped acreage, among others. For additional information and an analysis of our historical proceeds from sales of assets,
including the sale in 2018 of our Mid-Continent properties, see the “Cash Flows” discussion that follows.
305,217 $
230,934 $
321,000
321,000
Weighted-
Average
Maximum
$
$
Capital Market Transactions. From time-to-time and under market conditions that we believe are favorable to us, we may consider
capital market transactions, including the offering of debt and equity securities.
44
Cash Flows
The following table summarizes our cash flows for the periods presented:
Cash flows from operating activities
Operating cash flows, net of working capital changes
Crude oil derivative settlements paid, net
Interest payments, net of amounts capitalized
Acquisition, divestiture and strategic transaction costs paid
Reorganization items paid, net
Consulting costs paid to former Executive Chairman
Net cash provided by operating activities
Cash flows from investing activities
Acquisitions, net
Capital expenditures
Proceeds from sales of assets, net
Net cash used in investing activities
Cash flows from financing activities
Proceeds from credit facility borrowings, net
Proceeds from second lien facility, net
Debt issuance costs paid
Proceeds from rights offering, net
Other, net
Net cash provided by financing activities
Net increase in cash and cash equivalents
Year Ended
December 31,
2018
2017
$
346,780 $
(48,291 )
(22,599 )
(2,968)
(540)
(250)
272,132
(85,387 )
(430,592)
7,683
(508,296)
244,000
—
(989)
—
—
243,011
$
6,847 $
91,365
(3,511)
(4,102)
(1,088)
(954)
—
81,710
(200,849)
(115,687)
869
(315,667)
52,000
196,000
(9,787)
55
(55 )
238,213
4,256
Cash Flows from Operating Activities. The increase in net cash from operating activities for 2018 compared to 2017 was primarily
attributable to: (i) higher overall production volume in 2018, (ii) incremental net operating cash inflows from the Hunt Acquisition and the 2017
acquisition of oil and gas assets from Devon Energy Corporation, or the Devon Acquisition, (iii) higher overall product pricing in 2018 and (iv)
lower payments in 2018 for bankruptcy-related administration costs as the case was closed in November 2018. These items were partially offset
by: (i) substantially higher settlements paid for crude oil derivatives, (ii) higher interest payments due to greater outstanding borrowings in
2018, (iii) higher payments for acquisition, divestiture and strategic transaction costs in 2018 and (iv) certain costs paid in connection with the
retirement of our Executive Chairman in February 2018.
Cash Flows from Investing Activities. In 2018, we paid a combined total of $86.5 million for the Hunt Acquisition and the purchase of
other working interests in producing properties in the Eagle Ford and received a total of $1.1 million in connection with the final settlement of
the Devon Acquisition. In 2017, we paid a total of $200.8 million for the preliminary settlement of the Devon Acquisition which included $0.7
million paid to other parties that had tag-along rights to sell their interests. As illustrated in the tables below, our cash payments for capital
expenditures were higher during 2018 as compared to 2017 due primarily to an increase to a three-rig and two frac spread development program
from a two-rig and single frac spread program in 2017 as well as the effect of higher working interests from the Hunt and Devon Acquisitions.
The increased capital expenditures for 2018 and 2017 were partially offset by proceeds from asset sales during each year. We received proceeds
of $7.7 million in 2018 attributable to the sales of: (i) all of our Mid-Continent properties, (ii) undeveloped acreage holdings in the Tuscaloosa
Marine Shale in Louisiana, (iii) certain undeveloped leasehold rights in Oklahoma, (iv) certain pipeline assets in our former Marcellus Shale
operating region and (v) scrap and surplus tubular and well materials. In 2017, we received proceeds of $0.9 million from the sale of certain
inactive acreage in Oklahoma.
45
The following table sets forth costs related to our capital expenditure program for the periods presented:
Drilling and completion
Lease acquisitions and other land-related costs
Geological, geophysical (seismic) and delay rental costs
Pipeline, gathering facilities and other equipment, net
Year Ended
December 31,
2018
2017
405,677 $
5,180
377
7,717
418,951 $
125,235
4,493
696
(597)
129,827
$
$
The following table reconciles the total costs of our capital expenditure program with the net cash paid for capital expenditures as
reported in our Consolidated Statements of Cash Flows for the periods presented:
Total capital program costs (from above)
Increase in accrued capitalized costs
Less:
Transfers from tubular inventory and well materials
Sales & use tax refunds received and applied to property accounts
Add:
Tubular inventory and well materials purchased in advance of drilling
Capitalized internal labor
Capitalized interest
Total cash paid for capital expenditures
Year Ended
December 31,
2018
2017
$
418,951 $
(44 )
(10,056 )
(643)
9,578
3,688
9,118
430,592 $
$
129,827
(19,910 )
(3,326)
(2,265)
6,252
2,384
2,725
115,687
Cash Flows from Financing Activities. During 2018 we borrowed $244 million under the Credit Facility to fund the three-rig capital
program and the Hunt Acquisition, while 2017 only included borrowings of $52 million, net of repayments. In 2017, we received proceeds of
$196 million from the $200 million Second Lien Facility, or Second Lien Facility, net of OID, primarily to fund the Devon Acquisition. We
also paid approximately $1.0 million of debt issuance costs in 2018 in connection with amendments to the Credit Facility and other costs in
connection with the Second Lien Facility compared to $9.8 million paid in 2017 in connection with an amendments to the Credit Facility and
the issuance of the Second Lien Facility. The receipt in the 2017 period of delayed proceeds attributable to the rights offering in September
2016 were fully offset by costs paid in connection with the registration of our common stock in 2017.
Capitalization
The following table summarizes our total capitalization as of the dates presented:
Credit Facility borrowings
Second Lien Facility term loans, net of original issue discount and issuance costs
Total debt
Shareholders’ equity
Total capitalization
Debt as a % of total capitalization
December 31,
2018
2017
$
$
321,000
190,375
511,375
447,355
958,730
$
$
77,000
188,267
265,267
221,639
486,906
53%
54%
Credit Facility. The Credit Facility provides for a $450 million revolving commitment and borrowing base. The Credit Facility includes a
$5.0 million sublimit for the issuance of letters of credit. The availability under the Credit Facility may not exceed the lesser of the aggregate
commitments or the borrowing base. The borrowing base under the Credit Facility is redetermined semi-annually, generally in April and
October of each year. Additionally, the Credit Facility lenders may, at their discretion, initiate a redetermination at any time during the six-
month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes including working
capital. The Credit Facility matures in September
46
2020. We had $0.4 million and $0.8 million in letters of credit outstanding as of December, 2018 and December 31, 2017, respectively.
The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate
plus an applicable margin ranging from 2.00% to 3.00%, determined based on the average availability under the Credit Facility or (b) a
customary London interbank offered rate, or LIBOR, plus an applicable margin ranging from 3.00% to 4.00%, determined based on the average
availability under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year
of 365/366 days, and interest on LIBOR borrowings is payable every one, three or six months, at our election, and is computed on the basis of a
year of 360 days. As of December 31, 2018, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility
was 5.96%. Unused commitment fees are charged at a rate of 0.50%.
The Credit Facility is guaranteed by us and all of our subsidiaries, or the Guarantor Subsidiaries. The guarantees under the Credit Facility
are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. There are no
significant restrictions on our ability or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations
under the Credit Facility are secured by a first priority lien on substantially all of our assets.
Second Lien Facility. On September 29, 2017, we entered into the $200 million Second Lien Facility. The maturity date under the Second
Lien Facility is September 29, 2022.
The 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 6.00% or (b) a customary LIBOR rate plus an applicable margin of 7.00%. Amounts
under the Second Lien Facility were borrowed at a price of 98% with an initial interest rate of 8.34% resulting in an effective interest rate of
9.89%. As of December 31, 2018, the actual interest rate on the Second Lien Facility was 9.53%. Interest on reference rate borrowings is
payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on eurocurrency borrowings is payable every
one or three months (including in three month intervals if we select a six month interest period), at our election and is computed on the basis of a
year of 360 days. 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 eurocurrency loans): during year one, a customary
“make-whole” premium; during year two, 102% of the amount being prepaid; during year three, 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. During years one and two, 102% of the amount
being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium.
The Second Lien Facility is collateralized by substantially all of the Company’s and its subsidiaries’ assets with lien priority subordinated
to the liens securing the Credit Facility. The obligations under the Second Lien Facility are guaranteed by us and the Guarantor Subsidiaries.
Covenant Compliance. The Credit Facility requires us to maintain (1) a minimum interest coverage ratio (adjusted EBITDAX, as defined
in the Credit Facility, to adjusted interest expense), measured as of the last day of each fiscal quarter, of 3.00 to 1.00, (2) a minimum current
ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset), measured as of the last
day of each fiscal quarter of 1.00 to 1.00, and (3) a maximum leverage ratio (consolidated indebtedness to EBITDAX, as defined in the Credit
Facility), measured as of the last day of each fiscal quarter, of 3.50 to 1.00. The Second Lien Facility has no financial covenants.
The Credit Facility and Second Lien Facility also contain customary affirmative and negative covenants, including as to compliance with
laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual
financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties),
restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with
affiliates and other customary covenants.
The Credit Facility and Second Lien Facility contain customary events of default and remedies. If we do not comply with the financial
and other covenants in the Credit Facility and Second Lien Facility, the lenders thereto may, subject to customary cure rights, require immediate
payment of all amounts outstanding under the Credit Facility and Second Lien Facility.
As of December 31, 2018, we were in compliance with all of the covenants under the Credit Facility and the Second Lien Facility.
47
Results of Operations
The tabular presentations included below reflect the results of operations associated with the Successor periods of 2018, 2017 and 2016
(the period from September 13 through December 31, 2016) and the Predecessor period of 2016 (the period from January 1 through September
12, 2016). As discussed previously in “Overview and Executive Summary,” the adoption of Fresh Start Accounting and the full cost method of
accounting for oil and gas properties on the Emergence Date results in the Successor not being comparable to the Predecessor for purposes of
financial reporting. While the Successor effectively represents a new reporting entity for financial reporting purposes, the impact is generally
limited to those areas associated with the basis in and accounting for our oil and gas properties (specifically DD&A and exploration expenses),
capital structure (specifically interest expense) and income taxes (due to the change in control). Accordingly, we believe that describing certain
year-over-year variances and trends in our production, revenues and expenses for the calendar years 2018, 2017 and 2016 without regard to the
concept of a Successor and Predecessor facilitates a meaningful analysis of our results of operations.
A portion of the components of our year-over-year variances for 2018 to 2017 are due to the effects of the Hunt Acquisition in March
2018 and the Devon Acquisition in September 2017. Partially offsetting the impact these transactions are the effects of our property divestitures.
In the discussion and analysis that follows, the term “Divested properties” refers to the production, revenues and expenses associated with our
former assets in the Mid-Continent region that we sold in July 2018 as well as former operations in the Marcellus Shale in Pennsylvania. We
terminated operations in that region in August 2016 and completed well-plugging and remediation activities in 2017.
As discussed previously in “Overview and Executive Summary,” the adoption of ASC Topic 606 and ASU 2017–07 effective January 1,
2018 impacts the presentation and comparability of (i) NGL product revenues and GPT expense; and (ii) G&A expenses and Other income
(expense), net. Because we adopted ASC Topic 606 using the cumulative effect transition method, we are precluded from changing the
presentation of impacted items, which include NGL product revenues and GPT expenses, in prior periods. Accordingly, the presentation of
NGL product revenues and GPT expenses for 2018 are not comparable to those presented for 2017 and the Successor and Predecessor periods in
2016 (see Note 6 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”)
Conversely, the adoption of ASU 2017–07, which applies to the presentation of the components of retiree pension and postretirement benefits
costs, was applied on a retrospective basis to all prior periods. Accordingly, the presentations of our G&A expenses and Other income (expense),
net are comparable for all periods presented.
48
Production
The following tables set forth a summary of our total and average daily production volumes by product and geographic region for the
periods presented:
Crude oil (MBbl)
NGLs (MBbl)
Natural gas (MMcf)
Total (MBOE)
2018 vs 2017 Variance (MBOE)
% Change
2017 vs. Combined 2016 Variance (MBOE)
% Change
Crude oil (Bbl per day)
NGLs (Bbl per day)
Natural gas (MMcf per day)
Total (BOEPD)
2018 vs 2017 Variance (BOEPD)
% Change
2017 vs. Combined 2016 Variance (BOEPD)
% Change
South Texas
Divested properties 1
Total (MBOE)
2018 vs 2017 Variance (MBOE)
% Change
2017 vs. Combined 2016 Variance (MBOE)
% Change
Total Production
Successor
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
Predecessor
January 1 Through
September 12,
2016
6,077
1,004
5,181
7,944
2,764
523
2,949
3,779
4,165
110 %
710
164
994
1,039
2,311
533
3,012
3,346
(606 )
(14 )%
Average Daily Production
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
January 1 Through
September 12,
2016
16,650
2,750
14
21,765
7,573
1,432
8
10,353
11,412
110 %
6,457
1,486
9
9,449
9,028
2,083
12
13,071
(1,631 )
(14 )%
Total Production by Region
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
January 1 Through
September 12,
2016
7,780
165
7,944
3,487
292
3,779
4,165
110 %
937
103
1,039
Average Daily Production by Region
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
3,071
276
3,346
(606 )
(14 )%
January 1 Through
September 12,
2016
11,995
1,076
13,071
South Texas
Divested properties 1
Total (BOEPD)
21,314
451
21,765
9,553
800
10,353
11.412
8,515
934
9,449
2018 vs 2017 Variance (BOEPD)
% Change
2017 vs. Combined 2016 Variance (BOEPD)
% Change
_____________________________________________
1 Represents total production and average daily production of our former Mid-Continent operations for all periods presented and approximately 10 MBOE (48 BOEPD) for
110 %
(1,631 )
(14 )%
Predecessor period in 2016 attributable to our three then-active Marcellus Shale wells.
49
2018 vs. 2017. Total production increased during 2018 compared to 2017 due primarily to a greater number of wells turned to sales in
2018 under our expanded drilling program as well as incremental production from the Hunt and Devon Acquisitions. We operated three drilling
rigs during 2018 compared to two during 2017, the second of which was not contracted until mid-March 2017. These increases were partially
offset by the effect of the divestiture in July 2018 of our former Mid-Continent operations, as well as natural production declines from our
legacy Eagle Ford wells.
Approximately 76 percent of total production during 2018 was attributable to crude oil when compared to approximately 73 percent
during 2017. Our Eagle Ford production represented 98 percent of our total production during 2018 compared to approximately 92 percent from
this region during 2017. Subsequent to the sale of our Mid-Continent properties on July 31, 2018, the entirety of our production was derived
from the Eagle Ford. During 2018, we turned 53 gross (45.5 net) Eagle Ford wells to sales compared to 29 gross (16.9 net) wells during 2017.
2017 vs. 2016. Total production decreased during 2017 compared to the combined Successor and Predecessor periods in 2016 due
primarily to natural production declines and the carryover effect from the suspension of our drilling program that began in February 2016 and
extended through November 2016. While we resumed the drilling program at the end of 2016, we did not turn any new wells to sales until mid-
February 2017. The decline was further exacerbated by mechanical issues with our previously-contracted drilling rigs and the effects of
Hurricane Harvey in August 2017 which resulted in a partial curtailment of production for several days as well as delays in our scheduled
drilling and completion activities in South Texas. Approximately 73 percent of total production during 2017 was attributable to crude oil when
compared to approximately 69 percent during the combined Successor and Predecessor periods in 2016. Our Eagle Ford production represented
92 percent of our total production during 2017 compared to approximately 91 percent from this region during the combined Successor and
Predecessor periods in 2016. During 2017, we turned 29 gross (16.9 net) Eagle Ford wells to sales compared to five gross (2.9 net) wells during
the combined Successor and Predecessor periods in 2016.
50
Product Revenues and Prices
The following tables set forth a summary of our revenues and prices per unit of volume by product and geographic region for the periods
presented:
Crude oil
NGLs
Natural gas
Total
2018 vs. 2017 Variance
% Change
2017 vs. Combined 2016 Variance
% Change
Crude oil ($ per barrel)
NGLs ($ per barrel)
Natural gas ($ per Mcf)
Total ($ per BOE)
$
$
$
$
$
$
2018 vs. 2017 Variance ($ per BOE)
% Change
2017 vs. Combined 2016 Variance ($ per BOE)
% Change
South Texas
Divested properties 1
Total
2018 vs. 2017 Variance
% Change
2017 vs. Combined 2016 Variance
% Change
South Texas
Divested properties 1
Total ($ per BOE)
$
$
$
$
$
Total Product Revenues
Successor
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
Predecessor
January 1 Through
September 12,
2016
402,485 $
21,073
15,972
439,530 $
$
$
$
140,886
10,066
8,517
159,469
280,061
176 %
33,157 $
2,707
2,790
38,654 $
$
81,377
6,064
6,208
93,649
27,166
21 %
Product Revenues per Unit of Volume
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
January 1 Through
September 12,
2016
66.23 $
20.99 $
3.08 $
55.33 $
$
$
$
$
$
50.96
19.25
2.89
42.20
13.13
31%
46.68 $
16.56 $
2.81 $
37.19 $
$
35.21
11.37
2.06
27.99
12.03
40 %
Product Revenues by Region
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
January 1 Through
September 12,
2016
435,599 $
3,931
439,530 $
$
$
$
152,521
6,948
159,469
280,061
176 %
36,261 $
2,393
38,654 $
$
88,849
4,800
93,649
27,166
21 %
Product Revenues per BOE by Region
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
January 1 Through
September 12,
2016
55.99 $
23.87 $
55.33 $
$
43.74
23.79
42.20
13.13
$
$
$
38.71 $
23.29 $
37.19 $
28.94
17.42
27.99
2018 vs. 2017 Variance ($ per BOE)
% Change
2017 vs. Combined 2016 Variance ($ per BOE)
% Change
_____________________________________________
1 Represents revenues of our former Mid-Continent operations for all periods presented and $0.1 million attributable to the Marcellus Shale for the Predecessor period in 2016.
31%
12.03
40 %
$
51
The following table provides an analysis of the changes in our revenues for the periods presented:
Year Ended December 31, 2018 vs.
Year Ended December 31, 2017
Revenue Variance Due to
Year Ended December 31, 2017 vs.
Combined Successor and Predecessor
Periods Ended December 31, 2016
Revenue Variance Due to
Volume
Price
Total
Volume
Price
Total
$
$
168,812 $
9,259
6,448
184,519 $
92,787 $
1,748
1,007
95,542 $
261,599
11,007
7,455
280,061
$
$
(9,742) $
(2,188)
(2,378)
(14,308 ) $
36,094 $
3,483
1,897
41,474 $
26,352
1,295
(481)
27,166
Crude oil
NGLs
Natural gas
2018 vs. 2017. Our product revenues during 2018 increased over 2017 due primarily to approximately 120 percent higher crude oil
volumes, 92 percent higher NGL volumes and 76 higher natural gas volumes as well as the effect of 30 percent higher crude oil prices and
approximately seven percent higher natural gas prices. Our Eagle Ford crude oil production benefits from pricing based on the LLS index which
has averaged approximately eight percent higher than the comparable WTI index during the year ended in 2018 compared to 2017. Excluding
the $2.4 million effect of the adoption of ASC Topic 606, NGL pricing increased by 21 percent during 2018 as compared to 2017.
Crude oil revenues were approximately 92 percent of our total revenues during 2018 as compared to 88 percent during 2017. Total Eagle
Ford revenues were approximately 99 percent of total revenues during 2018 and 96 percent in 2017. Effective August 2018, all of our revenues
were derived from the Eagle Ford.
2017 vs. 2016. Our product revenues in 2017 increased over the combined Successor and Predecessor periods in 2016 due primarily to the
significant increases in all product pricing which was partially offset by the decline in production described previously. Total crude oil revenues
were approximately 88 percent during 2017 compared to 87 percent during the combined Successor and Predecessor periods in 2016. Total Eagle
Ford revenues were approximately 96 percent of total revenues in 2017 compared to 95 percent in the combined Successor and Predecessor
periods in 2016.
Effects of Derivatives
The following table reconciles crude oil revenues to realized prices, as adjusted for derivative activities, for the periods presented:
Successor
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
Predecessor
January 1 Through
September 12,
2016
$
$
$
$
402,485 $
(48,291 )
354,194 $
66.23 $
(7.95 )
58.28 $
140,886 $
(3,511)
137,375
$
50.96 $
(1.27 )
49.69
$
33,157 $
384
33,541 $
46.68 $
0.54
47.22 $
81,377
48,008
129,385
35.21
20.77
55.98
Crude oil revenues as reported
Derivative settlements, net
Crude oil prices per Bbl, as reported
Derivative settlements per Bbl
Gain (Loss) on Sales of Assets
We recognize gains and losses on the sale or disposition of assets other than our oil and gas properties upon the completion of the
underlying transactions.
The following table sets forth the total gains and losses recognized for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12,
2016
Gain (loss) on sales of assets, net
$
(177) $
(36 ) $
(49 )
$
1,261
2018, 2017 and Successor Period in 2016. In 2018, 2017 and the Successor period in 2016, we recognized insignificant net losses
attributable to sale of certain support equipment and tubular inventory and well materials.
52
Predecessor Period in 2016. The Predecessor period in 2016 includes $1.7 million from the amortization of deferred gains attributable to
our 2014 sale of rights to construct a crude oil gathering and intermediate transportation system. The amortization of $0.3 million of deferred
gains from the 2014 sale of our South Texas natural gas gathering and gas lift assets is also included for the Predecessor period in 2016. As of
the Emergence Date, the unamortized portions of those deferred gains were reversed from our Consolidated Balance Sheet in connection with
our application of Fresh Start Accounting and included as a component of Reorganization items, net.
Other Revenues, Net
Other revenues, net, includes fees for marketing and water disposal services that we charge to third parties, net of related expenses as
well as other miscellaneous revenues and credits attributable to our operations. During the Predecessor period, these revenues also included fees
for water supply services as well as charges for accretion attributable to our unused firm transportation obligation.
The following table sets forth the total other revenues, net for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12,
2016
Other revenues, net
$
1,479 $
621 $
398 $
(600 )
2018 vs. 2017. Other revenues, net increased during 2018 from 2017 due primarily to higher fees charged to third parties resulting from
substantially higher production.
2017 vs. 2016. Other revenues, net increased during 2017 from the combined Successor and Predecessor periods in 2016 due primarily to
higher marketing fees partially offset by lower water disposal fees resulting from lower overall production. The combined Successor and
Predecessor periods in 2016 included charges for reserves of certain of our receivables from joint venture partners and charges attributable to the
accretion of unused firm transportation, both of which are presented as contra-revenue items in this caption. There were no firm transportation
charges in 2017 because the underlying obligation was rejected in our bankruptcy proceedings.
Lease Operating Expenses
LOE include costs that we incur to operate our producing wells and field operations. The most significant costs include compression and
gas-lift, chemicals, water disposal, repairs and maintenance, including down-hole repairs, field labor, pumping and well-tending, equipment
rentals, utilities and supplies among others.
The following table sets forth our LOE for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12,
2016
Lease operating
Per unit of production ($/BOE)
$
$
35,879 $
4.52 $
21,784 $
5.76 $
5,331 $
5.13 $
15,626
4.67
2018 vs. 2017. LOE increased on an absolute basis, but declined on a per unit basis during 2018 when compared to 2017. The absolute
increases were due primarily to higher production volume including the incremental effects of the Devon and Hunt Acquisitions. The higher
production volume also had the effect of decreasing the overall per unit cost, particularly those costs that have a higher fixed cost component.
Furthermore, comprehensive maintenance costs in the second half of 2017 improved production and cost efficiency progressing throughout
2018.
2017 vs. 2016. LOE increased on an absolute and per unit basis during 2017 when compared to the combined Successor and Predecessor
periods in 2016 due primarily to lower production volume, as well as higher surface and other repair and maintenance costs. We proceeded with
certain of these repair and maintenance efforts during the third quarter of 2017 in order to recover a portion of the production shortfall brought
about by Hurricane Harvey and the operational delays discussed above. While we incurred approximately $1 million of higher surface repair
costs in 2017, they were partially offset by continuing cost containment efforts that we implemented throughout 2016 and into 2017 as well as
the effects of lower industry-wide pricing for certain oilfield products and services.
53
Gathering Processing and Transportation
GPT includes costs that we incur to gather and aggregate our crude oil, NGL and natural gas production from our wells and deliver them
via pipeline or truck to a central delivery point, downstream pipelines or processing plants, and blend or process, as necessary, depending upon
the type of production and the specific contractual arrangements that we have with the applicable midstream operators.
The following table sets forth our GPT for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12,
2016
Gathering, processing and transportation
Per unit of production ($/BOE)
$
$
18,626 $
2.34 $
10,734 $
2.84 $
3,043 $
2.93 $
13,235
3.96
2018 vs. 2017. GPT expense increased on an absolute basis during 2018 when compared to 2017 due primarily to substantially higher
production volumes partially offset by the effect of the adoption of ASC Topic 606, or $2.4 million. Per unit costs declined $0.30 per BOE in
2018 due primarily to the effect of the adoption of ASC Topic 606, as well as a result of increased production sold at the wellhead with no
corresponding GPT expense.
2017 vs. 2016. GPT decreased on an absolute and per unit basis during 2017 when compared to the combined Successor and Predecessor
periods in 2016 due primarily to lower production volumes and decreased gathering rates pursuant to an amendment to our gathering agreement
with Republic Midstream, which became effective in August of 2016. Prior to that time we had incurred $0.4 million of deficiency charges for
production failing to meet our minimum volume commitments which were previously higher. We also incurred costs of approximately $0.5
million in the Predecessor periods in 2016 for unused firm transportation services in the Marcellus Shale prior to our termination of operations
in that region. There were no such costs incurred in 2017 as the underlying contracts were rejected in our bankruptcy proceedings.
Production and Ad Valorem Taxes
Production or severance taxes represent taxes imposed by the states in which we operate for the removal of resources including crude oil,
NGLs and natural gas. Ad valorem taxes represent taxes imposed by certain jurisdictions, primarily counties, in which we operate, based on the
value of our operating properties. The assessments for ad valorem taxes are generally based on contemporary commodity prices.
The following table sets forth our production and ad valorem taxes for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12,
2016
Production and ad valorem taxes
Production/severance taxes
Ad valorem taxes
Per unit of production ($/BOE)
Production/severance tax rate as a percent of
product revenues
$
$
$
20,619
2,928
23,547
2.96
$
$
$
7,533
1,281
8,814
2.33
$
$
$
4.7 %
4.7 %
1,801
697
2,498
2.40
$
$
$
4.7 %
2,695
795
3,490
1.04
2.9 %
2018 vs. 2017. Production taxes increased on both an absolute and per unit basis during 2018 when compared to 2017 due primarily to
increased production volume and higher commodity prices. Accruals for ad valorem taxes have also increased for 2018 as we have grown our
assessable property base and we anticipate higher assessments as a result of higher commodity prices and increased working interests.
2017 vs. 2016. Production taxes increased on both an absolute and per unit basis during 2017 when compared to the combined Successor
and Predecessor periods in 2016 due primarily to the recognition of certain severance tax refunds from Oklahoma in the 2016 periods that were
attributable to prior years, as well as higher commodity prices despite a decline in production volume in 2017. In the latter half of 2016 and into
2017, we adjusted our accruals for ad valorem taxes downward, primarily in South Texas, reflecting lower oil and gas property valuations.
54
General and Administrative
Our G&A expenses include employee compensation, benefits and other related costs for our corporate management and governance
functions, rent and occupancy costs for our corporate facilities, insurance, and professional fees and consulting costs supporting various
corporate-level functions, among others. In order to facilitate a meaningful discussion and analysis of our results of operations with respect to
G&A, we have disaggregated certain costs into three components as presented in the table below. Primary G&A encompasses all G&A costs
except share-based compensation and certain significant special charges that are generally attributable to material stand-alone transactions or
corporate actions that are not otherwise in the normal course.
The following table sets forth the components of G&A expenses for the periods presented:
Primary G&A
Shares-based compensation
Liability-classified
Equity-classified
Significant special charges
Acquisition, divestiture and strategic
transaction costs
Strategic and financial advisory costs
Executive retirement costs
Restructuring expenses
Total general and administrative expenses
Per unit of production ($/BOE)
Per unit of production excluding all share-based
compensation and other significant special
charges identified above ($/BOE)
$
$
$
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
$
17,236 $
13,072 $
5,065
$
—
4,618
—
3,809
3,960
—
250
—
26,064 $
3.28 $
1,340
—
—
(20 )
18,201 $
4.82 $
—
81
—
—
—
(80 )
5,066
$
4.88 $
2.17 $
3.46 $
4.87 $
Predecessor
January 1 Through
September 12,
2016
15,607
(19 )
1,511
—
18,036
—
3,821
38,956
11.64
4.66
2018 vs. 2017. Our primary G&A expenses increased on an absolute and decreased on a per unit basis during 2018 compared to 2017.
The absolute increase is due primarily to the effects of higher payroll, benefits and support costs attributable to a higher overall employee
headcount as well as costs associated with the relocation of our corporate headquarters to a new office within Houston, Texas. Higher
production volume had the effect of reducing G&A per unit of production for 2018.
Equity-classified share-based compensation charges during all of the Successor periods are attributable to the amortization of
compensation cost associated with the grants of time-vested restricted stock units, or RSUs, and performance restricted stock units, or PRSUs.
The grants of RSUs and PRSUs are described in greater detail in Note 17 to the Consolidated Financial Statements included in Part II, Item 8,
“Financial Statements and Supplementary Data.” A substantial portion of the share-based compensation expense is attributable to the RSU and
PRSU grants made in the normal course in January 2017 and an RSU grants in September and December of 2016 in connection with our
reorganization. The remainder is attributable to grants of RSUs and PRSUs to certain employees upon their hiring or as a result of promotion
subsequent to the first quarter of 2017. The year 2018 also includes a charge of $0.6 million attributable to the accelerated vesting of certain
RSUs and PRSUs in connection with the retirement of our Executive Chairman in February 2018. All of our equity-classified share-based
compensation represents non-cash expenses.
During 2018, we incurred consulting and other costs associated with our review of strategic alternatives, including the Merger. In addition
to these costs, we incurred transaction costs associated with the Mid-Continent divestiture and the Hunt Acquisition, including legal, due
diligence and other professional fees. We also paid certain costs attributable to the retirement of our former Executive Chairman in February
2018. In the Successor periods in 2017, we recorded adjustments to severance-related restructuring accruals that were originally established in
connection with our reorganization in the Predecessor period in 2016.
2017 vs. 2016. Our primary G&A expenses decreased on an absolute and per unit basis during 2017 compared to the combined Successor
and Predecessor periods in 2016. The decrease is due primarily to the effects of: (i) lower payroll and benefits attributable to a lower overall
employee headcount, (ii) the capitalization of certain labor and benefits costs to oil and gas properties in accordance with the full cost method in
2017, (iii) the relocation of our headquarters from Radnor, Pennsylvania to Houston, Texas and related move to a smaller office location, (iv)
reduced travel and entertainment and (v) lower corporate support costs consistent with our efforts throughout 2016 and 2017 to decrease our
support cost base.
55
Liability-classified share-based compensation in the 2016 Predecessor period was attributable to our former performance-based restricted
stock units, or PBRSUs, and represents mark-to-market adjustments associated with the change in fair value of the then-outstanding PBRSU
grants. Our common stock performance relative to a defined peer group was less favorable during the 2016 period resulting in a mark-to-market
reversal. All of the unvested PBRSUs were canceled upon our emergence from bankruptcy.
Equity-classified share-based compensation in the Predecessor period in 2016 includes a charge for the cancellation of all of the RSUs
outstanding prior to our bankruptcy filing in May 2016, partially offset by forfeitures of the Predecessor’s stock options.
During 2017, we incurred transaction costs associated with the Devon Acquisition and certain costs in advance of the Hunt Acquisitions,
including advisory, legal, due diligence and other professional fees. During the Predecessor period in 2016, we incurred substantial professional
fees and other consulting costs associated with our consideration of strategic financing alternatives and related activities in advance of our
bankruptcy filing. In connection with our efforts to simplify and reduce our administrative cost structure, we terminated a total of 45 employees
during the combined Successor and Predecessor periods in 2016 and incurred related termination and severance benefit costs during the
Predecessor periods.
Exploration
While applying the successful efforts method of accounting to our oil and gas properties during the Predecessor period in 2016, we
incurred costs which were charged to operations in accordance with the successful efforts method. In the Successor periods, we applied the full
cost method whereby these costs are capitalized. See the discussion of our capital expenditures program included in “Financial Condition -
Cash Flows” above and Note 8 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary
Data” for a discussion of certain capitalized costs.
The following table sets forth the components of exploration expenses for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12,
2016
Unproved leasehold amortization
Drilling rig termination charges
Drilling carry commitment
Geological and geophysical costs (seismic)
Other, primarily write-off of uncompleted wells
$
$
— $
—
—
—
—
— $
— $
—
—
—
—
— $
— $
—
—
—
—
— $
1,940
1,705
1,964
33
4,646
10,288
On the Emergence Date we adopted the full cost method. Accordingly, there are no exploration expenses recorded for any of the
Successor periods. With respect to the Predecessor period in 2016, we recorded: (i) leasehold amortization attributable to our undeveloped
properties, (ii) early termination charges in connection with the release of drilling rigs in the Eagle Ford, (iii) a charge attributable to our failure
to complete a drilling carry requirement attributable to certain acreage acquired in the Eagle Ford in 2014, (iv) certain costs for acquired seismic
data, (v) a charge of $4.0 million for the write-off of certain uncompleted well costs prior to the aforementioned change in accounting method
and (vi) a charge of $0.6 million for coiled tubing services that were not utilized by the contract expiration date.
Depreciation, Depletion and Amortization (DD&A)
As discussed with respect to exploration expenses above, our adoption of the full cost method in place of the successful efforts method of
accounting for oil and gas properties also impacted the determination of our DD&A during the Successor periods as compared to the
Predecessor period in 2016. For a more detailed discussion of the determination of our DD&A, see the discussion of “Critical Accounting
Estimates” that follows as well as Note 3 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and
Supplementary Data.”
The following table sets forth total and per unit costs for DD&A for the periods presented:
Successor
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
Predecessor
January 1 Through
September 12,
2016
DD&A expense
DD&A rate ($/BOE)
$
$
127,961 $
16.11 $
48,649 $
12.87 $
11,652 $
11.21 $
33,582
10.04
56
2018 vs. 2017. DD&A increased on an absolute and per unit basis during 2018 when compared to 2017. Higher production volume
provided for an increase of approximately $53.6 million while $25.7 million was attributable to the higher DD&A rates in 2018. The higher
DD&A rates in the 2018 periods were attributable to costs added to the full cost pool, including those from the Devon and Hunt Acquisitions,
during a period of rising crude oil prices, as well as the sale of our Mid-Continent properties in July 2018, while the DD&A rate for 2017 period
is based primarily on the fair value of our properties at the time of our emergence from bankruptcy in September 2016.
2017 vs. 2016. Lower production volumes net of the effects of higher depletion rates were the primary factors attributable to the increase
in DD&A during 2017 when compared to the combined Successor and Predecessor period in 2016. The Successor periods include a higher
proportion of capitalized costs relative to the underlying proved reserves, consistent with the full cost method, when compared to the
Predecessor periods which utilized the successful efforts method.
Interest Expense
The following table summarizes the components of our interest expense for the periods presented:
Interest on borrowings and related fees
Accretion of original issue discount
Amortization of debt issuance costs
Capitalized interest
Successor
Year Ended December 31,
2018
2017
$
$
32,164
680
2,736
(9,118)
26,462 $
6,995 $
161
1,961
(2,725)
6,392
$
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12,
2016
$
678
—
226
(25 )
879
$
36,012
—
22,189
(183 )
58,018
2018 vs. 2017. Interest expense increased during 2018 as compared to 2017 due primarily to higher outstanding balances under the Credit
Facility, including amounts borrowed to fund our larger capital expenditure program in 2018 and the Hunt Acquisition, as well as interest
attributable to the Second Lien Facility that was entered into in September 2017. Furthermore, the Credit Facility and the Second Lien Facility
are variable-rate instruments and both have been subject to periodic increases in LIBOR rates on a consistent basis since 2017. The accretion of
original issue discount is entirely attributable to the Second Lien Facility while the amortization of debt issuance costs includes amounts
attributable to both the Credit Facility and Second Lien Facility. We capitalized a larger portion of interest during 2018 as we maintained a
substantially larger balance of unproved property as compared to 2017 due primarily to the Devon Acquisition.
2017 vs. 2016. Interest expense for 2017 is attributable to the Credit and Second Lien Facilities whereas interest expense during the
Successor period in 2016 is exclusively attributable to the Credit Facility. Interest expense during the Predecessor period in 2016 is attributable
to pre-petition credit facility, or RBL, and our 7.25% Senior Notes due 2019, or the 2019 Senior Notes, and our 8.50% Senior Notes due 2020, or
the 2020 Senior Notes, and together with the 2019 Senior Notes, the Senior Notes. Weighted-average amounts outstanding under the Credit
Facility during 2017 were lower than the combined weighted-average amounts outstanding under the Credit Facility and RBL during the
combined 2016 periods resulting in lower expense. This was partially offset by interest expense on borrowings as well as amortization and
accretion of debt issue costs and OID, respectively, attributable to the Second Lien Facility. The 2016 Predecessor period also includes a $20.5
million accelerated write-off of issuance costs associated with the RBL and Senior Notes in advance of our bankruptcy filings.
Derivatives
The gains and losses for our derivatives portfolio reflect changes in the fair value attributable to changes in market values relative to our
hedged commodity prices.
The following table summarizes the gains and (losses) attributable to our crude oil derivatives portfolio for the periods presented:
Successor
September 13 Through
Year Ended December 31,
December 31,
2018
2017
2016
Predecessor
January 1 Through
September 12,
2016
Crude oil derivative gains (losses)
$
37,427 $
(17,819 ) $
(16,622 ) $
(8,333 )
2018 vs. 2017. The forward curve for commodity prices declined relative to our weighted-average hedged prices during 2018 resulting in
a net gain for the year ended December 31, 2018 while the forward curve for such prices increased relative to our weighted-average hedged
prices during 2017. We paid cash settlements of $48.3 million in 2018 as compared to cash settlements paid of $3.5 million in 2017.
57
2017 vs. 2016. We paid cash settlements of $3.5 million in 2017 as compared to the receipt of $48.4 million of cash settlements from
crude oil derivatives during the combined Successor and Predecessor periods in 2016. During 2017, prices under our derivative contracts were
lower than the actual WTI crude oil prices resulting in net payments while the opposite situation occurred in the combined Successor and
Predecessor periods in 2016 resulting in net receipts of cash settlements as well as the early termination of certain pre-petition derivative
contracts in the Predecessor periods in 2016 which accelerated the receipt of cash settlements.
Other, Net
Other, net includes interest income, non-service costs associated with our retiree benefit plans and miscellaneous items of income and
expense that are not directly associated with our current operations, including certain recoveries and write-offs attributable to prior years and
properties that have been divested.
The following table sets forth the other income (expense), net recognized for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12,
2016
Other, net
$
2,266 $
58 $
792 $
(3,173 )
2018. In 2018, we received a recovery of $1.5 million from partners attributable to a prior-year acquisition and received recoveries of
$0.3 million of joint interest receivable balances previously written-off in connection with the bankruptcy of a former partner. We also received
severance tax refunds attributable to previously-divested properties in excess of recorded amounts, interest income earned on the escrow account
attributable to the Devon Acquisition prior to the escrow account’s liquidation in March 2018 as well as recording the reversal of a litigation
reserve attributable to previously-divested properties. The combined benefit to income from these items was approximately $0.7 million. These
amounts were partially offset by interest charges applicable to a settlement with a royalty owner and charges associated with our retiree benefit
plans.
2017. In 2017, we recorded interest income attributable to the escrow account attributable to the Devon Acquisition that was partially
offset by charges associated with our retiree benefit plans and certain costs attributable to assets that were sold in prior years.
2016. In the Successor period of 2016, we reversed $0.9 million representing a portion of a reserve recognized in the Predecessor period
of 2016 attributable to a prior-year acquisition-related receivable. This item was partially offset by the write-off of certain acquisition-related
joint interest billing receivables and a decline in the market value of certain supplemental retirement plan assets prior to their reversion to us in
connection with our emergence from bankruptcy. In the Predecessor period of 2016, we initially reserved the aforementioned acquisition-related
receivable for $2.9 million and wrote-off unrecoverable amounts from prior years, including severance tax receivables, certain joint interest
billing receivables, GPT and other revenue deductions due from other parties of $0.6 million, all of which were attributable primarily to
properties that were sold in prior years. These items were partially offset by a vendor settlement of $0.3 million also attributable to prior periods.
Reorganization Items, Net
The following table summarizes the components included in “Reorganization items, net” for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12,
2016
Gains on the settlement of liabilities subject to
compromise
Fresh Start Accounting adjustments
Legal and professional fees and expenses
Settlements attributable to contract amendments
Debtor-in-Possession Facility costs and
commitment fees
Write-off of prepaid directors and officers
insurance
Other reorganization items
$
$
— $
—
200
—
—
—
3,122
3,322 $
58
— $
—
—
—
—
—
—
— $
— $
—
—
—
—
—
—
— $
1,150,248
28,319
(29,976 )
(2,550 )
(170 )
(832 )
(46 )
1,144,993
2018. While we emerged from bankruptcy in September 2016, certain administrative and claims resolution activities continued until
November 2018 when the Bankruptcy Court issued a final decree which effectively closed the case. Upon the closure, we reversed the
remaining $0.2 million unused portion of an accrual that was established on the Emergence Date for legal and professional fees and
administrative costs. In addition, we reversed the $2.7 million unallocated portion of a reserve that was established on the Emergence Date for
the potential settlement of certain claims in cash. Finally, we also reversed $0.4 million of accounts payable that were held open since the
Emergence Date as secured claims, but were ultimately expunged. As these items of income are directly attributable to the final administration
of our bankruptcy case and not a part of our continuing operations, they are classified on our Consolidated Statement of Operations as
components of “Reorganization items, net.”
2016. The gains on the settlement of liabilities subject to compromise are primarily attributable to the Senior Notes and interest thereon.
The Fresh Start Accounting adjustments include those fair value adjustments attributable to our property and equipment, asset retirement
obligations, or AROs, retiree benefit obligations and the accelerated recognition of previously deferred gains of the Predecessor. The legal and
professional fees that we incurred were attributable to our advisers as well as those of the various creditor committees, the RBL lenders and the
indenture trustee under the Senior Notes. We paid settlements in cash with respect to certain critical contract amendments. While we did not
borrow any amounts under the Debtor-in-Possession, or DIP, credit facility from the Petition Date through the Emergence Date, we paid certain
costs and fees to arrange and maintain the DIP credit facility during this term. Upon emergence from bankruptcy, we wrote off certain prepaid
directors and officers insurance attributable to the Predecessor.
The items described herein are also described in further detail in Note 4 to the Consolidated Financial Statements included in Part II, Item
8, “Financial Statements and Supplementary Data.”
Income Taxes
The following table summarizes our income tax provision for the periods presented:
Successor
Year Ended December 31,
2018
2017
September 13 Through
December 31,
2016
Predecessor
January 1 Through
September 12,
2016
Income tax (expense) benefit
Effective tax rate
$
$
(523)
0.2 %
4,943
$
17.8%
$
—
— %
—
— %
2018. The provision for the year ended December 31, 2018 includes a current federal benefit of $2.5 million attributable to the
anticipated refund of alternative minimum tax, or AMT, credits for the 2018 tax year. This amount has been recognized as a current income tax
receivable on our Consolidated Balance Sheet as of December 31, 2018. This benefit is offset by a corresponding decrease in the deferred tax
asset associated with the refundable AMT credit giving rise to a deferred federal expense. In addition, we have a recognized a deferred state tax
expense of $0.5 million for an overall effective tax rate of 0.2%.
2017. In connection with our analysis of the impact of the TCJA we recorded an income tax charge of $86.6 million for the year ended
December 31, 2017, which consists of a reduction of deferred tax assets previously valued at 35%. We recorded a corresponding decrease in our
deferred tax asset valuation allowance representing an income tax benefit for the same amount. In addition to the aforementioned offsetting
items with respect to the reduction in income tax rates, our income tax provision included federal income taxes of $9.7 million applied at the
statutory rate of 35% for 2017 and an adjustment of $10.8 million attributable to reductions in certain tax attributes of property and other
adjustments of $0.3 million applied in connection with the filing of our 2016 income tax returns. These expenses were effectively offset by
benefits attributable to the reduction in our deferred tax asset valuation allowance of $24.3 million and state income tax benefits of $1.4 million
resulting in a net tax deferred benefit of $4.9 million, all of which is attributable to refundable AMT credit carryforwards.
2016. We recognized a federal income tax benefit for each of the Successor and Predecessor periods in 2016 at the statutory rate of 35%;
however, the federal tax benefit was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive
and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized,
primarily as a result of our cumulative losses.
59
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of
December 31, 2018, the material off-balance sheet arrangements and transactions that we have entered into included operating lease
arrangements, information technology licensing, service agreements, employment agreements and letters of credit, all of which are customary in
our business. Note that, effective January 1, 2019, the aforementioned lease arrangements will be recorded on our Consolidated Balance Sheet
as described in greater detail in “Disclosure of the Impact of Recently Issued Accounting Standards to be Adopted in the Future” below and Note
2 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” See “Contractual
Obligations” summarized below and Note 15 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and
Supplementary Data” for more details related to the value of our off-balance sheet arrangements. We did not have any relationships with
unconsolidated entities or financial partnerships, such as structured finance or special purpose entities, which would have been established for
the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We are, therefore, not materially
exposed to any financing, liquidity, market or credit risk that could arise had we engaged in such relationships.
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2018:
Payments Due by Period
Total
Less than
1 Year
1-3 Years
3-5 Years
More Than
5 Years
Credit Facility 1
Second Lien Facility 2
Interest payments on long-term debt 3
Operating leases 4
Crude oil gathering and transportation commitments 5
Drilling and completion commitments 6
Asset retirement obligations 7
Derivatives
Other commitments 8
Total contractual obligations
$
$
321,000 $
200,000
103,821
3,257
114,300
20,692
114,553
991
419
879,033 $
— $
—
38,187
532
11,702
20,692
—
991
254
72,358 $
321,000 $
—
51,483
1,294
25,924
—
—
—
165
399,866 $
— $
200,000
14,151
1,272
25,924
—
—
—
—
241,347 $
—
—
—
159
50,750
—
114,553
—
—
165,462
_____________________________________________
1 Assumes that the amount outstanding of $321 million as of December 31, 2018 will remain outstanding until its maturity in 2020. The Credit Facility has been classified as a
long term liability on our Consolidated Balance Sheet as described in “Financial Condition – Liquidity” and in Note 10 to the Consolidated Financial Statements included in
Part II, Item 8, “Financial Statements and Supplementary Data.”
2 Assumes that the amount outstanding of $200 million as of December 31, 2018 will remain outstanding until its maturity in 2022. The Second Lien Facility has been
classified as a long term liability on our Consolidated Balance Sheet as described in “Financial Condition – Liquidity” and in Note 10 to the Consolidated Financial
Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
3 Represents estimated interest payments that will be due under the Credit Facility and Second Lien Facility, assuming that the underlying LIBOR-based interest rates in effect
at December 31, 2018 remain in effect and the amounts outstanding of $321 million and $200 million as of December 31, 2018, respectively, will remain outstanding until
their maturities in 2020 and 2022, respectively.
4 Relates primarily to office facilities and equipment
leases.
5 Represents minimum payments for gathering and intermediate pipeline transportation services for our crude oil and condensate production in South Texas. The gathering
portion of these commitments is recognized as GPT while the intermediate transportation and pipeline support components are recognized as a reduction to the index-
based price that we receive from crude oil sold to Republic Midstream.
6 Includes fixed-term commitments for one drilling rig and one frac service crew and materials. Does not include commitments for drilling rigs contracted on a pad-to-pad
basis
7 Represents the undiscounted balance payable, primarily for the plugging of inactive wells, in periods more than five years in the future for which
$4.3 million , on a
discounted basis, has been recognized on our Consolidated Balance Sheet as of December 31, 2018. While we may make payments to settle certain AROs, including those
subject to regulatory requirements during each of the next five years, no material amounts are currently required by contract or regulatory authority to be made during this
time frame.
8 Represents all other significant obligations including information technology licensing and service agreements, among
others.
60
Critical Accounting Estimates
The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments
regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments
change or if the actual results differ from these estimates and judgments. We consider the following to be the most critical accounting estimates
requiring judgment of our management.
Fresh Start Accounting
On the Emergence Date, we adopted Fresh Start Accounting. Fresh Start Accounting involved a comprehensive valuation process in
which we determined the fair value of all of our assets and liabilities on the Emergence Date. This process, which is more fully described in
Note 4 to our Consolidated Financial Statements included in Item II, Part 8, “Financial Statements and Supplementary Data,” utilized several
critical estimates associated with, among other items, our development plans, financial projections, regional and broader market conditions as
well as an estimated discount rate.
Oil and Gas Reserves
Estimates of our oil and gas reserves are the most critical estimate included in our Consolidated Financial Statements. Reserve estimates
become the basis for determining depletive write-off rates and the recoverability of historical cost investments. There are many uncertainties
inherent in estimating crude oil, NGL and natural gas reserve quantities, including projecting the total quantities in place, future production rates
and the amount and timing of future development expenditures. In addition, reserve estimates of new discoveries are less precise than those of
producing properties due to the lack of a production history. Accordingly, these estimates are subject to change as additional information
becomes available.
There are several factors which could change the estimates of our oil and gas reserves. Significant rises or declines in commodity product
prices as well as changes in our drilling plans could lead to changes in the amount of reserves as production activities become more or less
economical. An additional factor that could result in a change of recorded reserves is the reservoir decline rates differing from those assumed
when the reserves were initially recorded. Estimation of future production and development costs is also subject to change partially due to
factors beyond our control, such as energy costs and inflation or deflation of oil field service costs.
Oil and Gas Properties
Beginning on the Emergence Date, we have applied the full cost method to account for our oil and gas properties. Under this method, all
productive and nonproductive costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs
may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic,
drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition
activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are
also capitalized. Future development costs are estimated on a property-by-property basis based on current economic conditions and are
amortized as a component of DD&A.
Unproved properties not being amortized include unevaluated leasehold costs and associated capitalized interest. These costs are
reviewed quarterly to determine whether or not and to what extent proved reserves have been assigned to a property or if an impairment has
occurred due to lease expirations, general economic conditions and other factors, in which case, the related costs along with associated
capitalized interest are reclassified to the proved oil and gas properties subject to DD&A. Factors we consider in our assessment include drilling
results, the terms of oil and gas leases not held by production and drilling and completion capital expenditures consistent with our plans.
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 discounted future net revenues from proved properties adjusted for costs excluded from amortization and related
income taxes, or a Ceiling Test. The estimated 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. As of December 31, 2018, the carrying value of our proved oil and gas
properties was below the limit determined by the Ceiling Test by approximately $800 million.
Depreciation, Depletion and Amortization
DD&A of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the
unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing
the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the
period.
61
Derivative Activities
From time to time, we enter into derivative instruments to mitigate our exposure to commodity price volatility. The derivative financial
instruments that we employ, which are placed with financial institutions that we believe are of acceptable credit risk, generally take the form of
collars and swaps, among others. All derivative instruments are recognized in our Consolidated Financial Statements at fair value with the
changes recorded currently in earnings. The fair values of our derivative instruments are determined based on discounted cash flows derived
from quoted forward prices. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by
our board of directors.
Deferred Tax Asset Valuation Allowance
We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized after
consideration of future taxable income and reasonable tax planning strategies. In the event that we were to determine that we would not be able
to realize all or a part of our deferred tax assets for which a valuation allowance had not been established, an adjustment to the deferred tax asset
will be reflected in income in the period such determination is made. The most significant matter applicable to the realization of our deferred tax
assets is attributable to net operating losses at the federal level as well as certain states in which we operate. Estimates of future taxable income
inherently reflect a significant degree of uncertainty. As of December 31, 2018, we had a full valuation allowance for all of our net deferred tax
assets, with the exception of our remaining refundable AMT credit carryforwards, due primarily to our inability to project sufficient future
taxable income in both the federal and various state jurisdictions.
Disclosure of the Impact of Recently Issued Accounting Standards to be Adopted in the Future
In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments, or ASU 2016–13, which changes
the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities,
among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption
permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events
and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i)
estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions
and reasonably supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable
portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our
traditional customer receivables. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our
Consolidated Financial Statements and related disclosures; however, we are continuing to evaluate the requirements and the period for which
we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique to our industry.
In February 2016, the FASB issued ASU 2016–02, Leases, or ASU 2016–02, which will require organizations that lease assets to
recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve
months. Together with recent related amendments to GAAP, ASU 2016–02 represents ASC Topic 842 Leases, or ASC Topic 842, which
supersedes all current GAAP with respect to leases. The recognition, measurement, and presentation of expenses and cash flows arising from a
lease by a lessee primarily will depend on its classification as a finance or operating lease. ASC Topic 842 also will require disclosures
regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASC Topic 842 is January 1, 2019, with
early adoption permitted.
ASC Topic 842 will be applicable to our existing leases for office facilities and certain office equipment, certain field equipment, land
easements and similar arrangements for rights-of-way, certain natural gas gathering and gas lift assets and potentially to certain drilling rig
contracts with terms in excess of 12 months to the extent we may have such contracts in the future. We are finalizing our evaluation of the
impact that the adoption may have on certain crude oil gathering arrangements.
We will adopt ASC Topic 842 effective January 1, 2019 using the modified retrospective method with a cumulative effect charge to the
beginning balance of retained earnings that is not anticipated to be material. We anticipate recognizing total right-of-use assets and lease of
obligations of approximately $3 million, excluding any potential impact attributable to our crude oil gathering arrangements. Upon adoption, all
of the leases for which we are recognizing assets and liabilities will be classified as operating leases. We also have identified certain contractual
arrangements that will be classified as variable leases. We plan to adopt certain practical expedients provided for in ASC Topic 842 including (i)
those associated with the reassessment and classification of existing leases, (ii) land easements and (iii) an election to not separate lease and non-
lease components. We also plan to make an accounting policy election, effective January 1, 2019, whereby any leases with terms of one year or
less will be formally classified as short-term leases.
62
Item 7A
Quantitative and Qualitative Disclosures About Market
Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are
exposed are interest rate risk and commodity price risk.
Interest Rate Risk
Our interest rate risk is attributable to our borrowings under the Credit Facility and the Second Lien Facility, which are subject to variable
interest rates. As of December 31, 2018, we had borrowings of $321 million under the Credit Facility at an interest rate of 5.96%. As of
December 31, 2018, we had borrowings of $190.4 million under the Second Lien Facility, net of OID and issuance costs, at an interest rate of
9.53%. Assuming a constant borrowing level under the Credit and Second Lien Facilities, an increase (decrease) in the interest rate of one
percent would result in an increase (decrease) in interest expense of approximately $5.2 million on an annual basis.
Commodity Price Risk
We produce and sell crude oil, NGLs and natural gas. As a result, our financial results are affected when prices for these commodities
fluctuate. Our price risk management programs permit the utilization of derivative financial instruments (such as collars and swaps) to seek to
mitigate the price risks associated with fluctuations in commodity prices as they relate to a portion of our anticipated production. The derivative
instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our derivative
instruments are significantly affected by fluctuations in the prices of oil and natural gas. We are not currently utilizing any derivative
instruments with respect to NGLs and natural gas, although we may do so in the future.
As of December 31, 2018, we reported a net commodity derivative asset of $44.0 million. The contracts associated with this position are
with eight counterparties, all of which are investment grade financial institutions. This concentration may impact our overall credit risk, either
positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither
paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative
contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that
may be owed to us by these counterparties.
During the year ended December 31, 2018, we reported net commodity derivative gains of $37.4 million. We have experienced and
could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our
derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which
fluctuate with changes in crude oil, NGL and natural gas prices. These fluctuations could be significant in a volatile pricing environment. See
Note 7 to our Consolidated Financial Statements included in Part II, Item 8, included in Part II, Item 8, “Financial Statements and
Supplementary Data” for a further description of our price risk management activities.
The following table sets forth our commodity derivative positions as of December 31, 2018:
Crude Oil:
First quarter 2019
First quarter 2019
Second quarter 2019
Second quarter 2019
Third quarter 2019
Third quarter 2019
Fourth quarter 2019
Fourth quarter 2019
First quarter 2020
Second quarter 2020
Third quarter 2020
Fourth quarter 2020
Instrument
Average
Volume Per
Weighted
Average
Day
(barrels)
Price
($/barrel)
Fair Value
Asset
Liability
Swaps-WTI
Swaps-LLS
Swaps-WTI
Swaps-LLS
Swaps-WTI
Swaps-LLS
Swaps-WTI
Swaps-LLS
Swaps-WTI
Swaps-WTI
Swaps-WTI
Swaps-WTI
63
6,446 $
5,000 $
6,421 $
5,000 $
6,397 $
5,000 $
6,398 $
5,000 $
6,000 $
6,000 $
6,000 $
6,000 $
54.46 $
59.17
54.48
59.17
54.50
59.17
54.50
59.17
54.09
54.09
54.09
54.09
4,959 $
3,684
4,307
3,203
3,821
3,092
3,498
3,015
2,807
2,609
2,450
2,234
—
—
—
—
—
—
—
—
—
—
—
—
The following table illustrates the estimated impact on the fair values of our derivative financial instruments and operating income
attributable to hypothetical changes in the underlying commodity prices. This illustration assumes that crude oil volumes remain constant at
anticipated levels. The estimated changes in operating income exclude potential cash receipts or payments in settling outstanding derivative
positions.
Change of $10.00 per Barrel of Crude Oil
($ in millions)
Effect on the fair value of crude oil derivatives
Effect on 2019 operating income, excluding crude oil derivatives 1
_____________________________________________
1 Based on our 2019 Business Plan consistent with the assumptions used to determine our proved reserves as disclosed in Item 2, “Properties – Summary of Oil and Gas
(62.1 ) $
55.0 $
$
$
Increase
Decrease
62.1
(55.0 )
Reserves.”
64
Item 8 Financial Statements and Supplementary
Data
PENN VIRGINIA CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Shareholders’ Equity
Notes to Consolidated Financial Statements:
1. Nature of Operations
2. Basis of Presentation
3. Summary of Significant Accounting Policies
4. Bankruptcy Proceedings, Emergence and Fresh Start Accounting
5. Acquisitions and Divestitures
6. Accounts Receivable and Major Customers
7. Derivative Instruments
8. Property and Equipment
9. Asset Retirement Obligations
10. Long-Term Debt
11. Income Taxes
12. Executive Retirement and Exit Activities
13. Additional Balance Sheet Detail
14. Fair Value Measurements
15. Commitments and Contingencies
16. Shareholders’ Equity
17. Share-Based Compensation and Other Benefit Plans
18. Interest Expense
19. Earnings per Share
Supplemental Quarterly Financial Information (unaudited)
Supplemental Information on Oil and Gas Producing Activities (unaudited)
65
Page
66
68
69
70
71
72
73
73
75
78
84
86
87
89
89
90
92
94
95
95
97
98
98
101
101
102
103
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Penn Virginia Corporation
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Penn Virginia Corporation (a Virginia corporation) and subsidiaries (the
“Company”) as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income (loss), shareholders’
equity, and cash flows for each of the two years in the period ended December 31, 2018 (Successor) and for the period from September 13, 2016
through December 31, 2016 (Successor) and the period from January 1, 2016 through September 12, 2016 (Predecessor), and the related notes
(collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the
financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the two
years in the period ended December 31, 2018 (Successor) and the period from September 13, 2016 through December 31, 2016 (Successor) and
the period from January 1, 2016 through September 12, 2016 (Predecessor), in conformity with accounting principles generally accepted in the
United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the
Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated
February 27, 2019 expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s
financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and
Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits
included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for
our opinion.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2016.
Houston, Texas
February 27, 2019
66
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Penn Virginia Corporation
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Penn Virginia Corporation (a Virginia corporation) and subsidiaries (the
“Company”) as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-
Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the
consolidated financial statements of the Company as of and for the year ended December 31, 2018, and our report dated February 27, 2019
expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with
the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a
reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A
company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance
that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Houston, Texas
February 27, 2019
67
PENN VIRGINIA CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Successor
Predecessor
September 13, Through
January 1, Through
Year Ended December 31,
December 31,
September 12,
2018
2017
2016
2016
Revenues
Crude oil
Natural gas liquids
Natural gas
Gain (loss) on sales of assets, net
Other revenues, net
Total revenues
Operating expenses
Lease operating
Gathering, processing and transportation
Production and ad valorem taxes
General and administrative
Exploration
Depreciation, depletion and amortization
Total operating expenses
Operating income (loss)
Other income (expense)
Interest expense, net of amounts capitalized
Derivatives
Other, net
Reorganization items, net
Income (loss) before income taxes
Income tax (expense) benefit
Net income (loss)
Preferred stock dividends
Net income (loss) attributable to common
shareholders
Net income (loss) per share:
Basic
Diluted
Weighted average shares outstanding – basic
Weighted average shares outstanding – diluted
$
$
$
$
402,485 $
21,073
15,972
(177)
1,479
440,832
35,879
18,626
23,547
26,064
—
127,961
232,077
208,755
(26,462 )
37,427
2,266
3,322
225,308
(523)
224,785
—
140,886 $
10,066
8,517
(36 )
621
160,054
21,784
10,734
8,814
18,201
—
48,649
108,182
51,872
(6,392)
(17,819 )
58
—
27,719
4,943
32,662
—
33,157 $
2,707
2,790
(49 )
398
39,003
5,331
3,043
2,498
5,066
—
11,652
27,590
11,413
(879 )
(16,622 )
792
—
(5,296 )
—
(5,296 )
—
81,377
6,064
6,208
1,261
(600 )
94,310
15,626
13,235
3,490
38,956
10,288
33,582
115,177
(20,867 )
(58,018 )
(8,333 )
(3,173 )
1,144,993
1,054,602
—
1,054,602
(5,972 )
224,785 $
32,662 $
(5,296 ) $
1,048,630
14.93 $
14.70 $
15,059
15,292
2.18 $
2.17 $
14,996
15,063
(0.35 ) $
(0.35 ) $
14,992
14,992
11.91
8.50
88,013
124,087
See accompanying notes to consolidated financial statements.
68
PENN VIRGINIA CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Successor
Predecessor
September 13 Through
January 1 Through
Year Ended December 31,
December 31,
September 12,
2018
2017
2016
2016
$
224,785 $
32,662 $
(5,296 ) $
1,054,602
Net income (loss)
Other comprehensive income (loss):
Change in pension and postretirement
obligations, net of tax of $0 for 2018 and 2017,
$39 for the Successor period from September 13,
2016 through December 31, 2016 and $(226) for
the Predecessor period from January 1, 2016
through September 12, 2016.
Comprehensive income (loss)
$
224,867 $
82
82
(73 )
(73 )
32,589 $
73
73
(5,223 ) $
(421 )
(421 )
1,054,181
See accompanying notes to consolidated financial statements.
69
PENN VIRGINIA CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
December 31,
2018
2017
Assets
Current assets
Cash and cash equivalents
Accounts receivable, net of allowance for doubtful accounts
Derivative assets
Income taxes receivable
Other current assets
Total current assets
Property and equipment, net
Derivative assets
Deferred income taxes
Other assets
Total assets
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities
Derivative liabilities
Total current liabilities
Other liabilities
Derivative liabilities
Long-term debt
Commitments and contingencies (Note 15)
Shareholders’ equity:
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued
Common stock of $0.01 par value – 45,000,000 shares authorized; 15,080,594 and 15,018,870
shares issued as of December 31, 2018 and December 31, 2017, respectively
Paid-in capital
Retained earnings
Accumulated other comprehensive income
Total shareholders’ equity
Total liabilities and shareholders’ equity
$
$
$
$
17,864 $
66,038
34,932
2,471
5,125
126,430
927,994
10,100
1,949
2,481
1,068,954 $
103,700 $
991
104,691
5,533
—
511,375
—
151
197,630
249,492
82
447,355
1,068,954 $
11,017
69,821
—
—
6,250
87,088
529,059
—
4,943
8,507
629,597
96,181
27,777
123,958
4,833
13,900
265,267
—
150
194,123
27,366
—
221,639
629,597
See accompanying notes to consolidated financial statements.
70
PENN VIRGINIA CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Successor
Predecessor
September 13 Through
January 1 Through
Year Ended December 31,
December 31,
September 12,
2018
2017
2016
2016
$
224,785 $
32,662 $
(5,296 ) $
1,054,602
Cash flows from operating activities
Net income (loss)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Non-cash reorganization items
Depreciation, depletion and amortization
Accretion of firm transportation obligation
Derivative contracts:
Net (gains) losses
Cash settlements, net
Deferred income tax expense (benefit)
Loss (gain) on sales of assets, net
Non-cash exploration expense
Non-cash interest expense
Share-based compensation (equity-classified)
Other, net
Changes in operating assets and liabilities:
Accounts receivable, net
Accounts payable and accrued expenses
Other assets and liabilities
Net cash provided by operating activities
Cash flows from investing activities
Acquisitions, net
Capital expenditures
Proceeds from sales of assets, net
Other, net
Net cash used in investing activities
Cash flows from financing activities
Proceeds from credit facility borrowings
Repayment of credit facility borrowings
Proceeds from second line note
Debt issuance costs paid
Proceeds received from rights offering, net
Other, net
Net cash provided by (used in) financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents - beginning of period
Cash and cash equivalents - end of period
Supplemental disclosures:
Cash paid for interest (net of amounts capitalized)
Cash paid for income taxes (net of refunds)
Cash paid for reorganization items, net
Non-cash investing and financing activities:
Common stock issued in exchange for liabilities
Changes in accrued liabilities related to capital
expenditures
Derivatives settled to reduce outstanding debt
$
$
$
$
$
$
$
(3,322 )
127,961
—
(37,427 )
(48,291 )
2,994
177
—
3,416
4,618
44
(23,674 )
21,109
(258)
272,132
(85,387 )
(430,592 )
7,683
—
(508,296 )
244,000
—
—
(989)
—
—
243,011
6,847
11,017
17,864 $
22,599 $
— $
540 $
— $
44 $
— $
—
48,649
—
17,819
(3,511 )
(4,943 )
36
—
2,122
3,809
61
(43,318 )
28,542
(218)
81,710
(200,849 )
(115,687 )
869
—
(315,667 )
59,000
(7,000 )
196,000
(9,787 )
55
(55)
238,213
4,256
6,761
11,017 $
4,102 $
— $
954 $
— $
19,910 $
— $
—
11,652
—
16,622
384
—
49
—
226
81
21
10,791
(3,887 )
131
30,774
—
(4,812 )
—
(104 )
(4,916 )
—
(50,350 )
—
—
—
(161 )
(50,511 )
(24,653 )
31,414
6,761
$
598
$
(7 ) $
$
525
— $
$
997
— $
(1,178,302 )
33,582
317
8,333
48,008
—
(1,261 )
6,038
22,189
1,511
(13 )
12,273
22,469
501
30,247
—
(15,359 )
224
1,186
(13,949 )
75,350
(119,121 )
—
(3,011 )
49,943
—
3,161
19,459
11,955
31,414
4,331
(35 )
30,990
140,952
(11,301 )
51,979
See accompanying notes to consolidated financial statements.
71
Balance as of December 31, 2015
(Predecessor)
Net income
Share-based compensation
All other changes
Balance, September 12, 2016
(Predecessor)
Cancellation of Predecessor equity
Balance, September 12, 2016
(Predecessor)
Issuance of Successor common stock -
Rights Offering
Issuance of Successor common stock -
Backstop Fee
Issuance of Successor common stock -
exchange of claims
Balance, September 12, 2016 (Successor)
Net loss
Share-based compensation
All other changes
473
6,885
14,992
—
—
—
Balance as of December 31, 2016
14,992
Net income
Share-based compensation
Restricted stock unit vesting
All other changes
—
—
27
—
Balance as of December 31, 2017
15,019
Net income
Share-based compensation
Restricted stock unit vesting
Cumulative effect of change in accounting
principle (see Note 6)
All other changes
—
—
61
—
—
Balance as of December 31, 2018
15,080
$
PENN VIRGINIA CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in thousands)
Common
Shares
Outstanding
Preferred
Stock
Common
Stock
Paid-in
Capital
Retained
Earnings
(Accumulated
Deficit)
Deferred
Compensation
Obligation
Accumulated
Other
Comprehensive
Income (Loss)
Treasury
Stock
Total
Shareholders’
Equity (Deficit)
1,211,088
(2,130,271 )
3,440
—
1,054,602
81,253
—
—
6,965
3,146
—
—
(1,266 )
628
—
—
69
1,511
1,198
88,218
(88,218 )
1,880
(1,880 )
697
(697 )
1,213,797
(1,213,797 )
—
—
(1,075,669 )
1,075,669
—
—
—
3,440
(3,440 )
422
—
—
(39 )
383
(383 )
(3,574 )
—
—
—
(3,574 )
(915,121 )
1,054,602
1,511
(38 )
140,954
3,574
(140,954 )
— $
— $
— $
— $
— $
— $
— $
— $
—
7,634
$
— $
76
$
49,867
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $
5
69
150
—
—
—
150
—
—
—
—
150
—
—
1
—
—
9,054
131,824
190,745
—
81
(205 )
190,621
—
3,809
(351 )
44
194,123
—
4,618
(1,111 )
—
—
— $
—
—
—
(5,296 )
—
—
(5,296 )
32,662
—
—
—
27,366
224,785
—
—
(2,659 )
—
— $
— $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
73
73
—
—
—
(73 )
—
—
—
—
—
82
82
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $
49,943
9,059
131,893
190,895
(5,296 )
81
(132 )
185,548
32,662
3,809
(351 )
(29 )
221,639
224,785
4,618
(1,110 )
(2,659 )
82
447,355
151
$
197,630
$
249,492
$
See accompanying notes to consolidated financial statements.
72
PENN VIRGINIA CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except per share amounts or where otherwise indicated)
1. Nature of
Operations
Penn Virginia Corporation (together with its consolidated subsidiaries unless the context otherwise requires, “Penn Virginia,” the
“Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the onshore exploration, development and production of
oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist primarily of drilling unconventional horizontal development
wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in Gonzales, Lavaca, Fayette and DeWitt Counties in South
Texas.
On October 28, 2018, Denbury Resources Inc. (“Denbury”) and Penn Virginia announced that they entered into a definitive merger
agreement (the “Merger Agreement”) pursuant to which Denbury will acquire Penn Virginia (the “Merger”). The consideration to be paid to
Penn Virginia shareholders will consist of 12.4 shares of Denbury common stock and $25.86 of cash for each share of Penn Virginia common
stock. Penn Virginia shareholders will be permitted to elect to receive either all cash, all stock or a mix of stock and cash, in each case subject to
proration, which will result in the aggregate issuance by Denbury of approximately 191.667 million Denbury shares and payment by Denbury of
$400 million in cash. The transaction was unanimously approved by the board of directors of each company, and certain Penn Virginia
shareholders holding approximately 15 percent of the outstanding shares signed voting agreements to vote “for” the transaction. The transaction
is subject to the approval by the holders of more than two-thirds of the outstanding Company common shares, the approval by the holders of a
majority of the outstanding Denbury common shares of an amendment to the certificate of incorporation to increase the number of authorized
Denbury common shares, the approval of the issuance of Denbury common shares in the Merger by the holders of a majority of the Denbury
common shares represented in person or by proxy at a meeting of Denbury shareholders held to vote on such matter and other customary
closing conditions. The special meeting of shareholders to approve the merger is anticipated in April 2019 and closing is anticipated soon
thereafter, subject to shareholder approval and certain other conditions. The Merger Agreement contains certain termination rights for both
Denbury and the Company, including if the Merger is not consummated by April 30, 2019, and requires Penn Virginia to pay a $45 million
termination fee in certain circumstances.
2. Basis of
Presentation
Comparability of Financial Statements to Prior Periods
As described in further detail in Note 4 below, we have adopted and applied the relevant guidance provided in accounting principles
generally accepted in the United States of America (“GAAP”) with respect to the accounting and financial statement disclosures for entities that
have emerged from bankruptcy proceedings (“Fresh Start Accounting”). Accordingly, our Consolidated Financial Statements and Notes after
September 12, 2016, are not comparable to the Consolidated Financial Statements and Notes through that date. To facilitate our financial
statement presentations, we refer to the reorganized company in these Consolidated Financial Statements and Notes as the “Successor” for
periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. Furthermore, our Consolidated
Financial Statements and Notes have been presented with a “black line” division to delineate the lack of comparability between the Predecessor
and Successor. In addition, we have adopted the full cost method of accounting for our oil and gas properties effective with our adoption of
Fresh Start Accounting. Accordingly, our results of operations and financial position for the Successor periods will be substantially different
from our historic trends.
We have applied the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities
that have filed petitions with the bankruptcy court and expect to reorganize as going concerns in preparing our Consolidated Financial
Statements and Notes through the period ended September 12, 2016, or Predecessor periods. That guidance requires that, for periods subsequent
to our bankruptcy filing on May 12, 2016, or post-petition periods, certain transactions and events that were directly related to our
reorganization be distinguished from our normal business operations. Accordingly, certain revenues, expenses, realized gains and losses and
provisions that were realized or incurred in connection with the bankruptcy proceedings have been included in “Reorganization items, net” in
our Consolidated Statement of Operations for the period ended September 12, 2016. In addition, certain liabilities and other obligations incurred
prior to May 12, 2016, or pre-petition periods, have been classified in “Liabilities subject to compromise” on our Predecessor Consolidated
Balance Sheet through September 12, 2016. Further detail for our “Reorganization items, net” and “Liabilities subject to compromise” are
provided in Note 4 below.
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Going Concern Presumption
Our Consolidated Financial Statements for the Successor periods have been prepared on a going concern basis, which contemplates the
realization of assets and the satisfaction of liabilities and other commitments in the normal course of business.
Subsequent Events
Management has evaluated all of our activities through the issuance date of our Consolidated Financial Statements and has concluded that
no subsequent events have occurred that would require recognition in our Consolidated Financial Statements or disclosure in the Notes thereto.
Adoption of Recently Issued Accounting Pronouncements
Effective January 1, 2018, we adopted and began applying the relevant guidance provided in Accounting Standards Update (“ASU”)
2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”). ASU
2017–07 requires employers to disaggregate the service cost component from the other components of net periodic benefit cost. The service cost
component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the
pertinent employees during the period, except for amounts capitalized. All other components of net periodic benefit cost shall be presented
outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if
the other components are not presented in a separate line item or items. ASU 2017–07 is applicable to our legacy retiree benefit plans which
cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current
employees, but rather there are interest and other costs associated with the legacy obligations. As required, ASU 2017–07 has been applied
retrospectively to periods prior to 2018. Accordingly, the entirety of the expense associated with these plans, which was less than $0.1 million,
has been included as a component of the “Other income (expense)” caption in our Consolidated Statements of Operations for all periods
presented. Prior to 2018, all costs associated with these plans were included in the “General and administrative” (“G&A”) expenses caption.
Effective January 1, 2018, we adopted and began applying the relevant guidance provided in ASU 2014–09, Revenues from Contracts
with Customers (“ASU 2014–09”) and related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards
Codification (“ASC”) Topic 606, Revenues from Contracts with Customers (“ASC Topic 606”). We adopted ASC Topic 606 using the
cumulative effect transition method (see Note 6 for the impact and disclosures associated with the adoption of ASC Topic 606).
Recently Issued Accounting Pronouncements Pending Adoption
In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016–13, Measurement of Credit Losses on Financial
Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable,
loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by
January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which
considers current information and events and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected
loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii)
considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have
applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher
credit risk than those associated with our traditional customer receivables. At this time, we do not anticipate that the adoption of ASU 2016–13
will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are continuing to evaluate the
requirements and the period for which we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique
to our industry.
In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to
recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve
months. Together with recent related amendments to GAAP, ASU 2016–02 represents ASC Topic 842, Leases (“ASC Topic 842”) which
supersedes all current GAAP with respect to leases. The recognition, measurement and presentation of expenses and cash flows arising from a
lease by a lessee primarily will depend on its classification as a finance or operating lease. ASC Topic 842 also will require disclosures
regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASC Topic 842 is January 1, 2019, with
early adoption permitted.
ASC Topic 842 will be applicable to our existing leases for office facilities and certain office equipment, certain field equipment, land
easements and similar arrangements for rights-of-way, certain gas gathering and gas lift assets and potentially to certain drilling rig contracts
with terms in excess of 12 months, to the extent we may have such contracts in the future. We are finalizing our evaluation of the impact that
the adoption may have on certain crude oil gathering arrangements.
74
We will adopt ASC Topic 842 effective January 1, 2019 using the modified retrospective method with a cumulative effect charge to the
beginning balance of retained earnings that is not anticipated to be material. We anticipate recognizing total right-of-use assets and lease of
obligations of approximately $3 million, excluding any potential impact attributable to our crude oil gathering arrangements. All of the leases
for which we are recognizing assets and liabilities will be classified as operating leases. We also have identified certain contractual
arrangements that will be classified as variable leases. We plan to adopt certain practical expedients provided for in ASC Topic 842 including (i)
those associated with the reassessment and classification of existing leases, (ii) land easements and (iii) an election to not separate lease and non-
lease components. We also plan to make an accounting policy election, effective January 1, 2019, whereby any leases with terms of one year or
less will be formally classified as short-term leases.
3. Summary of Significant Accounting
Policies
Principles of Consolidation
Our Consolidated Financial Statements include the accounts of Penn Virginia and all of its subsidiaries. Intercompany balances and
transactions have been eliminated.
Use of Estimates
Preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities in our Consolidated Financial Statements and the reported amounts of revenues and
expenses during the reporting period. Such estimates include certain asset and liability valuations as further described in these Notes. Actual
results could differ from those estimates.
Cash and Cash Equivalents
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Derivative Instruments
From time to time, we utilize derivative instruments to mitigate our financial exposure to commodity price and interest rate volatility. The
derivative instruments, which are placed with financial institutions that we believe are of acceptable credit risk, generally take the form of
collars and swaps. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of
directors.
All derivative instruments are recognized in our Consolidated Financial Statements at fair value. The fair values of our derivative
instruments are determined based on discounted cash flows derived from quoted forward prices. Our derivative instruments are not formally
designated as hedges. We recognize changes in fair value in earnings currently as a component of the Derivatives caption in our Consolidated
Statements of Operations. We have experienced and could continue to experience significant changes in the amount of derivative gains or losses
recognized due to fluctuations in the value of these commodity derivative contracts, which fluctuate with changes in commodity prices and
interest rates.
Oil and Gas Properties
We apply the full cost method of accounting for our oil and gas properties which we adopted effective with our adoption of Fresh Start
Accounting. Under this method, all productive and nonproductive costs incurred in the exploration, development and acquisition of oil and gas
reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions,
geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to
exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general
corporate overhead or similar activities are also capitalized. Future development costs are estimated on a property-by-property basis based on
current economic conditions and are amortized as a component of depreciation, depletion and amortization (“DD&A”).
Unproved properties not being amortized include unevaluated leasehold costs and associated capitalized interest. These costs are
reviewed quarterly to determine whether or not and to what extent proved reserves have been assigned to a property or if an impairment has
occurred due to lease expirations, general economic conditions and other factors, in which case the related costs along with associated
capitalized interest are reclassified to the proved oil and gas properties subject to DD&A.
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 discounted future net revenues from proved properties adjusted for costs excluded from amortization and related
income taxes (a “Ceiling Test”). The estimated 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.
75
For the periods prior to the Emergence Date, we applied the successful efforts method of accounting for our oil and gas properties. Under
this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs were capitalized. Seismic costs,
delay rentals and costs to drill exploratory wells that did not find proved reserves were expensed as oil and gas exploration. We carried the costs
of exploratory wells as assets if the wells had found a sufficient quantity of reserves to justify its completion as a producing well and as long as
we were making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain projects, it may
have taken us more than one year to evaluate the future potential of the exploratory well and make determinations of their economic viability.
Our ability to move forward on projects was dependent on gaining access to transportation or processing facilities or obtaining permits and
government or partner approval, the timing of which was beyond our control. In such cases, exploratory well costs remained suspended as long
as we were actively pursuing access to the necessary facilities or receiving such permits and approvals and believed that they would be obtained.
We assessed the status of suspended exploratory well costs on a quarterly basis.
Depreciation, Depletion and Amortization
DD&A of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the
unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing
the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the
period.
DD&A of our proved properties while we applied the successful efforts method during the Predecessor periods was computed using the
units-of-production method. Historically, we adjusted our depletion rate throughout the year as new data became available.
Other Property and Equipment
Other property and equipment consists primarily of gathering systems and related support equipment. Property and equipment are carried
at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Maintenance and repair
costs are charged to expense as incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized.
We compute depreciation and amortization of property and equipment using the straight-line balance method over the estimated useful
life of each asset as follows: Gathering systems – fifteen to twenty years and Other property and equipment – three to twenty years.
Impairment of Long-Lived Assets
While we applied the successful efforts method of accounting for our oil and gas properties during the Predecessor periods, we reviewed
our assets for impairment when events or circumstances indicated a possible decline in the recoverability of the carrying value of the properties.
If the carrying value of the asset was determined to be impaired, we reduced the asset to its fair value. Fair value may have been estimated using
comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash
flows were based on management’s expectations for the future and included estimates of future production, commodity prices based on
published forward commodity price curves as of the date of the estimate, operating and development costs, intent to develop properties and a
risk-adjusted discount rate.
We reviewed oil and gas properties for impairment periodically when events and circumstances indicated a decline in the recoverability
of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. We estimated the
future cash flows expected in connection with the properties and compared such future cash flows to the carrying amounts of the properties to
determine if the carrying amounts were recoverable. Performing the impairment evaluations required use of judgments and estimates since the
results were dependent on future events. Such events included estimates of proved and unproved reserves, future commodity prices, the timing
of future production, capital expenditures and intent to develop properties, among others.
The costs of unproved leaseholds, including associated interest costs for the period activities were in progress to bring projects to their
intended use, were capitalized pending the results of exploration efforts. Unproved properties whose acquisition costs were insignificant to total
oil and gas properties were amortized in the aggregate over the lesser of five years or the average remaining lease term and the amortization was
charged to exploration expense. We assessed unproved properties whose acquisition costs were relatively significant, if any, for impairment on a
stand-alone basis. As exploration work progressed and the reserves on properties were proved, capitalized costs of these properties became
subject to depreciation and depletion. If the exploration work was unsuccessful, the capitalized costs of the properties related to the unsuccessful
work was charged to exploration expense. The timing of any write-downs of any significant unproved properties depended upon the nature,
timing and extent of future exploration and development activities and their results.
76
Asset Retirement Obligations
We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Associated asset
retirement costs are capitalized as part of the carrying cost of the asset. Our AROs relate to the plugging and abandonment of oil and gas wells
and the associated asset is recorded as a component of oil and gas properties. After recording these amounts, the ARO is accreted to its future
estimated value, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion of the ARO and the
depreciation of the related long-lived assets are included in the DD&A expense caption in our Consolidated Statements of Operations.
Income Taxes
We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the
Company’s financial statements or tax returns. Using this method, deferred tax assets and liabilities are determined based on the difference
between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates. In assessing our deferred tax
assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The
ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and
our ability to utilize tax credits and operating loss carryforwards during the periods in which the temporary differences become deductible. We
also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies. We recognize interest attributable to income
taxes, to the extent they arise, as a component of interest expense and penalties as a component of income tax expense.
We are subject to ongoing tax examinations in numerous domestic jurisdictions. Accordingly, we may record incremental tax expense
based upon the more-likely-than-not outcomes of uncertain tax positions. In addition, when applicable, we adjust the previously recorded tax
expense to reflect examination results when the position is effectively settled. Our ongoing assessments of the more-likely-than-not outcomes of
the examinations and related tax positions require judgment and can increase or decrease our effective tax rate, as well as impact our operating
results. The specific timing of when the resolution of each tax position will be reached is uncertain.
Revenue Recognition and Associated Costs
Crude oil. We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point,
including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the
customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a
market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs
incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of GPT expense.
NGLs. We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our
midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are
owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third-party customer.
Depending upon the nature of the contractual arrangements with the midstream processing vendors, particularly those attributable to the
marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have
determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated
processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing
vendor is our customer, we recognize NGL product revenues based on a net basis with processing costs presented as a reduction of revenue.
Based on an analysis of all of our existing natural gas processing contracts, we have determined that, as of January 1, 2018, and through
December 31, 2018, we were the agent and our midstream processing vendors were our customers with respect to all of our NGL product sales.
Natural gas. Subsequent to the aforementioned processing of “wet” natural gas and the separation of NGL products, the “dry” or residue
gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom
are interstate pipelines. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of
loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location
differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are
recognized as a component of GPT expenses.
Marketing services. We provide marketing services to certain of our joint venture partners and other third parties with respect to oil and
gas production for which we are the operator. Pricing for such services represents a negotiated fixed rate fee based on the sales price of the
underlying oil and gas products. Production attributable to joint venture partners from wells that we operate that are not subject to marketing
agreements are delivered in kind. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers.
Direct costs associated with our marketing efforts are included in G&A expenses.
77
Share-Based Compensation
Our stock compensation plans permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units,
restricted stock and restricted stock units to our employees and directors. We measure the cost of employee services received in exchange for an
award of equity-classified instruments based on the grant-date fair value of the award. Compensation cost associated with the liability-classified
awards is measured at the end of each reporting period and recognized based on the period of time that has elapsed during the applicable
performance period.
4. Bankruptcy Proceedings, Emergence and Fresh Start
Accounting
Bankruptcy Proceedings and Emergence
On May 12, 2016 (the “Petition Date”), we and eight of our subsidiaries (the “Chapter 11 Subsidiaries”) filed voluntary petitions ( In re
Penn Virginia Corporation, et al., Case No. 16-32395) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code (the
“Bankruptcy Code”) in the United States Bankruptcy Court for the Eastern District of Virginia (the “Bankruptcy Court”).
On August 11, 2016 (the “Confirmation Date”), the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of
Reorganization of Penn Virginia Corporation and its Debtor Affiliates (the “Plan”), and we subsequently emerged from bankruptcy on
September 12, 2016 (the “Emergence Date”).
On November 20, 2018, the Bankruptcy Court issued a final decree to close the case.
Debtors-In-Possession. From the Petition Date through the Emergence Date, we and the Chapter 11 Subsidiaries operated our business
as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all “first day”
motions filed by us and the Chapter 11 Subsidiaries, which were designed primarily to minimize the impact of the bankruptcy proceedings on
our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to
conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have
paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition
amounts owed to certain lienholders, amounts due to taxing authorities for production and other related taxes and funds belonging to third
parties, including royalty and working interest holders.
Pre-Petition Agreements. Immediately prior to the Petition Date, the holders (the “Ad Hoc Committee”) of approximately 86 percent of
the $1,075 million principal amount of our 7.25% Senior Notes due 2019 (the “2019 Senior Notes”) and 8.50% Senior Notes due 2020 (the
“2020 Senior Notes” and, together with the 2019 Senior Notes, the “Senior Notes”) agreed to a restructuring support agreement (the “RSA”) that
set forth the general framework of the Plan and the timeline for the bankruptcy proceedings. In addition, we entered into a backstop commitment
agreement (the “Backstop Commitment Agreement”) with the parties thereto (collectively, the “Backstop Parties”), pursuant to which the
Backstop Parties committed to provide a $50 million commitment to backstop a rights offering (the “Rights Offering”) that was conducted in
connection with the Plan.
Plan of Reorganization. Pursuant to the terms of the Plan, which was supported by us, the holders (the “RBL Lenders”) of 100 percent
of the claims attributable to our pre-petition credit agreement (as amended, the “RBL”), the Ad Hoc Committee and the Official Committee of
Unsecured Claimholders (the “UCC”), the following transactions were completed subsequent to the Confirmation Date and prior to or at the
Emergence Date:
•
•
•
•
•
•
the approximately $1,122 million of indebtedness, including accrued interest, attributable to our Senior Notes and certain other
unsecured claims were exchanged for 6,069,074 shares representing 41 percent of the Successor’s common stock (“Successor Common
Stock”);
a total of $50 million of proceeds were received on the Emergence Date from the Rights Offering resulting in the issuance of 7,633,588
shares representing 51 percent of Successor Common Stock to holders of claims arising under the Senior Notes, certain holders of
general unsecured claims and to the Backstop Parties;
the Backstop Parties received a backstop fee comprised of 472,902 shares representing three percent of Successor Common
Stock;
an additional 816,454 shares representing five percent of Successor Common Stock were authorized for disputed general unsecured
claims and non-accredited investor holders of the Senior Notes and subsequently, 749,600 shares of Successor Common Stock were
reserved for issuance under a new management incentive plan;
on the Emergence Date, we entered into a shareholders agreement and a registration rights agreement and amended our articles of
incorporation and bylaws for the authorization of the Successor Common Stock and to provide customary registration rights thereunder,
among other corporate governance actions;
holders of claims arising under the RBL were paid in full from cash on hand, $75.4 million from borrowings under a new credit
agreement (the “Credit Facility”) (see Note 10 below) and proceeds from the Rights Offering;
78
•
•
•
•
•
•
•
the debtor-in-possession credit facility (the “DIP Facility”), under which there were no outstanding borrowings at any time from the
Petition Date through the Emergence Date, was canceled and less than $0.1 million in fees were paid in full in cash;
certain other priority claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claim-
holders;
a cash reserve of $2.7 million was established for certain other secured, priority or convenience claims pending resolution as of the
Emergence Date;
an escrow account for professional service fees attributable to our advisers and those of the UCC was funded by us with cash of $14.6
million, and we paid $7.2 million for professional fees and expenses on behalf of the RBL Lenders, the Ad Hoc Committee and the
indenture trustee for the Senior Notes;
on the Emergence Date, our previous interim Chief Executive Officer, Edward B. Cloues, resigned and each member of our board of
directors resigned and was replaced by new board members;
our Predecessor preferred stock and common stock was canceled, extinguished and discharged;
and
all of our Predecessor share-based compensation plans and supplemental employee retirement plan (the “SERP”) entitlements were
canceled.
Fresh Start Accounting
We adopted Fresh Start Accounting on the Emergence Date in connection with our emergence from bankruptcy. As referenced below,
our reorganization value of $334.0 million, immediately prior to emergence was substantially less than our post-petition liabilities and allowed
claims. Furthermore and in connection with our reorganization, we experienced a change in control as the outstanding common and preferred
shares of the Predecessor were canceled and substantially all of the Successor Common Stock was issued to the Predecessor’s creditors,
primarily former holders of our Senior Notes. Accordingly, the holders of the Predecessor’s common and preferred shares effectively received
no shares of the Successor. The adoption of Fresh Start Accounting results in a new reporting entity, the Successor, for financial reporting
purposes. The presentation is analogous to that of a new business entity such that the Successor is presented with no beginning retained earnings
or deficit on the Emergence Date.
Reorganization Value
Reorganization value represents the fair value of the Successor’s total assets prior to the consideration of liabilities and is intended to
approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value, which was derived
from the Successor’s enterprise value, was allocated to our individual assets based on their estimated fair values.
Enterprise value represents the estimated fair value of an entity’s long term debt and shareholders’ equity. The Successor’s enterprise
value, as approved by the Bankruptcy Court in support of the Plan, was estimated to be within a range of $218 million to $382 million with a
mid-point value of $300 million. Based on the estimates and assumptions utilized in our Fresh Start Accounting process, we estimated the
Successor’s enterprise value to be approximately $266.2 million after the consideration of cash and cash equivalents on hand at the Emergence
Date.
The following table reconciles the enterprise value, net of cash and cash equivalents, to the estimated fair value of our Successor
Common Stock as of the Emergence Date:
Enterprise value
Plus: Cash and cash equivalents
Less: Fair value of debt
Fair value of Successor Common Stock
Shares outstanding as of September 12, 2016
Per share value
$
$
$
234,831
31,414
(75,350 )
190,895
14,992,018
12.73
The following table reconciles the enterprise value to the reorganization value of our Successor assets as of the Emergence Date:
Enterprise value
Plus: Cash and cash equivalents
Plus: Current liabilities
Plus: Noncurrent liabilities excluding long-term debt
Reorganization value
79
$
$
234,831
31,414
54,171
13,558
333,974
Valuation Process
Our valuation analysis was prepared with the assistance of an independent third-party consultant utilizing reserve information prepared
by our independent reserve engineers, internal development plans and schedules, other internal financial information and projections and the
application of standard valuation techniques including risked net asset value analysis and comparable public company metrics. Because many of
the inputs utilized in the valuation process are not observable, we have classified the Fresh Start fair value measurements as Level 3 inputs as
that term is defined in GAAP.
Our principal assets include the Successor’s oil and gas properties. We determined the fair value of our oil and gas properties based on
the discounted cash flows expected to be generated from these assets. Our analyses were based on market conditions and reserves in place as
confirmed by our independent petroleum engineers. The proved reserves were segregated into various geographic regions, including sub-regions
within the Eagle Ford where a substantial portion of our assets are located, for which separate risk factors were determined based on geological
characteristics. Due to the limited drilling plans that we had in place, proved undeveloped locations were risked accordingly. Future cash flows
were estimated by using New York Mercantile Exchange (“NYMEX”) forward prices for West Texas Intermediate (“WTI”) crude oil and
Henry Hub natural gas with inflation adjustments applied to periods beyond a five-year horizon. These prices were adjusted for differentials
realized by us for location and product quality. Gathering and transportation costs were estimated based on agreements that we had in place and
development and operating costs were based on our most recent experience and adjusted for inflation in future years. The risk-adjusted after-tax
cash flows were discounted at a rate of 13.5%. This rate was determined from a weighted-average cost of capital computation which utilized a
blended expected cost of debt and expected returns on equity for similar industry participants. Plugging and abandonment costs were also
identified and measured in this process in order to determine the fair value of the Successor’s AROs attributable to our proved developed
reserves on the Emergence Date. Based on this valuation process, we determined fair values of $121.9 million for our proved reserves and $2.7
million for the related AROs.
With respect to the valuation of our undeveloped acreage, we segregated our current lease holdings in the Eagle Ford into prospect
regions in which we had significant developed acreage and those in which we had not yet initiated any significant drilling activity. For those
prospects within previously developed regions, we applied a multiple based on recent transactions involving acreage deemed comparable to our
acreage for each targeted formation. Based on this valuation process, we determined a fair value of $92.5 million for our undeveloped acreage
within previously developed regions of the Eagle Ford. For those lease holdings in other areas of the Eagle Ford, we disregarded those prospects
for which lease expirations were to occur during 2016 as well as those for which future drilling was considered uneconomical at then current
commodity prices. A reduced multiple was then applied to this adjusted undeveloped acreage consistent with recent transactions for acreage
deemed comparable to our acreage resulting in a fair value of $8.3 million. We attributed no value to our limited undeveloped lease holdings in
all areas other than the Eagle Ford.
Our remaining equipment and other fixed assets were valued at $ 26.7 million primarily using a cost approach that incorporated
depreciation and obsolescence to the extent applicable on an asset-by-asset basis. The most significant of these assets is our water facility in
South Texas which is integral to our regional operations. Accordingly, this asset, for which we determined a fair value of $23.4 million, is
included in our full cost pool for purposes of determining our DD&A attributable to our oil and gas production. Certain assets, particularly
personal property including office equipment and vehicles, among others, were valued based on market data for comparable assets to the extent
such information was available.
The remaining reorganization value is attributable to certain natural gas imbalance receivables, cash and cash equivalents, working capital
assets including accounts receivable, prepaid items, current derivative assets and debt issuance costs. Our natural gas imbalance receivables,
which are fully attributable to our Mid-Continent operations in the Granite Wash, were valued using NYMEX spot prices for Henry Hub natural
gas adjusted for basis differentials for transportation. Our accounts receivable, including amounts receivable from our joint venture partners,
were subjected to analysis on an individual basis and reserved to the extent we believe was appropriate. Collectively, these remaining assets,
including our current derivative assets which are marked-to-market on a monthly basis, were stated at their fair values on the Emergence Date.
The reorganization value also included $3.0 million of issuance costs attributable to the Credit Facility under which we initially borrowed $75.4
million. This amount was capitalized in accordance with GAAP as it represents costs attributable to the access to credit over the term of the
Credit Facility.
Our liabilities on the Emergence Date included the aforementioned borrowings under the Credit Facility, working capital liabilities
including accounts payable and accrued liabilities, a reserve for certain litigation matters, pension and health care obligations attributable to
certain retirees, AROs, and derivative liabilities. As the Credit Facility is current and is a variable-rate financial instrument, it was stated at its
fair value. Our working capital liabilities and litigation reserve are ordinary course obligations and their carrying amounts approximated their
fair values. We revalued our retiree obligations based on data from our independent actuaries and they have been stated at their fair values. The
AROs were valued in connection with the valuation process attributable to our oil and gas reserves as discussed above. Finally, our derivative
liabilities were also stated at their fair value as they are marked-to-market on a monthly basis.
80
Successor Balance Sheet
The following table reflects the reorganization and application of Fresh Start Accounting adjustments on our Consolidated Balance Sheet
as of September 12, 2016:
Assets
Current assets
Cash and cash equivalents
Accounts receivable, net of allowance for doubtful
accounts
Derivative assets
Other current assets
Total current assets
Property and equipment, net
Other assets
Total assets
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities
Accounts payable and accrued liabilities
Derivative liabilities
Current maturities of long-term debt
Total current liabilities
Other liabilities
Derivative liabilities
Long-term debt
Liabilities subject to compromise
Shareholders’ equity (deficit)
Preferred stock (Predecessor)
Common stock (Predecessor)
Paid-in capital (Predecessor)
Deferred compensation obligation (Predecessor)
Accumulated other comprehensive income
(Predecessor)
Treasury stock (Predecessor)
Common stock (Successor)
Paid-in capital (Successor)
Accumulated deficit
Total shareholders’ equity (deficit)
Total liabilities and shareholders’ equity (deficit)
$
Predecessor
Reorganization
Adjustments
Fresh Start
Adjustments
Successor
$
48,718
$
(17,304 )
(1 ) $
—
$
31,414
$
$
4,292
(2 )
—
(832)
(13,844 )
—
(1,281)
(15,125 )
(3 )
(4 )
$
(21,166 )
(5 ) $
—
(113,653)
(134,819)
(6 )
100
(5 )
—
75,350
(1,154,163 )
(7 )
(8 )
(9 )
(9 )
(9 )
(9 )
(9 )
(9 )
(10)
(10)
(11)
(1,880)
(697)
(1,213,797 )
(3,440)
(383)
3,574
150
190,745
2,224,135
1,198,407
(15,125 )
$
35,606
397
3,966
88,687
309,261
6,902
404,850
77,151
1,641
113,653
192,445
84,953
9,120
—
1,154,163
1,880
697
1,213,797
3,440
383
(3,574)
—
—
(2,252,454 )
(1,035,831 )
404,850
81
$
$
$
—
—
—
—
(55,751 ) (12)
—
(55,751 )
$
(3,455) (13) $
—
—
(3,455)
(80,615 ) (14)
—
—
—
—
—
—
—
—
—
—
—
28,319 (15)
28,319
(55,751 )
$
39,898
397
3,134
74,843
253,510
5,621
333,974
52,530
1,641
—
54,171
4,438
9,120
75,350
—
—
—
—
—
—
—
150
190,745
—
190,895
333,974
Reorganization Adjustments
1. Represents the net cash payments that occurred on the Emergence
Date:
Sources:
Proceeds from the Credit Facility
Proceeds from the Rights Offering, net of issuance costs
Total sources
Uses:
Repayment of RBL
Accrued interest payable on RBL
DIP Facility fees
Debt issue costs of the Credit Facility
Funding of professional fee escrow account
RBL lender professional fees and expenses
Ad Hoc Committee and indenture trustee professional fees and expenses
Payment of certain allowed claims and settlements
Total uses
125,293
$
$
75,350
49,943
$
113,653
1,374
12
3,011
14,575
455
6,782
2,735
142,597
(17,304)
$
2. Represents the reclassification of SERP assets to a current receivable from other noncurrent assets upon the cancellation of the underlying
plan and the reversion of the assets to the Successor.
3. Represents the write-off of certain prepaid directors and officers tail
insurance.
4. Represents the capitalization of debt issuance costs attributable to the Credit Facility, net of the reclassification of SERP assets as discussed
in item (2) above.
5. Represents the payment of professional fees on behalf of the RBL Lenders, the Ad Hoc Committee and the UCC, indenture trustee fees and
expenses, interest payable on the RBL as well as certain allowed claims and settlements net of the establishment of reserves and the
reinstatement of certain other obligations.
6. Represents the repayment of the RBL in cash in
full.
7. Represents the initial borrowings under the Credit
Facility.
8. Liabilities subject to compromise were settled as follows in accordance with the
Plan:
Liabilities subject to compromise prior to the Emergence Date:
Senior Notes
Interest on Senior Notes
Firm transportation obligation
Compensation – related
Deferred compensation
Trade accounts payable
Litigation claims
Other accrued liabilities
Amounts settled in cash, reinstated or otherwise reserved at emergence
Gain on settlement of liabilities subject to compromise
$
1,075,000
47,213
11,077
9,733
4,676
1,487
1,092
3,885
$
$
1,154,163
(3,915)
1,150,248
9. Represents the cancellation of our Predecessor preferred and common stock and related components of our Predecessor shareholders’
deficit.
10. Represents the issuance of 14,992,018 shares of Successor Common Stock with a fair value of $12.73 per
share.
82
11. Represents the cumulative impact of the reorganization adjustments described
above:
Gain on settlement of liabilities subject to compromise
Fair value of equity allocated to:
Unsecured creditors on the Emergence Date
Unsecured creditors pending resolution on the Emergence Date
Backstop Parties in the form of a Commitment Premium
Cancellation of Predecessor shareholders’ deficit
Net impact to Predecessor accumulated deficit
Fresh Start Adjustments
$
1,150,248
174,477
10,396
6,022
190,895
882,992
2,224,135
$
12. Represents the Fresh Start Accounting valuation adjustments applied to our oil and gas properties and other
equipment.
13. Represents the accelerated recognition of the current portion of previously deferred gains on sales of assets attributable to the accounting
presentation required by GAAP under the Predecessor.
14. Represents the recognition of Fresh Start Accounting adjustments to: (i) our AROs attributable to the revalued oil and gas properties and (ii)
our retiree obligations based on actuarial measurements, as well as the accelerated recognition of the noncurrent portion of previously
deferred gains on sales of assets attributable to the accounting presentation required by GAAP under the Predecessor.
15. Represents the cumulative impact of the Fresh Start Accounting adjustments discussed
above.
Reorganization Items. As described above in Note 2, our Consolidated Statements of Operations for the period ended September 12,
2016 include “Reorganization items, net,” which reflects gains recognized on the settlement of liabilities subject to compromise and costs and
other expenses associated with the bankruptcy proceedings, principally professional fees, and the costs associated with the DIP Facility. These
post-petition costs for professional fees, as well as administrative fees charged by the U.S. Trustee, have been reported in “Reorganization
items, net” in our Consolidated Statement of Operations as described above. Similar costs that were incurred during the pre-petition periods
have been reported in “General and administrative” expenses.
While we emerged from bankruptcy in September 2016, certain administrative and claims resolution activities continued until November
2018 when the Bankruptcy Court issued a final decree which effectively closed the case. Upon the closure, we reversed the $0.2 million
remaining unused portion of an accrual that was established on the Emergence Date for legal and professional fees and administrative costs. In
addition, we reversed the $2.7 million unallocated portion of a reserve that was established on the Emergence Date for the potential settlement
of certain claims in cash. Finally, we also reversed $0.4 million of accounts payable that were held open since the Emergence Date as secured
claims, but were ultimately expunged. As these items of income are directly attributable to the final administration of our bankruptcy case and
not a part of our continuing operations, they are classified on our Consolidated Statement of Operations as components of “Reorganization
items, net.”
The following table summarizes the components included in “Reorganization items, net” in our Consolidated Statements of Operations
for the period presented:
Gains on the settlement of liabilities subject to compromise
Fresh start accounting adjustments
Legal and professional fees and expenses
Settlements attributable to contract amendments
DIP Facility costs and commitment fees
Write-off of prepaid directors and officers insurance
Other reorganization items
83
Year Ended
December 31,
2018
January 1 Through
September 12,
2016
— $
—
200
—
—
—
3,122
3,322 $
1,150,248
28,319
(29,976 )
(2,550 )
(170 )
(832 )
(46 )
1,144,993
$
$
5. Acquisitions and Divestitures
Acquisitions
Hunt Acquisition
In December 2017, we entered into a purchase and sale agreement with Hunt Oil Company (“Hunt”) to acquire certain oil and gas assets
in the Eagle Ford Shale, primarily in Gonzales County, Texas for $86.0 million in cash, subject to adjustments (the “Hunt Acquisition”). The
Hunt Acquisition had an effective date of October 1, 2017 and closed on March 1, 2018, at which time we paid cash consideration of $84.4
million. In connection with the Hunt Acquisition, we also acquired working interests in certain wells that we previously drilled as operator in
which Hunt had rights to participate prior to the transaction closing. Accumulated costs, net of suspended revenues for these wells was $13.8
million, which we have reflected as a component of total net assets acquired. We funded the Hunt Acquisition with borrowings under the Credit
Facility.
The final settlement of the Hunt Acquisition occurred in July 2018, at which time an additional $0.2 million of acquisition costs was
allocated from certain working capital components and Hunt transferred $1.4 million to us primarily for suspended revenues attributable to the
acquired properties.
We incurred a total of $0.5 million of transaction costs for legal, due diligence and other professional fees associated with the Hunt
Acquisition, including $0.1 million in 2017 and $0.4 million in the first quarter of 2018. These costs have been recognized as a component of
our G&A expenses.
We accounted for the Hunt Acquisition by applying the acquisition method of accounting as of March 1, 2018. The following table
represents the final fair values assigned to the net assets acquired and the total acquisition cost incurred, including consideration transferred to
Hunt:
Assets
Oil and gas properties - proved
Oil and gas properties - unproved
Liabilities
Revenue suspense
Asset retirement obligations
Net assets acquired
Cash consideration paid to Hunt, net
Application of working capital adjustments
Accumulated costs, net of suspended revenues, for wells in which Hunt had rights to participate
Total acquisition costs incurred
Devon Acquisition
$
$
$
$
82,443
16,339
1,448
356
96,978
82,955
245
13,778
96,978
In July 2017, we entered into a purchase and sale agreement (the “Purchase Agreement”), with Devon Energy Corporation (“Devon”) to
acquire all of Devon’s right, title and interest in and to certain oil and gas assets (the “Devon Properties”), including oil and gas leases covering
approximately 19,600 net acres located primarily in Lavaca County, Texas for aggregate consideration of $205 million in cash (the “Devon
Acquisition”). Upon execution of the Purchase Agreement, we deposited $10.3 million as earnest money into an escrow account (the “Escrow
Account”). The Devon Acquisition had an effective date of March 1, 2017 and closed on September 29, 2017, at which time we paid cash
consideration of $189.9 million and $7.1 million was released from the Escrow Account to Devon. In November 2017, we acquired additional
working interests in the Devon Properties for $0.7 million from parties that had tag-along rights to sell their interests under the Purchase
Agreement.
As of December 31, 2017, $3.2 million remained in the Escrow Account, which was included as a component of noncurrent “Other
assets” on our Consolidated Balance Sheet. The final settlements of the Devon Acquisition together with the tag-along rights acquisition,
occurred in February 2018, at which time $2.5 million in cash was transferred from the Escrow Account to Devon, and the remaining $0.7
million was distributed to us. In addition, Devon transferred $0.4 million to us for suspended revenues attributable to the acquired properties.
The Devon Acquisition was financed with the net proceeds received from borrowing under the $200 million Second Lien Credit
Agreement dated as of September 29, 2017 (the “Second Lien Facility”) (see Note 10 for terms of the Second Lien Facility) and incremental
borrowings under the Credit Facility.
We incurred a total of $1.3 million of transaction costs associated with the Devon Acquisitions during 2017, including advisory, legal,
due diligence and other professional fees. These costs have been recognized as a component of our G&A expenses.
84
We accounted for the Devon Acquisition by applying the acquisition method of accounting as of the Date of Acquisition. The following
table represents the final fair values assigned to the net assets acquired and the total consideration transferred:
Assets
Oil and gas properties - proved
Oil and gas properties - unproved
Other property and equipment
Liabilities
Revenue suspense
Asset retirement obligations
Net assets acquired
Cash consideration paid to Devon and tag-along parties, net
Amount transferred to Devon from the Escrow Account
Application of working capital adjustments, net
Total consideration
Valuation of Acquisitions
$
$
$
$
42,866
146,686
8,642
355
494
197,345
190,277
9,519
(2,451 )
197,345
The fair values of the oil and gas properties acquired in the Hunt and Devon Acquisitions were measured using valuation techniques that
convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves, (ii) future
operating and development costs, (iii) future commodity prices, (iv) future cash flows (v) the timing of or development plans and (vi) a market-
based weighted-average cost of capital. The fair value of the other property and equipment acquired was measured primarily with reference to
replacement costs for similar assets adjusted for the age and normal use of the underlying assets. Because many of these inputs are not
observable, we have classified the initial fair value estimates as Level 3 inputs as that term is defined in GAAP.
Impact of Acquisitions on Actual and Pro Forma Results of Operations
The results of operations attributable to the Hunt and Devon Acquisitions have been included in our Consolidated Financial Statements
for the periods after March 1, 2018 and September 30, 2017, respectively. The Devon Acquisition provided revenues and estimated earnings,
excluding allocations of interest expense and income taxes, of approximately $9 million and $4 million, respectively, for the period from
October 1, 2017 through December 31, 2017. The Hunt Acquisition provided revenues and estimated earnings, excluding allocations of interest
expense and income taxes, of approximately $0.4 million and $0.2 million, respectively, for the period from March 1, 2018 through March 31,
2018. As the properties and working interests acquired in connection with the Hunt and Devon Acquisitions are included within our existing
Eagle Ford acreage, it is not practical or meaningful to disclose revenues and earnings unique to those assets for periods beyond those during
which they were acquired, as they were fully integrated into our regional operations soon after their acquisition.
The following table presents unaudited summary pro forma financial information for the years ended December, 31, 2018 and 2017
assuming the Hunt and Devon Acquisitions and the related entry into the Second Lien Facility occurred as of January 1, 2017. The pro forma
financial information does not purport to represent what our actual results of operations would have been if the Hunt and Devon Acquisitions
and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods. We have excluded
any pro forma presentations for the Successor and Predecessor periods in 2016 as the determination of such pro forma adjustments are not
practical due primarily to our reorganization and the adoption of Fresh Start Accounting and the full cost method on the Emergence Date. In
light of these circumstances, we also believe that such a pro forma presentation for 2016 would not be comparable and could potentially be
misleading.
Total revenues
Net income attributable to common shareholders
Net income per share - basic
Net income per share - diluted
85
Year Ended December 31,
2018
2017
446,077 $
227,930 $
15.14 $
14.91 $
209,015
30,861
2.06
2.05
$
$
$
$
Divestitures
Mid-Continent Divestiture
In June 2018, we entered into a purchase and sale agreement with a third party to sell all of our remaining Mid-Continent oil and gas
properties, located primarily in Oklahoma in the Granite Wash, for $6.0 million in cash, subject to customary adjustments. The sale had an
effective date of March 1, 2018 and closed on July 31, 2018, and we received proceeds of $6.2 million. The sale proceeds and de-recognition of
certain assets and liabilities were recorded as a reduction of our net oil and gas properties. In November 2018, we paid $0.5 million, including
$0.2 million of suspended revenues, to the buyer in connection with the final settlement.
The Mid-Continent properties had asset retirement obligations (“AROs”) of $0.3 million as well as a net working capital deficit
attributable to the oil and gas properties of $1.3 million as of July 31, 2018. The net pre-tax operating income attributable to the Mid-Continent
assets was $1.6 million and $2.2 million for the years ended December 31, 2018 and December 31, 2017, respectively.
Sales of Undeveloped Acreage, Rights and Other Assets
In February 2018, we sold our undeveloped acreage holdings in the Tuscaloosa Marine Shale in Louisiana that were scheduled to expire
in 2019. In March 2018, we sold certain undeveloped deep leasehold rights in Oklahoma, and in May 2018, we sold certain pipeline assets in our
former Marcellus Shale operating region. We received a combined total of $1.7 million for these leasehold and other assets which were applied
as a reduction of our net oil and gas properties.
6. Accounts Receivable and Major
Customers
The following table summarizes our accounts receivable by type as of the dates presented:
Customers
Joint interest partners
Other
Less: Allowance for doubtful accounts
December 31,
2018
2017
59,030 $
6,404
640
66,074
(36 )
66,038 $
39,106
32,493
584
72,183
(2,362 )
69,821
$
$
For the year ended December 31, 2018, three customers accounted for $304.3 million, or approximately 69% of our consolidated product
revenues. The revenues generated from these customers during 2018 were $173.0 million, $71.5 million and $59.8 million or 39%, 16%, and
14% of the consolidated total, respectively. As of December 31, 2018, $28.6 million, or approximately 48% of our consolidated accounts
receivable from customers was related to these customers. For the year ended December 31, 2017, three customers accounted for $137.5
million, or approximately 86% of our consolidated product revenues. The revenues generated from these customers during 2017 were $94.1
million, $22.1 million and $21.3 million, or approximately 59%, 14% and 13% of the consolidated total, respectively. As of December 31, 2017,
$32.1 million, or approximately 82% of our consolidated accounts receivable from customers was related to these customers. No significant
uncertainties exist related to the collectability of amounts owed to us by any of these customers.
Revenue from Contracts with Customers
Adoption of ASC Topic 606
Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contracts with customers for the sale
of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other
third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to
consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services.
Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and
changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and
transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote off $2.7 million of
accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning
balance of retained earnings as of January 1, 2018, and (iii) adopted the sales method with respect to production imbalance transactions
beginning after December 31, 2017.
86
The following table illustrates the impact of the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for
the year ended December 31, 2018:
Revenues
Crude oil
Natural gas liquids
Natural gas
Marketing services (included in Other revenues, net)
Operating expenses
Gathering, processing and transportation
Net income
Year Ended December 31, 2018
As Determined Under As Reported Under
Prior GAAP
ASC Topic 606
Net Change
$
$
$
$
$
$
402,485 $
23,429 $
15,972 $
523 $
20,982 $
224,785 $
402,485 $
21,073 $
15,972 $
523 $
18,626 $
224,785 $
—
(2,356)
—
—
(2,356)
—
Transaction Prices, Contract Balances and Performance Obligations
Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have
applied the practical expedient included in ASC Topic 606, which provides for an exemption from disclosure of the transaction price allocated to
remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been
satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do
not create contract assets or liabilities as those terms are defined in ASC Topic 606.
We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements
necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead
allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas
production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based
on estimates of our share of production. We record any differences, which historically have not been significant, between the actual amounts
ultimately received and the original estimates in the period they become finalized.
7. Derivative
Instruments
We utilize derivative instruments to mitigate our financial exposure to commodity price volatility. Our derivative instruments are not
formally designated as hedges in the context of U.S. GAAP.
We typically utilize collars and swaps, which are placed with financial institutions that we believe are acceptable credit risks, to hedge
against the variability in cash flows associated with anticipated sales of our future production. While the use of derivative instruments limits the
risk of adverse price movements, such use may also limit future revenues from favorable price movements.
The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below
the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period
is above the ceiling or swap price for such contract. Neither party is required to make a payment to the other party if the settlement price for any
settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such collar contract.
We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted
forward prices for WTI crude oil and LLS crude oil closing prices as of the end of the reporting period. The discounted cash flows utilize
discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is
in a liability position.
We terminated all of our pre-petition derivative contracts from March 2016 through May 2016 for $63.0 million and reduced our amounts
outstanding under the RBL by $52.0 million. In connection with these transactions, the counterparties to the derivative contracts, which were
also affiliates of lenders under the RBL, transferred the cash proceeds that were used for RBL repayments directly to the administrative agent
under the RBL. Accordingly, all of these RBL repayments have been presented as non-cash financing activities in our Consolidated Statement of
Cash Flows for the period January 1, 2016 through September 12, 2016.
87
The following table sets forth our commodity derivative positions as of December 31, 2018:
Instrument
Crude Oil:
First quarter 2019
First quarter 2019
Second quarter 2019
Second quarter 2019
Third quarter 2019
Third quarter 2019
Fourth quarter 2019
Fourth quarter 2019
First quarter 2020
Second quarter 2020
Third quarter 2020
Fourth quarter 2020
Settlements to be received in subsequent period, net
Swaps-WTI
Swaps-LLS
Swaps-WTI
Swaps-LLS
Swaps-WTI
Swaps-LLS
Swaps-WTI
Swaps-LLS
Swaps-WTI
Swaps-WTI
Swaps-WTI
Swaps-WTI
Financial Statement Impact of Derivatives
Average
Volume Per
Weighted
Average
Day
(barrels)
Price
($/barrel)
Fair Value
Asset
Liability
6,446 $
5,000 $
6,421 $
5,000 $
6,397 $
5,000 $
6,398 $
5,000 $
6,000 $
6,000 $
6,000 $
6,000 $
54.46 $
59.17
54.48
59.17
54.50
59.17
54.50
59.17
54.09
54.09
54.09
54.09
4,959 $
3,684
4,307
3,203
3,821
3,092
3,498
3,015
2,807
2,609
2,450
2,234
4,362
—
—
—
—
—
—
—
—
—
—
—
—
The impact of our derivatives activities on income is included in the “Derivatives” caption on our Consolidated Statements of Operations.
The following table summarizes the effects of our derivative activities for the periods presented:
Successor
Predecessor
September 13 Through
January 1 Through
Year Ended December 31,
December 31,
September 12,
2018
2017
2016
2016
Derivative gains (losses)
$
37,427 $
(17,819 ) $
(16,622 ) $
(8,333 )
The effects of derivative gains and (losses) and cash settlements (except for those cash settlements attributable to the aforementioned
termination transactions) are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are
recorded in the “Derivative contracts” section of our Consolidated Statements of Cash Flows under the “Net losses (gains)” and “Cash
settlements, net.”
The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments, on our
Consolidated Balance Sheets as of the dates presented:
Type
Balance Sheet Location
Commodity contracts Derivative assets/liabilities – current
Commodity contracts Derivative assets/liabilities – noncurrent
Fair Values
December 31, 2018
December 31, 2017
Derivative
Assets
Derivative
Liabilities
Derivative
Assets
Derivative
Liabilities
$
$
34,932 $
10,100
45,032 $
991 $
—
991 $
— $
—
— $
27,777
13,900
41,677
As of December 31, 2018, we reported net commodity derivative assets of $44.0 million. The contracts associated with this position are
with eight counterparties, all of which are investment grade financial institutions. This concentration may impact our overall credit risk, either
positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither
paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative
contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that
may be owed to us by these counterparties.
88
8. Property and
Equipment
The following table summarizes our property and equipment as of the dates presented:
Oil and gas properties:
Proved
Unproved
Total oil and gas properties
Other property and equipment
Total property and equipment
Accumulated depreciation, depletion and amortization
December 31,
2018
2017
$
$
1,037,993 $
63,484
1,101,477
20,383
1,121,860
(193,866 )
927,994 $
460,029
117,634
577,663
12,712
590,375
(61,316 )
529,059
Unproved property costs of $63.5 million and $117.6 million have been excluded from amortization as of December 31, 2018 and
December 31, 2017, respectively. We transferred $82.8 million and $40.4 million of undeveloped leasehold costs, including capitalized interest,
associated with proved undeveloped reserves, acreage unlikely to be drilled or expiring acreage, from unproved properties to the full cost pool
during the years ended December 31, 2018 and 2017, respectively. We capitalized internal costs of $3.7 million and $2.4 million and interest of
$9.1 million and $2.7 million during the year ended December 31, 2018 and 2017, respectively, in accordance with our accounting policies.
Average DD&A per barrel of oil equivalent of proved oil and gas properties was $16.11 and $12.87 for the years ended December 31, 2018 and
2017, $11.21 for the Successor period from September 13, 2016 through December 31, 2016, and $10.04 for the Predecessor period from
January 1, 2016 through September 12, 2016. The DD&A rate for the Predecessor period was determined under the successful efforts method
while the Successor periods subsequent to September 12, 2016 were determined under the full cost method (see Note 2).
9. Asset Retirement
Obligations
The following table reconciles our AROs as of the dates presented, which are included in the “Other liabilities” caption on our
Consolidated Balance Sheets:
Balance at beginning of period
Changes in estimates
Liabilities incurred
Liabilities settled
Purchase of properties
Sale of properties
Accretion expense
Balance at end of period
Year Ended December 31,
2018
2017
3,286 $
354
335
(8 )
385
(310 )
272
4,314 $
2,459
149
118
(139 )
494
—
205
3,286
$
$
89
10. Long-Term
Debt
The following table summarizes our long-term debt as of the dates presented:
Credit facility 2
Second lien term loans
Totals
Less: Unamortized discount
Less: Unamortized deferred issuance costs
Long-term debt, net
December 31, 2018
December 31, 2017
Unamortized
Discount and
Issuance Costs 1
Unamortized
Discount and
Issuance Costs 1
Principal
Principal
$
$
321,000
200,000 $
521,000
(3,159)
(6,466)
511,375
$
9,625
9,625
$
77,000
200,000 $
277,000
(3,839)
(7,894)
265,267
11,733
11,733
_____________________________________________
1 Discount and issuance costs of the Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method.
2
Issuance costs of the Credit Facility, which represent costs attributable to the access to credit over its contractual term, have been presented as a component of Other assets
(see Note 13) and are being amortized over the term of the Credit Facility using the straight-line method.
Credit Facility
On the Emergence Date, we entered into the Credit Facility. The Credit Facility provides for a $450.0 million revolving commitment and
borrowing base and a $5 million sublimit for the issuance of letters of credit. On October 26, 2018, we entered into the Master Assignment,
Agreement and Amendment No. 5 to the Credit Facility (the “Fifth Amendment”) whereby the borrowing base was redetermined from $340.0
million to $450.0 million. In the years ended December 31, 2018 and December 31, 2017, we paid and capitalized issue costs of $0.9 million
and $1.7 million, respectively in connection with amendments to the Credit Facility and wrote-off $0.8 million during 2017 of previously
capitalized issue costs due to changes in the composition of financial institutions comprising the Credit Facility bank group associated with that
amendment. The availability under the Credit Facility may not exceed the lesser of the aggregate commitments or the borrowing base. The
borrowing base under the Credit Facility is generally redetermined semi-annually in April and October of each year. Additionally, the Credit
Facility lenders may, at their discretion, initiate a redetermination at any time during the six-month period between scheduled redeterminations.
The Credit Facility is available to us for general corporate purposes including working capital. The Credit Facility matures in September 2020.
We had $0.4 million and $0.8 million in letters of credit outstanding as of December 31, 2018 and December 31, 2017, respectively.
The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate
plus an applicable margin ranging from 2.00% to 3.00%, determined based on the average availability under the Credit Facility or (b) a
customary London interbank offered rate (“LIBOR”) plus an applicable margin ranging from 3.00% to 4.00%, determined based on the average
availability under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year
of 365/366 days, and interest on LIBOR borrowings is payable every one, three or six months, at the election of the borrower, and is computed
on the basis of a year of 360 days. As of December 31, 2018, the actual interest rate on the outstanding borrowings under the Credit Facility was
5.96%. Unused commitment fees are charged at a rate of 0.50%.
The Credit Facility is guaranteed by us and all of our subsidiaries (the “Guarantor Subsidiaries”). The guarantees under the Credit
Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The
parent company has no material independent assets or operations. There are no significant restrictions on the ability of the parent company or
any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by
a first priority lien on substantially all of our assets.
The Credit Facility requires us to maintain (1) a minimum interest coverage ratio (adjusted earnings before interest, taxes, depreciation,
depletion, amortization and exploration expenses as defined in the Credit Facility (“EBITDAX”) to adjusted interest expense), measured as of
the last day of each fiscal quarter, of 3.00 to 1.00, (2) a minimum current ratio (as defined in the Credit Facility, which considers the unused
portion of the total commitment as a current asset), measured as of the last day of each fiscal quarter of 1.00 to 1.00, and (3) a maximum
leverage ratio (consolidated indebtedness to EBITDAX), measured as of the last day of each fiscal quarter, of 3.50 to 1.00.
The Credit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including
environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements,
oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the
incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other
customary covenants.
90
As of December 31, 2018, and through the date upon which the Consolidated Financial Statements were issued, we were in compliance
with all of the covenants under the Credit Facility.
Second Lien Facility
On September 29, 2017, we entered into the $200 million Second Lien Facility. We received net proceeds of $ 187.8 million from the
Second Lien Facility net of an original issue discount (“OID”) of $4.0 million and issue costs of $8.2 million. The proceeds from the Second
Lien Facility were used to fund the Devon Acquisition and related fees and expenses. The maturity date under the Second Lien Facility is
September 29, 2022.
The 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 6.00% or (b) a customary LIBOR rate plus an applicable margin of 7.00%. As of
December 31, 2018, the actual interest rate of outstanding borrowings under the Second Lien Facility was 9.53%. Amounts under the Second
Lien Facility were borrowed at a price of 98% with an initial interest rate of 8.34% resulting in an effective interest rate of 9.89%. Interest on
reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on eurocurrency
borrowings is payable every one or three months (including in three month intervals if we select a six month interest period), at our election and
is computed on the basis of a 360-day year. 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 eurocurrency loans): during
year one, a customary “make-whole” premium; during year two, 102% of the amount being prepaid; during year three, 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: during years one and two,
102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium.
The Second Lien Facility is collateralized by substantially all of the Company’s and its subsidiaries’ assets with lien priority subordinated
to the liens securing the Credit Facility. The obligations under the Second Lien Facility are guaranteed by us and the Subsidiary Guarantors.
The Second Lien Facility has no financial covenants, but contains customary affirmative and negative covenants, including as to
compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly
and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas
properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets and transactions with affiliates and
other customary covenants.
As illustrated in the table above, the OID and issue costs of the Second Lien Facility are presented as reductions to the outstanding term
loans. These costs are subject to amortization using the interest method over the five-year term of the Second Lien Facility.
As of December 31, 2018, and through the date upon which the Consolidated Financial Statements were issued, we were in compliance
with all of the covenants under the Second Lien Facility.
91
11. Income
Taxes
The following table summarizes our provision for income taxes for the periods presented:
Current income taxes (benefit)
Federal
Deferred income taxes (benefit)
Federal
State
Successor
Predecessor
September 13 Through
January 1 Through
Year Ended December 31,
December 31,
September 12,
2018
2017
2016
2016
$
$
(2,471) $
(2,471)
2,471
523
2,994
523 $
— $
—
(4,943)
—
(4,943)
(4,943) $
— $
—
—
—
—
— $
—
—
—
—
—
—
The following table reconciles the difference between the income tax expense (benefit) computed by applying the statutory tax rate to our
income (loss) before income taxes and our reported income tax benefit for the periods presented:
Computed at federal statutory rate
State income taxes, net of federal
income tax benefit
Change in valuation allowance
Effect of rate change on the
valuation allowance
Effect of rate change
Reorganization adjustments
Other, net
Successor
Predecessor
September 13 Through
January 1 Through
Year Ended December 31,
December 31,
September 12,
2018
2017
2016
2016
$ 47,315
21.0 % $
9,701
35.0 % $
(1,854)
35.0 % $ 369,111
35.0 %
1,743
(48,820 )
0.8 %
(21.7 )%
(1,383)
(24,353 )
(5.0)%
(87.8 )%
197
1,657
(3.7)%
(31.3 )%
1,989
(384,692)
0.2 %
(36.5 )%
—
—
—
285
523
$
— %
— %
— %
0.1 %
0.2 % $
(86,612 )
86,612
10,760
332
(4,943)
(312.5)%
312.5 %
38.8 %
1.2 %
(17.8 )% $
—
—
—
—
—
— %
— %
— %
— %
— % $
—
—
13,572
20
—
— %
— %
1.3 %
— %
— %
The following table summarizes the principal components of our deferred income tax assets and liabilities as of the dates presented:
December 31,
2018
2017
Deferred tax assets:
Net operating loss (“NOL”) carryforwards
Property and equipment
Pension and postretirement benefits
Share-based compensation
Fair value of derivative instruments
Other
Less: Valuation allowance
Total net deferred tax assets
Deferred tax liabilities:
Property and equipment
Fair value of derivative instruments
Total deferred tax liabilities
Net deferred tax assets
$
163,437 $
—
441
546
—
8,836
173,260
(128,650 )
44,610
33,413
9,248
42,661
1,949 $
$
92
127,821
37,345
452
435
8,752
7,608
182,413
(177,470 )
4,943
—
—
—
4,943
Analysis of 2018 Tax Reform
On December 22, 2017, the U.S. Congress enacted the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (the
“TCJA”). The TCJA makes broad and complex changes to the U.S. tax code, including but not limited to, (i) the requirement to pay a one-time
transition tax on all undistributed earnings of foreign subsidiaries; (ii) reducing the U.S. federal corporate income tax rate from 35% to 21%; (iii)
generally eliminating U.S. federal income taxes on dividends from foreign subsidiaries; (iv) creating a new limitation on deductible interest
expense; (v) changing rules related to use and limitations of NOL carryforwards created in tax years beginning after December 31, 2017 and (vi)
repeal of the corporate alternative minimum tax (“AMT”).
In connection with our analysis of the impact of the TCJA, we recorded income tax charge of $86.6 million for the year ended December
31, 2017, which consists of a reduction of deferred tax assets previously valued at 35%. We recorded a corresponding decrease in our deferred
tax asset valuation allowance representing an income tax benefit for the same amount. The reduction in the statutory U.S. federal rate is
expected to positively impact the Company’s future US after tax earnings. As a result of the repeal of the AMT, our existing AMT credit
carryovers became refundable beginning with the 2018 tax year. The AMT credit carryforwards are used to offset current year regular tax
liabilities with 50 percent of any excess remaining credit per year being refundable as part of the annual income tax filing. We anticipate a full
refund of our approximately $5 million of the AMT credit carryforwards by 2021.
Income Tax Provision
The provision for the year ended December 31, 2018 includes a current federal benefit of $2.5 million attributable to the anticipated
refund of AMT credits for the 2018 tax year. This amount has been recognized as a “current income tax receivable” on our Consolidated
Balance Sheet as of December 31, 2018. This benefit is offset by a corresponding decrease in the deferred tax asset associated with the
refundable AMT credit giving rise to a deferred federal expense. In addition, we have a recognized a deferred state tax expense of $0.5 million
for an overall effective tax rate of 0.2%. The remaining AMT credit carryforwards of approximately $2.5 million will be reclassified from
deferred tax assets, where they are classified as of December 31, 2018, to current income tax receivables upon the filing of federal returns in
future years.
In addition to the aforementioned offsetting items with respect to the reduction in income tax rates, our income tax provision for the year
ended December 31, 2017 included federal income taxes of $9.7 million applied at the statutory rate of 35% for 2017 and an adjustment of
$10.8 million attributable to reductions in certain tax attributes of property and other adjustments of $0.3 million applied in connection with the
filing of our 2016 income tax returns. These expenses were effectively offset by benefits attributable to the reduction in our deferred tax asset
valuation allowance of $24.4 million and state income tax benefits of $1.4 million resulting in a net tax deferred benefit of $4.9 million. The
entire federal tax benefit and the corresponding net deferred tax asset presented on our Consolidated Balance Sheet as of December 31, 2017 are
exclusively attributable to the AMT credit carryforwards.
Deferred Tax Assets and Liabilities
As of December 31, 2018, we had federal NOL carryforwards of approximately $557.2 million, a substantial portion of which, if not
utilized, expire between 2032 and 2037. NOLs incurred after January 1, 2018 can be carried forward indefinitely. State NOL carryforwards of
approximately $437.9 million expire between 2024 and 2037. Because of the change in ownership provisions of the Code, use of a portion of
our federal and state NOL may be limited in future periods. As of December 31, 2018, we carried a valuation allowance against our federal and
state deferred tax assets of $128.7 million. We considered both the positive and negative evidence in determining whether it was more likely
than not that some portion or all of our deferred tax assets will be realized. The amount of deferred tax asset considered realizable could,
however, be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative
evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as our projections for
growth. Our net deferred tax assets recognized on the Consolidated Balance Sheets as of December 31, 2018 and 2017 are attributable to AMT
credit carryforwards, and net of certain state deferred tax liabilities as of December 31, 2018. The valuation allowance related to all other net
deferred tax assets remains in full.
Other Income Tax Matters
We had no liability for unrecognized tax benefits as of December 31, 2018 and 2017. There were no interest and penalty charges
recognized during the years ended December 31, 2018, 2017 and 2016. Tax years from 2013 forward remain open for examination by the
Internal Revenue Service and various state jurisdictions, and certain taxes are not dischargeable in bankruptcy.
93
12. Executive Retirement and Exit
Activities
Executive Retirement
Effective February 28, 2018, Mr. Harry Quarls retired from his position as a director and Executive Chairman of the Company. In
connection with his retirement, we entered into a separation and consulting agreement (“Separation Agreement”) whereby Mr. Quarls provided
transition and support services to us through December 31, 2018. We paid Mr. Quarls $0.3 million for such services. The Separation Agreement
included a general release of claims and provided for the accelerated vesting of certain share-based compensation awards for which we
recognized expense of $0.6 million during the year ended December 31, 2018 (see Note 17). The costs associated with the Separation
Agreement, including the share-based compensation charges, are included as a component of “G&A expenses” in our Consolidated Statements
of Operations.
Exit Activities
During 2016, we committed to a number of actions, or exit activities. The most significant of those activities were attributable to an
overall reduction in the scope and scale of our organization and required payments to satisfy obligations associated with the underlying
commitments. The following summarizes the most significant exit activities.
Reductions in Force
In 2016, we reduced our total employee headcount by 53 employees. We paid a total of $2.1 million, including $1.4 million in severance
and termination benefits and $0.7 million in retention bonuses during the year ended December 31, 2016. The costs associated with these
reduction-in-force and retention actions are included as a component of our “General and administrative” expenses in our Consolidated
Statements of Operations.
Drilling Rig Termination
In connection with the suspension of our 2016 drilling program, we terminated a drilling rig contract and incurred $1.7 million in early
termination charges. As this obligation represented a pre-petition liability of the Predecessor, it was discharged in connection with our
emergence from bankruptcy and included in “Reorganization items, net” in our Consolidated Statements of Operations.
Firm Transportation Obligation
We had a contractual obligation with a carrying value of $10.8 million for certain firm transportation capacity in the Appalachian region
that was scheduled to expire in 2022 and, as a result of the sale of our natural gas assets in this region in 2012, we no longer had production
available to satisfy this commitment. We originally recognized a liability in 2012 representing this obligation for the estimated discounted future
net cash outflows over the remaining term of the contract. The accretion of the obligation through the Petition Date, net of any recoveries from
periodic sales of our contractual capacity, was charged as an offset to “Other revenue” in our Consolidated Statement of Operations. In
connection with our emergence from bankruptcy, we rejected the underlying contract and the obligation was included in “Reorganization items,
net” in our Consolidated Statements of Operations.
94
13. Additional Balance Sheet
Detail
The following table summarizes components of selected balance sheet accounts as of the dates presented:
Other current assets:
Tubular inventory and well materials
Prepaid expenses
Other assets:
Deferred issuance costs of the Credit Facility
Deposit in escrow 1
Other
Accounts payable and accrued liabilities:
Trade accounts payable
Drilling costs
Royalties and revenue - related
Production, ad valorem and other taxes 2
Compensation - related
Interest
Reserve for bankruptcy claims
Other 2
Other liabilities:
Asset retirement obligations
Defined benefit pension obligations
Postretirement health care benefit obligations
Other
December 31,
2018
2017
$
$
$
$
$
$
$
$
4,061 $
1,064
5,125 $
2,437 $
—
44
2,481 $
16,507 $
22,434
51,212
2,418
4,489
670
—
5,970
103,700 $
4,314 $
857
362
—
5,533 $
5,146
1,104
6,250
2,857
3,210
2,440
8,507
22,579
22,389
39,287
1,275
2,975
223
3,933
3,520
96,181
3,286
971
476
100
4,833
_____________________________________________
1 The December 31, 2017 amount represents amounts that had remained in the Escrow Account for the Devon Acquisition which fully funded the remaining liability due to
Devon for the final settlement (see Note 5).
2 The amount for December 31, 2017 was reclassified from Accounts payable and accrued liabilities - Other.
14. Fair Value
Measurements
We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities.
Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to
transfer a liability in an orderly transaction with market participants at the measurement date.
We use a hierarchy that prioritizes the inputs we use to measure fair value into three distinct categories based upon whether such inputs
are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is
significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this
hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below.
Fair value measurements are classified and disclosed in one of the following three categories:
•
•
•
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or
liabilities. Level 1 inputs generally provide the most reliable evidence of fair value.
Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially
the full term of the asset or liability.
Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable
(i.e., supported by little or no market activity).
95
Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts
payable, derivatives and our Credit Facility and Second Lien Facility borrowings. Due to the short-term nature of their maturities, the carrying
value of our cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Our derivatives are marked-to-
market and presented at their values. The carrying value of our long-term debt, which includes the Credit Facility and the Second Lien Facility,
approximated their fair values as they represent variable-rate debt and their interest rates are reflective of market rates.
Recurring Fair Value Measurements
Certain financial assets and liabilities are measured at fair value on a recurring basis on our Consolidated Balance Sheets. The following
tables summarize the valuation of those assets and (liabilities) as of the dates presented:
Description
Assets:
Commodity derivative assets – current
Commodity derivative assets – noncurrent
Liabilities:
Commodity derivative liabilities – current
Commodity derivative liabilities – noncurrent
Description
Liabilities:
Commodity derivative liabilities – current
Commodity derivative liabilities – noncurrent
December 31, 2018
Fair Value
Fair Value Measurement Classification
Measurement
Level 1
Level 2
Level 3
$
$
34,932 $
10,100
(991) $
—
— $
—
— $
—
34,932 $
10,100
(991) $
—
December 31, 2017
Fair Value
Fair Value Measurement Classification
Measurement
Level 1
Level 2
Level 3
$
(27,777 ) $
(13,900 )
— $
—
(27,777 ) $
(13,900 )
—
—
—
—
—
—
Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of
the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in
which the event or change in circumstances that caused the transfer occurred. There were no transfers during any period in the years ended
December 31, 2018, 2017 and 2016.
We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:
•
Commodity derivatives: We determine the fair values of our commodity derivative instruments based on discounted cash flows
derived from third-party quoted forward prices for WTI and LLS crude oil closing prices as of the end of the reporting periods. We
generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of
these is a level 2 input.
Non-Recurring Fair Value Measurements
The most significant non-recurring fair value measurements utilized in the preparation of our Consolidated Financial Statements are
those attributable to the recognition and measurement of the Successor’s net assets with respect to the application of Fresh Start Accounting.
Those measurements are more fully described in Note 4. In addition, we utilize non-recurring fair value measurements with respect to the
recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful
efforts method to our oil and gas properties, as well as the initial determination of AROs associated with the ongoing development of new oil
and gas properties.
The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful
efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-
adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital
expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because
these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs. Under the full cost method,
which we have applied since the Emergence Date, we apply a ceiling test determination utilizing prescribed procedures as described in Note 3.
The full cost method is substantially different from the successful efforts method which relies upon fair value measurements.
96
The determination of the fair value of AROs is based upon regional market and facility specific information. The amount
of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current
prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment
obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these
significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs.
15. Commitments and
Contingencies
The following table sets forth our significant commitments as of December 31, 2018, by category, for the next five years and thereafter:
Year
2019
2020
2021
2022
2023
Thereafter
Total
Rental Commitments
Minimum
Rentals
Drilling and
Completion
Gathering and
Intermediate
Transportation
$
$
532 $
657
637
638
634
159
3,257 $
20,692 $
—
—
—
—
—
20,692 $
Other Commitments
254
121
44
—
—
—
419
11,702 $
12,962
12,962
12,962
12,962
50,750
114,300 $
Operating lease rental expense was $2.7 million, $1.0 million, $0.2 million and $2.4 million, for the years ended December 31, 2018 and
2017, the Successor period from September 13, 2016 through December 31, 2016, and the Predecessor period from January 1, 2016 through
September 12, 2016, related primarily to field equipment, office equipment and office leases.
Drilling and Completion Commitments
We had a contractual commitment for one drilling rig as of December 31, 2018. Upon expiration of its original term in February 2019, the
drilling rig will be converted from a fixed-term commitment to a pad-to-pad basis. We also had two other drilling rigs contracted as of December
31, 2018 on pad-to-pad terms. In December 2018, we entered into a one-year commitment, which can be terminated with 60-days’ notice by
either party, to utilize certain frac services, which is effective January 1, 2019.
Gathering and Intermediate Transportation Commitments
We have long-term agreements with Republic Midstream and Republic Midstream Marketing, LLC (“Republic Marketing” and, together
with Republic Midstream, collectively, “Republic”) to provide gathering and intermediate pipeline transportation services for a substantial
portion of our crude oil and condensate production in the South Texas region as well as volume capacity support for certain downstream
interstate pipeline transportation.
In August 2016, the Bankruptcy Court approved a settlement with Republic and authorized the assumption of certain amended
agreements with Republic (the “Amended Agreements”). We paid Republic $0.3 million in connection with the settlement which is included in
“Reorganization items, net” in our Consolidated Statements of Operations.
Under the terms of the Amended Agreements, Republic is obligated to gather and transport our crude oil and condensate from within a
dedicated area in the Eagle Ford (the “Dedication Area”) via a gathering system and intermediate takeaway pipeline connecting to a downstream
interstate pipeline operated by a third party. The amended gathering agreement reduced our minimum volume commitment from 15,000 to
8,000 gross barrels of oil per day. The term of the amended gathering agreement runs through 2041, with the term of the minimum volume
commitment extended from 10 to 15 years through 2031. The gathering portion of these minimum commitments are being recognized as a
component of our gathering, processing and transportation expense while the intermediate transportation and pipeline support commitments are
recognized as a reduction to the index-based price that we receive for crude oil sold to Republic in accordance with Amended Agreements.
Under the amended marketing agreement, we have a 10-year commitment to sell 8,000 barrels per day of crude oil (gross) to Republic, or
any third party, utilizing Republic Marketing’s capacity on a certain downstream interstate pipeline.
Other Commitments
We have entered into certain contractual arrangements for other products and services. We have purchase commitments for certain
materials as well as minimum commitments under information technology licensing and service agreements, among others.
97
Legal
We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of
these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial
position, results of operations or cash flows. As of December 31, 2018, we had a reserve in the amount of $1.3 million included in Accounts
payable and accrued liabilities for the estimated settlement of disputes with partners regarding certain transactions that occurred in prior years. A
total of $1.0 million of this amount was paid in January 2019. In addition, during 2018 we eliminated a $0.1 million reserve for a litigation
matter that was ultimately resolved and did not require settlement.
Environmental Compliance
Extensive federal, state and local laws govern oil and gas operations, regulate the discharge of materials into the environment or
otherwise relate to the protection of the environment. 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 for
failure to comply. 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, 2018, we
have recorded AROs of $4.3 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 or results of
operations. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws, including any significant
limitation on the use of hydraulic fracturing, have the potential to adversely affect our operations.
16. Shareholders’
Equity
Preferred Stock
As discussed in Note 4, all of our Predecessor preferred stock was canceled upon our emergence from bankruptcy on the Emergence
Date. As of December 31, 2018 and December 31, 2017, there were 5,000,000 Successor shares of preferred stock authorized with none issued
or outstanding.
Common Stock
As discussed in Note 4, all our Predecessor common stock was canceled upon our emergence from bankruptcy on the Emergence Date
and 14,992,018 shares of Successor Common Stock were issued with a par value of $0.01 per share. We have a total of 45,000,000 shares
authorized. We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable
future. In addition, our Credit Facility and Second Lien Facility have restrictive covenants that limit our ability to pay dividends.
Accumulated Other Comprehensive Income
Accumulated other comprehensive income and losses are entirely attributable to our pension and postretirement health care benefit
obligations. The accumulated other comprehensive income, net of tax, was less than $0.1 million for all periods presented.
Treasury Stock
Shares of our Predecessor common stock held by the SERP and Predecessor deferred common stock units that had not been converted
into Predecessor common stock were previously presented for financial reporting purposes as treasury stock carried at cost. As discussed above,
all of the Predecessor common stock held by the SERP and Predecessor deferred common stock units were canceled upon our emergence from
bankruptcy on the Emergence Date.
17. Share-Based Compensation and Other Benefit
Plans
We recognize share-based compensation expense related to our share-based compensation plans as a component of “General and
administrative” expense in our Consolidated Statements of Operations.
We reserved 749,600 shares of Successor Common Stock for issuance under the Penn Virginia Corporation Management Incentive Plan
for future share-based compensation awards. A total of 347,440 time-vested restricted stock units (“RSUs”) and 98,526 performance restricted
stock units (“PRSUs”) have been granted as of December 31, 2018.
98
In the Predecessor period in 2016, we had outstanding equity-classified awards in the form of stock options, restricted stock units and
deferred stock units. As discussed in Note 4, all Predecessor equity-classified share-based compensation awards were canceled in connection
with our emergence from bankruptcy.
With the exception of our Predecessor performance-based restricted stock units (“Predecessor PBRSUs”), all of our Successor and
Predecessor share-based compensation awards are classified as equity instruments because they result in the issuance of common stock on the
date of grant, upon exercise or are otherwise payable in common stock upon vesting, as applicable. The compensation cost attributable to these
awards has been measured at the grant date and recognized over the applicable vesting periods as a non-cash item of expense. Because the
Predecessor PBRSUs were payable in cash, they were considered liability-classified awards and were included in “Accounts payable and accrued
liabilities” (current portion) and “Other liabilities” (noncurrent portion) on the Consolidated Balance Sheets of the Predecessor. Compensation
cost associated with the Predecessor PBRSUs was measured at the end of each reporting period and recognized based on the period of time that
had elapsed during each of the individual performance periods.
The following table summarizes our share-based compensation expense (benefit) recognized for the periods presented:
Successor
Predecessor
September 13 Through
January 1 Through
Year Ended December 31,
September 30,
September 12,
2018
2017
2016
2016
$
$
4,618 $
—
4,618 $
3,809 $
—
3,809 $
81 $
81 $
1,511
(19 )
1,492
Equity-classified awards
Liability-classified awards
Stock Options
The exercise price of all stock options granted under our Predecessor incentive compensation plans was equal to the fair value of our
common stock on the date of the grant. Options could be exercised at any time after vesting and prior to ten years following the date of grant.
Options vested upon terms established by the compensation and benefits committee of our Predecessor board of directors. Generally, options
vested over a three-year period, with one-third vesting in each year. In connection with our emergence from bankruptcy, all stock options
outstanding as of September 12, 2016 were canceled.
Time-Vested Restricted Stock Units
A restricted stock unit entitles the grantee to receive a share of common stock upon the vesting of the restricted stock unit. The grant date
fair value of our time-vested restricted stock unit awards are recognized on a straight-line basis over the applicable vesting period.
The following table summarizes activity for our most recent fiscal year with respect to awarded RSUs:
Balance at beginning of year
Granted
Vested
Forfeited
Balance at end of year
Restricted Stock
Units
Weighted-Average
Grant Date
Fair Value
259,990
42,459
(79,828 )
(14,581 )
208,040
$
$
$
$
$
41.32
65.96
38.90
43.64
47.35
As of December 31, 2018, we had $7.8 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be
recognized over a weighted-average period of 1.5 years. The total grant-date fair values of RSUs that vested in 2018 and 2017 was $3.3 million
and $0.8 million, respectively. No RSUs vested during 2016. In connection with our emergence from bankruptcy, all Predecessor RSUs
outstanding as of September 12, 2016 were canceled.
Predecessor Performance-Based Restricted Stock Units
In each of the years ended December 31, 2015, 2014 and 2013, we granted Predecessor PBRSUs to certain executive officers. Vested
Predecessor PBRSUs were payable solely in cash on the third anniversary of the date of grant based upon the achievement of specified market-
based performance metrics with respect to each of a one-year, two-year and three-year performance period, in each case commencing on the
date of grant. The number of Predecessor PBRSUs vested ranged from 0% to 200% of the initial grant. The Predecessor PBRSUs did not have
voting rights and did not participate in dividends. In connection with our emergence of bankruptcy, all Predecessor PBRSUs outstanding as of
September 12, 2016 were canceled.
99
Successor Performance Restricted Stock Units
In the year ended December 31, 2017, we granted 98,526 PRSUs to members of our management. There were no PRSUs granted for the
year ended December 31, 2018. The PRSUs were issued collectively in two to three separate tranches with individual three-year performance
periods beginning in January 2017, 2018 and 2019, respectively. Vesting of the PRSUs can range from zero to 200% of the original grant based
on the performance of our common stock relative to an industry index. Due to their market condition, the PRSUs are being charged to expense
using graded vesting over a maximum of five years. The fair value of each PRSU award was estimated on their grant dates using a Monte Carlo
simulation with a range of $47.70 to $65.28 per PRSU.
The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2017 are presented as follows:
Expected volatility
Dividend yield
Risk-free interest rate
The following table summarizes activity for our most recent fiscal year with respect to PRSUs:
59.63% to 62.18%
0.0% to 0.0%
1.44% to 1.51%
Performance
Restricted Stock
Units
Weighted-Average
Fair Value
Balance at beginning of year
Granted
Vested
Forfeited
Balance at end of year
Defined Contribution Plan
98,526
$
— $
$
$
$
(1,968 )
(7,487 )
89,071
57.81
—
49.56
49.56
58.69
We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution
plan, which covers substantially all of our employees. We provide matching contributions on our employees’ elective deferral contributions up
to six percent of compensation up to the maximum statutory limits. The 401(k) Plan also provides for discretionary employer contributions. The
expense recognized with respect to the 401(k) Plan was $0.6 million, $0.5 million, $0.1 million and $0.5 million for the years ended
December 31, 2018 and 2017, the Successor period from September 13, 2016 through December 31, 2016, and the Predecessor period from
January 1, 2016 through September 12, 2016, respectively, and is included as a component of “General and administrative expenses” in our
Statements of Operations. Amounts representing accrued obligations to the 401(k) Plan of $0.3 million and $0.2 million are included in the
“Accounts payable and accrued expenses” caption on our Consolidated Balance Sheets as of December 31, 2018 and 2017, respectively.
Defined Benefit Pension and Postretirement Health Care Plans
We maintain unqualified legacy defined benefit pension and defined benefit postretirement health care plans which cover a limited
population of former employees that retired prior to January 1, 2000. The combined expense recognized with respect to these plans was less than
$0.1 million, $0.1 million, less than $0.1 million and less than $0.1 million for the years ended December 31, 2018 and 2017, the Successor
period from September 13, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through September 12, 2016,
respectively, and is included as a component of “General and administrative expenses” in our Statements of Operations. The combined unfunded
benefit obligations under these plans were $1.4 million and are included within the “Accounts payable and accrued expenses” (current portion)
and “Other liabilities” (noncurrent) captions on our Consolidated Balance Sheets as of December 31, 2018 and 2017.
100
18. Interest
Expense
The following table summarizes the components of interest expense for the periods presented:
Successor
Predecessor
September 13 Through
January 1 Through
Year Ended December 31,
December 31,
2018
2017
2016
December 31,
2016
Interest on borrowings and related fees 1
Accretion of original issue discount 2
Amortization of debt issuance costs 3
Capitalized interest
$
$
32,164 $
680
2,736
(9,118)
26,462 $
6,995 $
161
1,961
(2,725)
6,392 $
$
678
—
226
(25 )
879
$
36,012
—
22,189
(183 )
58,018
_____________________________________________
1 Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense
of $66.1 million for the Predecessor period from January 1, 2016 through September 12, 2016, including $ 15.3 million attributable to the 2019 Senior Notes and $ 46.3
million attributable to the 2020 Senior Notes.
2 Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 10).
3 The year ended December 31, 2017 includes a total of $0.8 million of write-offs attributable to changes in the composition of financial institutions comprising the Credit
Facility’s bank group in connection with amendments to the Credit Facility (see Note 10). The Predecessor period from January 1, 2016 through September 12, 2016
includes $20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes (see Note 10).
19. Earnings per
Share
The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share utilizing
the two-class method for the periods presented:
Successor
Predecessor
September 13 Through
January 1 Through
Year Ended December 31,
December 31,
September 12,
2018
2017
2016
2016
224,785 $
—
32,662 $
—
(5,296 ) $
—
1,054,602
(5,972 )
224,785 $
32,662 $
(5,296 ) $
1,048,630
Net income (loss)
Less: Preferred stock dividends
Net income (loss) attributable to common
shareholders – basic and diluted
$
$
Weighted-average shares – basic
Effect of dilutive securities 1
Weighted-average shares – diluted
_____________________________________________
1 For the period from September 13, 2016 through December 31, 2016, less than 0.1 million potentially dilutive securities, represented by RSUs, had the effect of being anti-
15,059
233
15,292
14,996
67
15,063
14,992
—
14,992
88,013
36,074
124,087
dilutive and were excluded from the calculation of diluted earnings per common share.
101
Supplemental Quarterly Financial Information (Unaudited)
2018
Revenues 1
Operating income
Income (loss) attributable to common shareholders 2
Income (loss) per share – basic 3
Income (loss) per share – diluted 3
Weighted-average shares outstanding:
Basic
Diluted
2017
Revenues 4
Operating income
Income (loss) attributable to common shareholders
Income (loss) per share – basic 3
Income (loss) per share – diluted 3
Weighted-average shares outstanding:
Basic
Diluted
$
$
$
$
$
$
$
$
$
$
First
Quarter
Second
Quarter
Third Quarter
Fourth
Quarter
77,211 $
33,912 $
10,295 $
0.68 $
0.68 $
15,042
15,081
111,580 $
55,886 $
(2,521) $
(0.17 ) $
(0.17 ) $
127,185 $
64,036 $
16,276 $
1.08 $
1.06 $
15,058
15,058
15,062
15,344
124,856
54,921
200,735
13.32
13.10
15,075
15,328
First
Quarter
Second
Quarter
Third Quarter
Fourth
Quarter
34,986 $
11,623 $
28,081 $
1.87 $
1.86 $
14,992
15,126
36,282 $
11,460 $
21,329 $
1.42 $
1.42 $
14,992
15,050
34,459 $
7,547 $
(5,947) $
(0.40 ) $
(0.40 ) $
14,994
14,994
54,327
21,242
(10,801 )
(0.72 )
(0.72 )
15,006
15,006
_____________________________________________
1 Includes gains (losses) on sales of assets of less than $0.1 million, less than $0.1 million, less than $0.1 million and $(0.3) million during the quarters ended March 31,
2018, June 30, 2018, September 30, 2018 and December 31, 2018, respectively.
2 The quarter ended December 31, 2018 includes a mark-to-market gain on derivatives of $149.2 million.
3 The sum of the quarters may not equal the total of the respective year’s earnings per common share due to changes in weighted-average shares outstanding throughout the
year.
4 Includes gains (losses) on sales of assets of less than $0.1 million, $(0.1) million, less than $0.1 million and less than $0.1 million during the quarters ended March 31,
2017, June 30, 2017, September 30, 2017 and December 31, 2017, respectively.
102
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Oil and Gas Reserves
All of our proved oil and gas reserves are located in the continental United States. The estimates of our proved oil and gas reserves were
prepared by our independent third party engineers, DeGolyer and MacNaughton, Inc. utilizing data compiled by us. DeGolyer and
MacNaughton, Inc. is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists. Our Vice President,
Engineering is primarily responsible for overseeing the preparation of the reserve estimate by DeGolyer and MacNaughton, Inc.
Reserve engineering is a process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner, and
the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
The quantities of crude oil, NGLs and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future
development expenditures and future prices for these commodities may all differ from those assumed. In addition, reserve estimates of new
discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as
additional information becomes available.
The following table sets forth our estimate of net quantities of proved reserves, including changes therein and proved developed and
proved undeveloped reserves for the periods presented:
Proved Developed and Undeveloped Reserves
December 31, 2015 (Predecessor)
Revisions of previous estimates
Extensions and discoveries
Production
December 31, 2016 (Successor)
Revisions of previous estimates
Extensions and discoveries
Production
Purchase of reserves
December 31, 2017 (Successor)
Revisions of previous estimates
Extensions and discoveries
Production
Purchase of reserves
Sale of reserves in place
December 31, 2018 (Successor)
Proved Developed Reserves:
December 31, 2016
December 31, 2017
December 31, 2018
Proved Undeveloped Reserves:
December 31, 2016
December 31, 2017
December 31, 2018
Oil
(MBbl)
NGLs
(MBbl)
Natural
Gas
(MMcf)
Total
Equivalents
(MBOE)
7,204
(1,225)
1,483
(697)
6,765
(2,071)
3,571
(523)
1,122
8,864
(1,789)
11,737
(1,004)
969
(733)
18,044
4,335
4,882
6,279
2,430
3,982
11,765
42,153
(8,661)
7,196
(4,006)
36,682
(10,468 )
16,840
(2,949)
7,162
47,267
(9,608)
59,447
(5,181)
5,827
(6,259)
91,493
24,899
27,229
31,833
11,783
20,038
59,660
43,691
(4,028)
14,213
(4,386)
49,490
(9,550)
30,228
(3,779)
6,183
72,572
(22,487 )
69,764
(7,944)
13,218
(2,173)
122,950
26,219
31,832
46,774
23,271
40,740
76,176
29,462
(1,359)
11,529
(3,021)
36,611
(5,735)
23,850
(2,764)
3,867
55,829
(19,096 )
48,119
(6,077)
11,278
(397)
89,656
17,734
22,412
35,190
18,877
33,417
54,466
103
The following is a discussion and analysis of the significant changes in our proved reserve estimates for the periods presented:
Year Ended December 31, 2018
In 2018, our proved reserves increased by 50.4 MMBOE. The overall increase over our proved reserves at the end of 2017 is due
primarily to a significant shift in our development plans from the northwest portion of our acreage position in the Eagle Ford to the southeast
region. The performance of our wells drilled in the southeast region in the first half of the year was the impetus to our redirecting of resources
and replication, to the extent practical, of our drilling and completion design techniques for the second half of 2018. Of the 53 gross wells we
drilled in 2018, 19 gross wells were not proved undeveloped locations at the end of 2017. Accordingly, our five-year drilling plan is heavily
weighted to the southeast region.
We had downward revisions of 22.5 MMBOE including: (i) 21.1 MMBOE due to the loss of certain locations resulting from changes in
the drilling locations and timing attributable to our development plans as discussed above and (ii) 4.4 MMBOE due to well performance
partially offset by (iii) 1.2 MMBOE due to improved treatable lateral lengths in certain locations due primarily to reconfiguration of the planned
drilling units and (iv) 1.8 MMBOE of other changes, primarily price-related. Extensions and discoveries of 69.8 MMBOE are substantially
attributable to geographical shift in our development plan, greater utilization of extended reach laterals, increasing the length of such laterals,
higher EUR estimates per lateral foot and higher net revenue interests due to the Hunt Acquisition. We acquired 13.2 MMBOE in connection
with the Hunt Acquisition and we sold 2.2 MMBOE in connection with our exit from the Mid-Continent region.
Year Ended December 31, 2017
We had downward revisions of 9.6 MMBOE as a result of the following: (i) downward revisions of 6.5 MMBOE due primarily to
reduced treatable lateral lengths in certain locations due primarily to reconfiguration of the planned drilling units partially offset by improved
performance, (ii) downward revisions of 4.7 MMBOE to our proved undeveloped reserves due to the loss of certain locations resulting from
changes in the timing and drilling locations attributable to our development plans partially offset by (iii) 1.6 MMBOE due to improved well
performance. Extensions and discoveries of 30.2 MMBOE are entirely attributable to our expanded development plan including adding a third
rig to our drilling program and the corresponding increase in the number of drilling locations that we are planning to drill in the next five years.
We acquired 6.2 MMBOE in connection with the Devon Acquisition. An additional 1.0 MMBOE attributable to the Devon Acquisition was
determined in our year-end assessment consistent with our development plans and is included in the aforementioned extensions and discoveries.
Year Ended December 31, 2016
We had downward revisions of 4.0 MMBOE primarily as a result of the following: (i) revisions of 1.7 MMBOE due to lower EURs for
natural gas and NGLs net of higher expected crude oil recoveries attributable to our existing and new Eagle Ford wells, (ii) revisions of 1.3
MMBOE to our proved undeveloped reserves due to the loss of certain locations resulting from changes in the timing of our development plans
and lower EURs, (iii) revisions of 0.7 MMBOE (Granite Wash - 0.4 MMBOE and Eagle Ford 0.3 MMBOE) due to lower commodity prices
compared to year-end 2015 and (iv) revisions of 0.3 MMBOE to our Granite Wash wells due to well performance. Extensions and discoveries of
14.2 MMBOE for our proved undeveloped reserves were attributable to the resumption of our development plans.
Capitalized Costs Relating to Oil and Gas Producing Activities
The following table sets forth capitalized costs related to our oil and gas producing activities and accumulated DD&A for the periods
presented:
Oil and gas properties:
Proved
Unproved
Total oil and gas properties
Other property and equipment
Total capitalized costs relating to oil and gas producing activities
Accumulated depreciation and depletion
Net capitalized costs relating to oil and gas producing activities 1
December 31,
2018
2017
2016
$
$
1,037,993 $
63,484
1,101,477
16,462
1,117,939
(191,802)
926,137 $
460,029 $
117,634
577,663
10,057
587,720
(60,247 )
527,473 $
251,083
4,719
255,802
1,230
257,032
(11,669 )
245,363
_____________________________________________
1 Excludes property and equipment attributable to our corporate operations which is comprised of certain capitalized hardware, software, leasehold improvements and office
furniture and fixtures.
104
Costs Incurred in Certain Oil and Gas Activities
The following table summarizes costs incurred in our oil and gas property acquisition, exploration and development activities for the
periods presented:
Development costs 1
Proved property acquisition costs 2
Unproved property acquisition costs 3
Exploration costs 4
Successor
Year Ended December 31,
2018
2017
$
$
416,037 $
86,514
30,637
377
533,565 $
135,360 $
43,151
153,905
696
333,112 $
September 13
Through
December 31,
2016
Predecessor
January 1
Through
September 12,
2016
5,399 $
53
25
567
6,044 $
4,777
—
183
8,311
13,271
_____________________________________________
1 Includes plugging and abandonment asset additions for all periods presented and capitalized internal costs for the Successor periods during which time we have applied the
full cost method of accounting for oil and gas properties.
2 Includes proved properties and plugging and abandonment assets acquired in the Hunt and Devon Acquisitions during the years ended December 31, 2018 and 2017.
3 Includes capitalized interest for all periods presented and unproved properties acquired in the Hunt and Devon Acquisitions during the years ended December 31, 2018 and
2017.
4 Includes geological costs, geophysical costs (seismic) and delay rentals for all periods presented. Also includes: (i) drilling rig termination charges of $1.7 million, (ii) a $2.0
million charge for failure to complete a drilling carry commitment, (iii) a $0.6 million charge for unutilized coiled tubing services and (iv) a $4.0 million write-off of certain
uncompleted well costs during the Predecessor period ended September 12, 2016, all of which were charged to exploration expense during which time we applied the
successful efforts method of accounting for oil and gas properties.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Future cash inflows were computed by applying the average prices of oil and gas during the 12-month period prior to the period end,
determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period and estimated costs as of
that fiscal year end, to the estimated future production of proved reserves. Future prices actually received may materially differ from current
prices or the prices used in the standardized measure.
Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing
and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by
applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved reserves and the tax basis of proved
oil and gas properties. In addition, the effects of statutory depletion in excess of tax basis, available NOL carryforwards and alternative
minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a
10% annual rate.
The standardized measure of discounted future net cash flows is not intended, and should not be interpreted, to represent the fair value of
our oil and gas reserves. An estimate of the fair value would also consider, among other things, the recovery of reserves not presently classified
as proved, anticipated future changes in prices and cost, and a discount factor more representative of economic conditions and risks inherent in
reserve estimates. Accordingly, the changes in standardized measure reflected above do not necessarily represent the economic reality of such
transactions.
105
Crude oil and natural gas prices were based on average (beginning of month basis) sales prices per Bbl and MMBtu with the
representative price of natural gas adjusted for basis premium and energy content to arrive at the appropriate net price. NGL prices were
estimated as a percentage of the base crude oil price.
The following table summarizes the price measurements utilized, by product, with respect to our estimates of proved reserves as well as
in the determination of the standardized measure of the discounted future net cash flows for the periods presented:
As of December 31, 2016
As of December 31, 2017
As of December 31, 2018
Crude Oil
$ per Bbl
NGLs
$ per Bbl
Natural Gas
$ per MMBtu
$
$
$
42.75 $
51.34 $
65.56 $
12.33 $
18.48 $
23.60 $
2.48
2.98
3.10
The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved reserves for the
periods presented:
Future cash inflows
Future production costs
Future development costs
Future net cash flows before income tax
Future income tax expense
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
December 31,
2018
6,719,145 $
(1,852,168 )
(1,208,815 )
3,658,162
(413,137)
3,245,025
(1,621,135 )
1,623,890 $
2017
3,091,366 $
(1,069,910 )
(689,998)
1,331,458
(84,350 )
1,247,108
(656,624)
590,484 $
2016
1,667,971
(673,538)
(327,213)
667,220
—
667,220
(349,670)
317,550
$
$
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following table summarizes the changes in the standardized measure of the discounted future net cash flows attributable to our
proved reserves for the periods presented:
Sales of oil and gas, net of production costs
Net changes in prices and production costs
Changes in future development costs
Extensions and discoveries
Development costs incurred during the period
Revisions of previous quantity estimates
Purchases of reserves-in-place
Sale of reserves-in-place
Changes in production rates and all other
Accretion of discount
Net change in income taxes
Net increase (decrease)
Beginning of year
End of year
Year Ended December 31,
2018
2017
2016
$
$
(361,478) $
585,737
206,901
809,880
204,160
(483,091)
86,128
(8,912)
60,160
60,897
(126,976)
1,033,406
590,484
1,623,890 $
(118,137) $
170,488
30,692
131,060
74,880
(122,357)
80,878
—
12,161
31,755
(18,486 )
272,934
317,550
590,484 $
(89,080 )
(11,971 )
59,266
35,321
6,775
(38,151 )
—
—
(252)
32,331
—
(5,761)
323,311
317,550
106
Item 9
Changes in and Disagreements With Accountants on Accounting and Financial
Disclosure
Not applicable.
Item 9A
Controls and
Procedures
(a) Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of our
disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of December 31, 2018. Our disclosure controls and
procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is
recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms,
and that such information is accumulated and communicated to the issuer’s management, including our Chief Executive Officer and our Chief
Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer
and our Chief Financial Officer concluded that, as of December 31, 2018, such disclosure controls and procedures were effective.
(b) Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over our financial reporting. Our management
assessed the effectiveness of our internal control over financial reporting as of December 31, 2018. This evaluation was completed based on the
framework established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
Based on that assessment, our management has concluded that, as of December 31, 2018, our internal control over financial reporting was
effective.
(c) Attestation Report of the Registered Public Accounting Firm
Grant Thornton LLP, the independent registered public accounting firm that audited and reported on the consolidated financial statements
contained in this Form 10-K, has issued an attestation report on the internal control over financial reporting as of December 31, 2018, which is
included in Item 8 of this Annual Report on Form 10-K.
(d) Changes in Internal Control Over Financial Reporting
No changes were made in our internal control over financial reporting that occurred during our last fiscal quarter that have materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B
Other
Information
None.
107
Item 10
Directors, Executive Officers and Corporate
Governance
Part III
Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.
We have adopted a Code of Business Conduct and Ethics that applies to all of our directors, officer and employees,
including our principal executive, principal financial and principal accounting officers, or persons performing similar
functions. Our Code of Business Conduct and Ethics is posted on our website located at https://ir.pennvirginia.com/governance-docs. We intend
to disclose future amendments to certain provisions of the Code of Business Conduct and Ethics, and waivers of the Code of Business Conduct
and Ethics granted to executive officers and directors, on the website within four business days following the date of the amendment or waiver.
Item 11
Executive
Compensation
Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.
Item 13
Certain Relationships and Related Transactions, and Director
Independence
Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.
Item 14
Principal Accountant Fees and
Services
Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.
108
Item 15 Exhibits and Financial Statement Schedules
The following documents are included as exhibits to this Annual Report on Form 10-K. Those exhibits incorporated by reference are
indicated as such in the parenthetical following the description. All other exhibits are included herewith.
Part IV
(1)
(2.1)
(2.2)
(2.3)
(3.1)
(3.2)
(10.1)
(10.1.1)
(10.1.2)
(10.1.3)
(10.1.4)
(10.1.5)
(10.2)
(10.3)
(10.4)
(10.5)
Financial Statements — The financial statements filed herewith are listed in the Index to Consolidated Financial Statements on page 65 of
this Annual Report on Form 10-K.
Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and Its Debtor Affiliates (Technical
Modifications) filed pursuant to Chapter 11 of the United States Bankruptcy Code filed on August 10, 2016 with the United States
Bankruptcy Court for the Eastern Division of Virginia, Richmond Division (incorporated by reference to Exhibit 2.1 to Registrant’s
Current Report on Form 8-K filed on August 17, 2016).
Disclosure Statement for the First Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and Its Debtor
Affiliates and Amended Exhibits Thereto filed pursuant to Chapter 11 of the United States Bankruptcy Code filed on June 24, 2016 with
the United States Bankruptcy Court for the Eastern Division of Virginia, Richmond Division (incorporated by reference to Exhibit 2.2 to
Registrant’s Current Report on Form 8-K filed on August 17, 2016).
Agreement and Plan of Merger dated as of October 28, 2018, by and among Denbury Resources Inc, Dragon Merger Sub Inc, DR Sub
LLC Sub and Penn Virginia Corporation (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on
October 29, 2018).
Second Amended and Restated Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to
Registrant’s Current Report on Form 8-K filed on September 15, 2016).
Third Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registran t’s Current
Report on Form 8-K filed on January 19, 2018).
Credit Agreement, dated as of September 12, 2016, by and among Penn Virginia Holding Corp., Penn Virginia Corporation, the lenders
party thereto and Wells Fargo Bank, National Association, as administrative agent and issuing lender (incorporated by reference to
Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on September 15, 2016).
Amendment No. 1 to Credit Agreement dated as of March 10, 2017 among Penn Virginia Holding Corp., Penn Virginia Corporation, the
guarantors and lenders party thereto and Wells Fargo Bank, National Association, as administrative agent and issuing lender (incorporated
by reference to Exhibit 10.1.1 to Registrant’s Registration Statement on Form S-3/A (Amendment No. 2) filed on May 2, 2017).
Master Assignment, Agreement and Amendment No. 2 to Credit Agreement dated as of June 27, 2017 among Penn Virginia Holding
Corp., as borrower, Penn Virginia Corporation, as parent, the subsidiaries of the borrower party thereto, the lenders and New Lenders
party thereto and Wells Fargo Bank, National Association, as administrative agent and issuing lender (incorporated by reference to
Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on June 30, 2017).
Master Assignment, Agreement and Amendment No. 3 to Credit Agreement dated as of September 29, 2017 among Penn Virginia
Holding Corp., as borrower, Penn Virginia Corporation, as parent, the subsidiaries of the borrower party thereto, the lenders party thereto
and Wells Fargo Bank, National Association, as administrative agent and issuing lender (incorporated by reference to Exhibit 10.1 to
Registrant’s Current Report on Form 8-K filed on October 5, 2017).
Master Assignment, Agreement and Amendment No. 4 to Credit Agreement, dated as of March 1, 2018, among Penn Virginia Holding
Corp., as borrower, Penn Virginia Corporation, as parent, the subsidiaries of the borrower party thereto, the lenders party thereto and
Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report
on Form 8-K filed on March 7, 2018).
Borrowing Base Increase Agreement and Amendment No. 5 to Credit Agreement dated as of October 26, 2018 among Penn Virginia
Holding Corp., as borrower, Penn Virginia Corporation, as parent, the subsidiaries of the borrower party thereto, the lenders party thereto
and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current
Report on Form 8-K filed on October 26, 2018).
Pledge and Security Agreement, dated as of September 12, 2016, by Penn Virginia Holding Corp., Penn Virginia Corporation and the
other grantors party thereto in favor of Wells Fargo Bank, National Association, as administrative agent for the benefit of the secured
parties thereunder (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on September 15, 2016).
Registration Rights Agreement, dated as of September 12, 2016 between Penn Virginia Corporation and the holders party thereto
(incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed on September 15, 2016).
Credit Agreement, dated as of September 29, 2017, by and among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation,
the lenders party thereto and Jefferies Finance LLC, as administrative agent, collateral agent and sole lead arranger (incorporated by
reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on October 5, 2017).
Pledge and Security Agreement, dated as of September 29, 2017, by Penn Virginia Holding Corp., Penn Virginia Corporation and the
other grantors party thereto in favor of Jefferies Finance LLC, as administrative agent and collateral agent for the ratable benefit of the
secured parties thereunder (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed on October 5,
2017).
109
(10.6)
(10.7)
(10.8)
(10.9)
(10.9.1)
(10.9.2)
(10.9.3) #
(10.10)
(10.10.1) †
(10.11)*
(10.11.1)*
(10.11.2)*
(10.11.3)*
(10.11.4)*
(10.12)*
(10.13)*
(10.14)
(10.15)
(21.1) #
(23.1) #
(23.2) #
(31.1) #
(31.2) #
Intercreditor Agreement, dated as of September 29, 2017, by and among Penn Virginia Holding Corp., Penn Virginia Corporation, the
subsidiaries of Penn Virginia Holding Corp. party thereto, Wells Fargo Bank, National Association and Jefferies Finance LLC
(incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed on October 5, 2017).
Purchase and Sale Agreement by and between Devon Energy Production Company, L.P. as seller, and Penn Virginia Oil & Gas, L.P. as
buyer dated as of July 29, 2017 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q filed on
November 9, 2017).
Purchase and Sale Agreement by and between Hunt Oil Company and Penn Virginia Oil and Gas, L.P. dated December 30, 2017
(incorporated by reference to Exhibit 10.8 to Registrant’s Annual Report on Form 10-K filed on March 2, 2018).
Second Amended and Restated Construction and Field Gathering Agreement by and between Republic Midstream, LLC and Penn
Virginia Oil & Gas, L.P. dated August 1, 2016 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-
Q/A filed on November 28, 2016).
Amendment No. 1 to the Second Amended and Restated Construction and Field Gathering Agreement dated as of April 13, 2017 but
effective August 1, 2016 by and between Republic Midstream, LLC and Penn Virginia Oil & Gas, L.P. (incorporated by reference to
Exhibit 10.4.1 to Registrant’s Registration Statement on Form S-3/A (Amendment No. 2) filed on May 2, 2017).
Second Amendment to Second Amended and Restated Construction and Field Gathering Agreement dated as of July 2, 2018 by and
between Republic Midstream, LLC and Penn Virginia Oil & Gas L.P. (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly
Report on Form 10-Q filed on November 8, 2018).
Third Amendment to Second Amended and Restated Construction and Field Gathering Agreement dated as of December 14, 2018 by and
between Republic Midstream, LLC and Penn Virginia Oil & Gas L.P.
First Amended and Restated Crude Oil Marketing Agreement dated as of August 1, 2016, by and between Penn Virginia Oil & Gas, L.P.,
Republic Midstream Marketing, LLC and solely for purposes of Article V therein, Penn Virginia Corporation (incorporated by reference
to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q/A filed on November 28, 2016).
First Amendment to First Amended and Restated Crude Oil Marketing Agreement dated as of July 2, 2018 by and between Penn Virginia
Oil & Gas, L.P. and Republic Midstream Marketing, LLC.(incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on
Form 10-Q filed on November 8, 2018).
Penn Virginia Corporation 2016 Management Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrant ’s Current Report on
Form 8-K filed on October 11, 2016).
Form of Nonqualified Stock Option Award Agreement (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form
8-K filed on October 11, 2016).
Form of Officer Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.1 to Registrant ’s Current Report on
Form 8-K filed on January 30, 2017).
Form of Performance Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to Registrant ’s Current Report
on Form 8-K filed on January 30, 2017).
Form of Director Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.1 to Registrant ’s Current Report on Form
8-K filed on December 21, 2016).
Separation and Consulting Agreement dated January 18, 2018 by and among Penn Virginia Corporation and Harry Quarls (incorporated
by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on January 19, 2018).
Penn Virginia Corporation 2017 Special Severance Plan Amended and Restated Effective July 18, 2018 (incorporated by reference to
Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q filed on November 8, 2018).
Support Agreement, dated January 18, 2018 by and among Penn Virginia Corporation, Strategic Value Partners, LLC and certain funds
and accounts managed by Strategic Value Partners, LLC (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on
Form 8-K filed on January 19, 2018).
Form of Director Indemnification Agreement (incorporated by reference to Exhibit 10.6 to Registrant’s Current Report on Form 8-K filed
on October 11, 2016).
Subsidiaries of Penn Virginia Corporation.
Consent of Grant Thornton LLP.
Consent of DeGolyer and MacNaughton.
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification Pursuant to 18 Section 302 of the Sarbanes-Oxley Act of 2002.
(32.1) ††
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(32.2) ††
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(99.1) #
Report of DeGolyer and MacNaughton dated January 28, 2019 concerning evaluation of oil and gas reserves.
110
(101.INS)#
XBRL Instance Document
(101.SCH)# XBRL Taxonomy Extension Schema Document
(101.CAL)# XBRL Taxonomy Extension Calculation Linkbase Document
(101.DEF)#
XBRL Taxonomy Extension Definition Linkbase Document
(101.LAB)# XBRL Taxonomy Extension Label Linkbase Document
XBRL Taxonomy Extension Presentation Linkbase Document
(101.PRE)#
____________________
* Management contract or compensatory plan or
arrangement.
# Filed
herewith.
† Confidential treatment has been requested for this exhibit and confidential portions have been filed separately with the Securities and Exchange Commission.
††Furnished
herewith.
Item 16
Form 10-K
Summary
None.
111
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
February 27, 2019
PENN VIRGINIA CORPORATION
By:
By:
/s/ STEVEN A. HARTMAN
Steven A. Hartman
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ TAMMY L. HINKLE
Tammy L. Hinkle
Vice President and Controller
(Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf
of the Registrant and in the capacities and on the dates indicated.
/s/ JOHN A. BROOKS
John A. Brooks
/s/ STEVEN A. HARTMAN
Steven A. Hartman
Chief Executive Officer and Director
February 27, 2019
(Principal Executive Officer)
Senior Vice President and Chief Financial Officer
February 27, 2019
(Principal Financial Officer)
/s/ TAMMY L. HINKLE
Tammy L. Hinkle
Vice President and Controller
(Principal Accounting Officer)
February 27, 2109
/s/ DAVID GEENBERG
David Geenberg
/s/ MICHAEL HANNAH
Michael Hannah
/s/ DARIN G. HOLDERNESS
Darin G. Holderness
/s/ VICTOR F. POTTOW
Victor F. Pottow
/s/ JERRY R. SCHUYLER
Jerry R. Schuyler
Co-Chairman of the Board
February 27, 2109
Director
February 27, 2109
Co-Chairman of the Board
February 27, 2019
February 27, 2019
February 27, 2019
Director
Director
112
Exhibit 10.9.3
THIRD AMENDMENT TO SECOND AMENDED AND RESTATED
CONSTRUCTION AND FIELD GATHERING AGREEMENT
This Third Amendment to Second Amended and Restated Construction and Field Gathering Agreement (this
“Amendment”) is dated as of December 14, 2018 (the “ Execution Date”) by and between Republic Midstream, LLC, a
Delaware limited liability company (“Gatherer”), and Penn Virginia Oil & Gas, L.P., a Texas limited partnership
(“Shipper”). Gatherer and Shipper may hereinafter be referred to singularly as a “Party” and, together, as the “ Parties.”
WHEREAS, the Parties entered into that certain Second Amended and Restated Construction and Field
Gathering Agreement effective as of August 1, 2016 (as amended, the “Agreement”);
WHEREAS, the Parties entered into that First Amendment to Second Amended and Restated Construction and
Field Gathering Agreement, dated as of April 13, 2017;
WHEREAS, the Parties entered into that Second Amendment to Second Amended and Restated Construction
and Field Gathering Agreement, dated as of July 2, 2018; and
WHEREAS, the Parties desire to amend certain provisions of the Agreement;
NOW, THEREFORE, in consideration of the mutual covenants, terms and conditions herein contained, together
with other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and
intending to be legally bound hereby, the Parties, for themselves and for their successors and assigns, do hereby
mutually covenant and agree as follows:
A.
following definitions in appropriate alphabetical order:
Amendment of Definitions in Agreement. Article I of the Agreement is hereby amended by adding the
“Deedra Unit” means that certain 482.359 acre unit described in that certain Designation of Unit recorded in
Volume 672 and Page 432, Official Records of Lavaca County, Texas, as amended by that certain First
Amendment to Designation of Unit recorded in Volume 691 and Page 18, Official Records of Lavaca County,
Texas, and as amended by that certain Second Amendment to Designation of Unit recorded in Volume 781 and
Page 294, Official Records of Lavaca County, Texas, solely to the extent not included in the area identified on
the map attached hereto as Exhibit A-1. For the avoidance of doubt, the portion of the Deedra Unit within the
area identified on the map attached hereto as Exhibit A-1 constitutes an Interest and part of the Dedication Area
and remains subject to the dedication set forth in Article II and to the other provisions of this Agreement.
“Future Interests” means all interests that Shipper (or any of its Affiliates or any successor in interest resulting
from any merger, reorganization, consolidation or as part of a sale or other disposition of all or any portion of
such interests) now or hereinafter owns, controls, acquires or has the right to market (as such marketing rights
may change from time to time) in Crude Oil reserves of, and production from, all leases and mineral fee interests,
lands and formations (in each case) in, under or attributable to the Future Units, together with any pool,
communitized area or unit, and all interests in any wells, whether now existing or drilled hereafter, on or
completed within the Future Units, or within any such pool,
Exhibit 10.9.3
communitized area or unit, even though such interests may be incorrectly or incompletely stated, all as the same
shall be enlarged by the discharge of any burdens or by the removal of any charges or encumbrances to which
any of same maybe subject as of (x) with respect to the Carol Unit, Robin Unit, Marcia Unit and Shelly Unit,
July 2, 2018, and (y) with respect to the Deedra Unit, Nancy Unit and Lori Unit, December 14, 2018, and any
and all replacements, renewals and extensions or amendments of any of the same; provided, however, that
“Future Interests” shall not include (a) any Interests or (b) any interest of Shipper or any of its Affiliates that
must be offered to a third-party working interest partner pursuant to any applicable agreement with such partner
in effect on (1) with respect to the Carol Unit, Robin Unit, Marcia Unit and Shelly Unit, July 2, 2018, and (2)
with respect to the Deedra Unit, Nancy Unit and Lori Unit, December 14, 2018, and which such partner receives
or elects to receive, as applicable under the affected agreement.
“Future Units” means the Deedra Unit, Nancy Unit, Lori Unit, Carol Unit, Robin Unit, Marcia Unit and Shelly
Unit, collectively.
“Future Wells” means (a) with respect to the Carol Unit, Robin Unit, Marcia Unit and Shelly Unit, any new
wells drilled within the surface outline of such Future Units, and (b) with respect to the Deedra Unit, Nancy Unit
and Lori Unit, the entirety of any new wells with a surface location within the surface outline of such Future
Units. For the avoidance of doubt, the term “Future Wells” does not include the Other Wells.
“Lori Unit” means that certain 670.71 acre unit described in that certain Designation of Unit recorded in Volume
670 and Page 173, Official Records of Lavaca County, Texas, as amended by that certain Second Amendment to
Designation of Unit recorded in Volume 781 and Page 306, Official Records of Lavaca County, Texas.
“Nancy Unit” means that certain 693.52 acre unit described in that certain Designation of Unit recorded in
Volume 671 and Page 471, Official Records of Lavaca County, Texas, solely to the extent not included in the
area identified on the map attached hereto as Exhibit A-1. For the avoidance of doubt, the portion of the Nancy
Unit within the area identified on the map attached hereto as Exhibit A-1 constitutes an Interest and part of the
Dedication Area and remains subject to the dedication set forth in Article II and to the other provisions of this
Agreement.
B.
Waiver of Construction Notice.
(1)
(2)
For purposes of this Amendment, “ Deedra-Lori Initial Wells ” means the Deedra-Lori Unit 3 (SA) Well
3H and the Deedra-Lori Unit 4 (SA) Well 4H.
Gatherer hereby waives the obligation set forth in Section 3.3(g) of the Agreement for Shipper to deliver
a Construction Notice for the Deedra-Lori Initial Wells, and hereby agrees and elects to install an
Additional Segment to connect a Receipt Point for such Future Wells. Within 30 days after the date
hereof, Gatherer shall deliver to Shipper a Construction Plan in accordance with Section 3.3(b) of the
Agreement. The Parties acknowledge and agree that the “Expected Production Date” with respect to the
Deedra-Lori Initial Wells is March 11, 2019.
Exhibit 10.9.3
C.
read in its entirety as follows:
Amendment of Section 9.4 of Agreement . Section 9.4 of the Agreement is hereby amended and restated to
During the first thirty-six (36) Months of the Term, the aggregate Monthly Fees shall be subject to increase by
$0.04 per Barrel for every $1.00 that the Monthly average of the NYMEX West Texas Intermediate (“ WTI”)
crude price exceeds $50.00 per Barrel, with such increase being capped at a WTI crude price of $90.00. After the
first thirty-six (36) Months of the Term and for the remainder of the Term, the aggregate Monthly Fees shall
similarly be subject to increase by $0.04 per Barrel for every $1.00 that the Monthly average WTI crude price
exceeds $63.75 per Barrel, with such increase being capped at a WTI crude price of $90.00. The above-described
increases shall be offset by downward adjustments to reflect corresponding decreases to the WTI crude price
from time to time, provided that no downward adjustment shall be recognized for decreases below a WTI crude
price of (1) $50.00 during the first thirty-six (36) Months of the Term, and (2) $63.75 after the first thirty-six (36)
Months of the Term. Each of the foregoing increases or decreases shall be applied on a Monthly basis, and
calculated based on the Monthly average of the WTI crude price over the preceding Month. The adjustments set
forth in this Section 9.4 shall be referred to herein as the “Upside Adjustments”. For the avoidance of doubt, no
Upside Adjustment shall result in a Fee being decreased below the amount for such Fee set forth in Section 9.2,
after giving effect to any PPI Adjustment. Notwithstanding the foregoing, for any month in which Shipper
delivers an average of 20,000 or more Barrels of Oil per Day, the Upside Adjustment to the Truck Loading Fee
shall be waived for all Oil delivered to the Gathering System from Shipper's wells outside the Dedication Area.
D.
Ratification; Primacy. Except as expressly amended by this Amendment, all of the terms, provisions,
covenants and conditions contained in the Agreement remain in full force and effect; provided, if there is ever any
conflict between the Agreement and this Amendment, the terms, provisions, covenants and conditions contained in this
Amendment shall govern. The terms and provisions of the Agreement as amended by this Amendment are binding
upon and inure to the benefit of the Parties, their representatives, successors and assigns. As amended by this
Amendment, the Agreement is ratified and confirmed by the Parties, and declared to be a valid and enforceable
contract between them.
E.
Counterparts. This Amendment may be executed in as many counterparts as deemed necessary. When so
executed, the aggregate counterparts shall constitute one agreement and shall have the same effect as if all Parties
signing counterparts had executed the same instrument.
Amendment; Waiver. Neither this Amendment nor the Agreement may be amended or modified except
F.
pursuant to a written instrument signed by all of the Parties. Each Party may waive on its own behalf compliance by
any other Party with any term or provision hereof; provided, however, that any such waiver shall be in writing and shall
not bind the non-waiving Party. The waiver by any Party of a breach of any term or provision shall not be construed as
a waiver of any subsequent breach of the same or any other provision.
G.
and not by any one Party to the exclusion of the other.
Joint Preparation. The Parties agree and confirm that this Amendment was prepared jointly by all Parties
H.
No Third Party Beneficiaries. This Amendment is not intended to confer upon any person not a party hereto
any rights or remedies hereunder, and no person other than the Parties is entitled to rely on or enforce any provision
hereof.
I.
incorporated herein by this reference as if set out fully herein and shall apply in all respects to this Amendment.
Miscellaneous Provisions. The provisions of Articles XVII, XIX, XX and XXI of the Agreement are
[Signature Page Follows]
Exhibit 10.9.3
IN WITNESS WHEREOF, the Parties have executed this Amendment as of the day and year hereinabove first
written.
Exhibit 10.9.3
REPUBLIC MIDSTREAM, LLC
By: /s/ Daniel R. Revers
Revers
PENN VIRGINIA OIL & GAS, L.P.
By: Penn Virginia Oil & Gas GP LLC,
its general partner
Name: Daniel R.
Title: President
By: /s/ Jill T. Zivley
Land and Marketing
Name:Jill T. Zivley
Title: Vice President,
Subsidiaries of Penn Virginia Corporation
Exhibit 21.1
Name
Penn Virginia Holding Corp.
Penn Virginia Oil & Gas Corporation
Penn Virginia Oil & Gas, L.P.
Penn Virginia Oil & Gas GP LLC
Penn Virginia Oil & Gas LP LLC
Penn Virginia MC Corporation
Penn Virginia MC Energy L.L.C.
Penn Virginia MC Operating Company L.L.C
Penn Virginia MC Gathering Company L.L.C.
Penn Virginia Resource Holdings Corp.
Jurisdiction of Organization
Delaware
Virginia
Texas
Delaware
Delaware
Delaware
Delaware
Delaware
Oklahoma
Delaware
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have issued our reports dated February 27, 2019, with respect to the consolidated financial statements and internal control over
financial reporting included in the Annual Report of Penn Virginia Corporation on Form 10-K for the year ended December 31, 2018. We
consent to the incorporation by reference of said reports in the Registration Statements of Penn Virginia Corporation on Form S-3 (File
Nos. 333-214709 and 333-216756) and on Form S-8 (File No. 333-213979) and the Registration Statement of Denbury Resources Inc. on
Form S-4 (File No. 333-228935).
Exhibit 23.1
/s/ GRANT THORNTON LLP
Houston, Texas
February 27, 2019
Exhibit 23.2
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 26, 2019
Penn Virginia Corporation
16285 Park Ten Place
Suite 500
Houston, Texas 77084
Ladies and Gentlemen:
We hereby consent to the reference to DeGolyer and MacNaughton and to the incorporation of the estimates contained in our
report entitled “Report as of December 31, 2018 on Reserves and Revenue of Certain Properties with interests attributable to Penn Virginia
Corporation” (our Report) in Part I and in the “Notes to Consolidated Financial Statements” portion of the Annual Report on Form 10-K of
Penn Virginia Corporation for the year ended December 31, 2018 (the Annual Report), to be filed with the United States Securities and
Exchange Commission on or about February 27, 2019. In addition, we hereby consent to the incorporation by reference of our report of
third-party dated January 28, 2019, in the “Exhibits and Financial Statement Schedules” portion of the Annual Report. We further consent
to the incorporation by reference of references to DeGolyer and MacNaughton and to our Report in Penn Virginia Corporation’s
Registration Statements on Form S-3 (File Nos. 333-214709 and 333-216756) and Form S-8 (File No. 333-213979) and Denbury
Resources Inc.’s Registration Statement on Form S-4 (File No. 333-228935).
Very truly yours,
/s/DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
Exhibit 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John A. Brooks, Chief Executive Officer of Penn Virginia Corporation (the “Registrant”), certify that:
1. I have reviewed this Annual Report on Form 10-K of the Registrant (this “Report”);
2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with
respect to the period covered by this Report;
3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all
material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented
in this Report;
4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange
Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information relating to the Registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report
is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles;
(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this Report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by
this Report based on such evaluation; and
(d) Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during
the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the
Registrant’s internal control over financial reporting; and
5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial
reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors:
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and
report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
Registrant’s internal control over financial reporting.
Date: February 27, 2019
/s/ JOHN A. BROOKS
John A. Brooks
Chief Executive Officer
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 31.2
I, Steven A. Hartman, Senior Vice President and Chief Financial Officer of Penn Virginia Corporation (the “Registrant”), certify
that:
1. I have reviewed this Annual Report on Form 10-K of the Registrant (this “Report”);
2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with
respect to the period covered by this Report;
3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all
material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented
in this Report;
4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange
Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information relating to the Registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report
is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles;
(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this Report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by
this Report based on such evaluation; and
(d) Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during
the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the
Registrant’s internal control over financial reporting; and
5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial
reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors:
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and
report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
Registrant’s internal control over financial reporting.
Date: February 27, 2019
/s/ STEVEN A. HARTMAN
Steven A. Hartman
Senior Vice President and Chief Financial Officer
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32.1
In connection with the Annual Report of Penn Virginia Corporation (the “Company”) on Form 10-K for the year ended
December 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John A. Brooks, Chief
Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002, to the best of my knowledge, that:
1.
2.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934;
and
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
Date: February 27, 2019
/s/ JOHN A. BROOKS
John A. Brooks
Chief Executive Officer
This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original
of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to
the Securities and Exchange Commission or its staff upon request.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32.2
In connection with the Annual Report of Penn Virginia Corporation (the “Company”) on Form 10-K for the year ended
December 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Steven A. Hartman, Senior
Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:
1.
2.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934;
and
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
Date: February 27, 2019
/s/ STEVEN A. HARTMAN
Steven A. Hartman
Senior Vice President and Chief Financial Officer
This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original
of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to
the Securities and Exchange Commission or its staff upon request.
Exhibit 99.1
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
January 28, 2019
Penn Virginia Corporation
16285 Park Ten Place
Suite 500
Houston, Texas 77084
Ladies and Gentlemen:
Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2018, of the extent and
value of the estimated net proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which Penn Virginia
Corporation (Penn Virginia) has represented it holds an interest. This evaluation was completed on January 28, 2019. The properties
evaluated herein consist of working and royalty interests located in Texas. Penn Virginia has represented that these properties account for
100 percent on a net oil equivalent basis of Penn Virginia’s net proved reserves as of December 31, 2018. The net proved reserves
estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and
Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of
Regulation S–K and is to be used for inclusion in certain SEC filings by Penn Virginia.
Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum
remaining to be produced from these properties after December 31, 2018. Net reserves are defined as that portion of the gross reserves
attributable to the interests held by Penn Virginia after deducting all interests held by others.
Values for proved reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future
gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net
reserves. Future net revenue is calculated by deducting production taxes, ad valorem taxes, operating expenses, capital costs, and
abandonment costs from future gross revenue. Operating expenses include field operating expenses, transportation and processing expenses,
and an allocation of overhead that directly relates to production activities. Capital costs include drilling and completion costs, facilities
costs, and field maintenance costs. Abandonment costs are represented by Penn Virginia to be inclusive of those costs associated with the
removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment. At the request of Penn
Virginia, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net
revenue discounted at a specified arbitrary nominal discount rate of 10 percent compounded monthly over the expected period of
realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that
influence the prices at which properties are bought and sold.
Estimates of reserves and revenue should be regarded only as estimates that may change as production history and additional
information become available. Not only are such estimates based on that information which is currently available, but such estimates are
also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
Information used in the preparation of this report was obtained from Penn Virginia and from public sources. In the preparation of this
report we have relied, without independent verification, upon information furnished by Penn Virginia with respect to the property interests
being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements
relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A
field examination of the properties was not considered necessary for the purposes of this report.
Definition of Reserves
Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report.
Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of
the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating
conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the
analyses of production-decline curves, reserves
were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs
consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual
arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:
Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known
reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which
contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or
the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that
can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of
available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH)
as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower
contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for
an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,
engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a
whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable
technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B)
The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.
The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report,
determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless
prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is
relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is
by means not involving a well.
Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably
certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of
economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating
that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by
actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other
evidence using reliable technology establishing reasonable certainty.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and
techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices
generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)” and in Monograph 3
and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis
of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and
production history.
Based on the current stage of field development, production performance, the development plans provided by Penn Virginia, and
analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.
Penn Virginia has represented that its senior management is committed to the development plan provided by Penn Virginia and that
Penn Virginia has the financial capability to execute the development plan, including the drilling and completion of wells and the
installation of equipment and facilities.
A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the
evaluation of all reserves categories. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve
analysis, and (3) model-based analysis (if necessary, based on the availability of data). Production diagnostics include data quality control,
identification of flow regimes, and characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve
areas).
Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one
or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model‑based analysis may be
integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well performance, and
complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis was tempered by experience
with similar reservoirs, stage of development, quality and completeness of basic data, production history, and appropriate reserves
definitions.
In the evaluation of non-producing and undeveloped reserves, type-well analysis was performed using well data from analogous
reservoirs for which more complete historical performance data were available.
Data provided by Penn Virginia from wells drilled through December 31, 2018, and made available for this evaluation were used to
prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for
certain properties only through November 2018. Estimated cumulative production, as of December 31, 2018, was deducted from the
estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 1 month. All proved
developed reserves estimated herein are considered to be proved developed producing.
Oil and condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein
include C5+ and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions. NGL reserves are the result of
low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in barrels (bbl) representing 42
United States gallons per barrel. For reporting purposes, oil and condensate reserves have been estimated separately and are presented
herein as a summed quantity.
Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs,
measured at the point of delivery, after reduction for fuel use and shrinkage resulting from field separation and processing. Gas reserves
estimated herein are reported as sales gas. All gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a
pressure base of 14.65 pounds per square inch absolute (psia). Gas reserves included in this report are expressed in thousands of cubic feet
(Mcf).
Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial
reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial
reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions.
Gas quantities estimated herein include both associated and nonassociated gas.
At the request of Penn Virginia, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent
factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. This conversion factor was provided by Penn Virginia.
Primary Economic Assumptions
Revenue values in this report were estimated using initial prices, expenses, and costs provided by Penn Virginia. Future prices were
estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic
assumptions were used for estimating the revenue values reported herein:
Oil, Condensate, and NGL Prices
Penn Virginia has represented that the oil, condensate, and NGL prices were based on West Texas Intermediate (WTI) pricing,
calculated as the unweighted arithmetic average of the first‑day-of-the-month price for each month within the 12‑month period
prior to the end of the reporting period, unless prices are defined by contractual agreements. The oil, condensate, and NGL prices
were calculated using differentials furnished by Penn Virginia to the reference price of $65.56 per barrel and held constant
thereafter. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was
$66.72 per barrel of oil and condensate and $24.99 per barrel of NGL.
Gas Prices
Penn Virginia has represented that the gas prices were based on Henry Hub pricing, calculated as the unweighted arithmetic
average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period,
unless prices are defined by contractual agreements. The gas prices were calculated for each property using differentials
furnished by Penn Virginia to the reference price of $3.10 per million British thermal units ($/MMBtu) and held constant
thereafter. British thermal unit factors provided by Penn Virginia were used to convert prices from $/MMBtu to dollars per
thousand cubic feet. The volume-weighted average price attributable to the estimated proved reserves over the lives of the
properties was $3.132 per thousand cubic feet of gas.
Production and Ad Valorem Taxes
Production taxes were calculated using the tax rates for Texas, including, where appropriate, abatements for enhanced recovery
programs. Ad valorem taxes were calculated using rates provided by Penn Virginia based on recent payments.
Operating Expenses, Capital Costs, and Abandonment Costs
Estimates of operating expenses, provided by Penn Virginia and based on current expenses, were held constant for the lives of the
properties. Future capital expenditures were estimated using 2018 values, provided by Penn Virginia, and were not adjusted for
inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of
anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment
costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration
associated with the abandonment, were provided by Penn Virginia for all properties and were not adjusted for inflation. Operating
expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of non-
producing and undeveloped reserves estimated herein.
In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present
worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas of the properties evaluated by us
contained in this report has been prepared in accordance with Paragraphs 932‑235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-
235-50-30, and 932‑235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic
932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–
(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and
Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future
net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not
presented at the beginning of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as
engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or
sufficient therefor.
Summary of Conclusions
The estimated net proved reserves, as of December 31, 2018, of the properties evaluated herein were based on the definitions of
proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf),
thousands of barrels of oil equivalent (Mboe):
Estimated by DeGolyer and MacNaughton
Net Proved Reserves
as of December 31, 2018
Sales
Gas
(MMcf)
NGL
(Mbbl)
Oil and
Condensate
(Mbbl)
Oil
Equivalent
(Mboe)
Proved Developed Producing
Proved Developed Non-Producing
Total Proved Developed
Proved Undeveloped
Total Proved
35,190
0
35,190
54,466
6,279
0
31,833
0
46,775
0
6,279
31,833
46,775
11,765
59,661
76,174
89,656
18,044
91,494
122,950
Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy
equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.
The estimated future revenue to be derived from the production of the net proved reserves, as of December 31, 2018, of the
properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):
Proved
Developed
Producing
(M$)
Proved Developed
Non-Producing
(M$)
Total
Proved
Developed
(M$)
Proved
Undeveloped
(M$)
Total
Proved
(M$)
Future Gross Revenue
Production and Ad Valorem Taxes
Operating Expenses
Capital and Abandonment Costs
Future Net Revenue
Present Worth at 10 Percent
2,619,165
168,253
684,110
24,015
1,742,787
1,027,564
0
0
0
0
0
0
2,619,165
168,253
684,110
24,015
1,742,787
1,027,564
4,099,980
264,432
735,373
1,184,800
1,915,375
741,788
6,719,145
432,685
1,419,483
1,208,815
3,658,162
1,769,352
Note: Future income taxes have not been taken into account in the preparation of these estimates.
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s
ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31,
2018, estimated reserves.
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting
services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in
Penn Virginia. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Penn Virginia.
DeGolyer and MacNaughton has used all data, assumptions, procedures, and methods that it considers necessary to prepare this report.
Submitted,
Engineering Firm F-716
DeGOLYER and MacNAUGHTON Texas Registered
Gregory K. Graves, P.E.
Senior Vice President
DeGolyer and MacNaughton
CERTIFICATE of QUALIFICATION
I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas,
75244 U.S.A., hereby certify:
1.
2.
3.
That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to
Penn Virginia dated
January 28, 2019, and that I, as Senior Vice President, was responsible for the preparation of this report of third
party.
That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering
in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum
Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 34 years of experience in oil and gas
reservoir studies and reserves evaluations.
Gregory K. Graves, P.E.
Senior Vice President
DeGolyer and MacNaughton