Pursuant to Rule 12b-15 under the Exchange Act, this Amendment No. 1 also contains new certifications pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, which are attached hereto. No financial statements are included in this Amendment No. 1 and this Amendment No. 1 does not contain or amend any disclosure with respect to Items 307 and 308 of Regulation S-K. Further, because no financial statements are included in this Amendment No. 1, the Company is not including certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Glossary of Certain Industry Terminology
The following abbreviations, terms and definitions are commonly used in the oil and gas industry and are used within this Annual Report on Form 10-K.
Bbl. A standard barrel of 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
BOE. One barrel of oil equivalent with six thousand cubic feet of natural gas converted to one barrel of crude oil based on the estimated relative energy content.
BOEPD. Barrels of oil equivalent per day.
Borrowing base. The value assigned to a collection of borrower’s assets used by lenders to determine an initial and/or continuing amount for loans. In the case of oil and gas exploration and development companies, the borrowing base is generally based on proved developed reserves.
Completion. A process of treating a drilled well, including hydraulic fracturing among other stimulation processes, followed by the installation of permanent equipment for the production of oil or gas.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface temperature and pressure.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil or gas in sufficient commercial quantities to justify completion of the well.
EBITDAX. A measure of profitability utilized in the oil and gas industry representing earnings before interest, income taxes, depreciation, depletion, amortization and exploration expenses. EBITDAX is not a defined term or measure in generally accepted accounting principles, or GAAP (see below).
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.
EUR. Estimated ultimate reserves, the sum of reserves remaining as of a given date and cumulative production as of that date.
GAAP. Accounting principles generally accepted in the Unites States of America.
Gas lift. A method of artificial lift that uses an external source of high-pressure gas for supplementing formation gas for lifting the well fluids.
Gross acre or well. An acre or well in which a working interest is owned.
HBP. Held by production is a provision in an oil and gas or mineral lease that perpetuates the leaseholder’s right to operate the property as long as the property produces a minimum paying quantity of oil or gas.
Henry Hub. The Erath, Louisiana settlement point price for natural gas.
LIBOR. London Interbank Offered Rate.
LLS. Light Louisiana Sweet, a crude oil pricing index reference.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet of natural gas.
MEH. Magellan East Houston, a crude oil pricing index reference.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units, a measure of energy content.
MMcf. One million cubic feet of natural gas.
Nasdaq. The Nasdaq Global Select Market.
Net acre or well. The number of gross acres or wells multiplied by the owned working interest in such gross acres or wells.
NGL. Natural gas liquid.
NYMEX. New York Mercantile Exchange.
Operator. The entity responsible for the exploration and/or production of a lease or well.
Play. A geological formation with potential oil and gas reserves.
Productive wells. Wells that are not dry holes.
Proved reserves. Those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved developed reserves. Proved reserves that can be expected to be recovered: (a) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (b) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled.
PV10. A non-GAAP measure representing the present value of estimated future oil and gas revenues, net of estimated direct costs, discounted at an annual discount rate of 10%. PV10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for any GAAP measure. PV10 does not purport to represent the fair value of oil and gas properties.
Reservoir. A porous and permeable underground formation containing a natural accumulation of hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Revenue interest. An economic interest in production of hydrocarbons from a specified property.
Royalty interest. An interest in the production of a well entitling the owner to a share of production generally free of the costs of exploration, development and production.
SEC. United States Securities and Exchange Commission.
Service well. A well drilled or completed for the purpose of supporting production in an existing field.
Standardized measure. The present value, discounted at 10% per year, of estimated future cash inflows from the production of proved reserves, computed by applying prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves (except for consideration of future price changes to the extent provided by contractual arrangements in existence at year-end), reduced by estimated future development and production costs, computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year (including the settlement of asset retirement obligations), based on year-end costs and assuming continuation of existing economic conditions, further reduced by estimated future income tax expenses, computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the proved oil and gas reserves, less the tax basis of the properties involved and giving effect to the tax deductions and tax credits and allowances relating to the proved oil and gas reserves.
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.
Part III. OTHER INFORMATION
I
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Item 101 | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEBusiness |
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 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 87,400 net acres (as of December 31, 2019) 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 2019, our total production was comprised of 74 percent crude oil, 15 percent NGLs and 11 percent natural gas. Crude oil accounted for 93 percent of our product revenues. We generally sell our crude oil, NGL and natural gas products using short-term floating price physical and spot market contracts.
As of December 31, 2019, our total proved reserves were approximately 133 MMBOE, of which 42 percent were proved developed reserves and 74 percent were crude oil. As of December 31, 2019, we had 510 gross (430.1 net) productive wells, approximately 98 percent of which we operate, and leased approximately 100,200 gross (87,400 net) acres of leasehold and royalty interests, approximately 9 percent of which were undeveloped. Approximately 91 percent of our total acreage is HBP and includes a substantial number of undrilled locations. During 2019, we drilled and completed 48 gross (43.3 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.”
In 2018 and 2017 we completed the acquisition of certain oil and gas assets from Hunt Oil Company, or Hunt, and Devon Energy Corporation, or Devon, including oil and gas leases covering approximately 9,700 and 19,600 net acres located primarily in Gonzales and Lavaca Counties, Texas, respectively, or the Hunt and Devon Acquisitions. These acquisitions substantially expanded our Eagle Ford operations to their present scale. For a more detailed discussion of these transactions, 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 field gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production through February 2041 and February 2026, respectively, as well as volume capacity support for certain downstream interstate pipeline transportation.
Natural gas service contracts. We have an agreement that provides us with field gathering, compression and short-haul transportation services for a substantial portion of our natural gas production and gas lift for all of our hydrocarbon production until 2039.
Natural gas processing contracts. We have two agreements that provide us with services to process our wet gas production into NGL products and dry, or residue, gas. The more significant of these agreements extends through June 2029 while the other agreement, which represents a minor portion of our total processing requirements, is evergreen in term with either party having the right to terminate with 30-days’notice to the counterparty.
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, 2019, 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, 2019, approximately 76 percent of our consolidated product revenues were attributable to four customers: BP Products North America Inc.; Phillips 66 Company; Shell Trading (US) Company and Trafigura Trading LLC.
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.
Government Regulation and Environmental Matters
Our operations are subject to extensive federal, state and local laws and regulations that govern oil and gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. These laws, rules and regulations may, among other things:
require the acquisition of various permits before drilling commences;
require notice to stakeholders of proposed and ongoing operations;
require the installation of expensive pollution control equipment;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling and production and saltwater disposal activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources; and
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities for failure to comply. Violations and liabilities with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and cash flows. In certain instances, citizens or citizen groups also have the ability to bring legal proceedings against us if we are not in compliance with environmental laws or to challenge our ability to receive environmental permits that we need to operate. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of December 31, 2019, we have recorded asset retirement obligations of $4.9 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.
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 required 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; the EPA ultimately determined that a revision was not necessary. 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. In June 2017, the EPA and the Corps proposed a rule that would initiate the first step in a two-step process intended to review and revise the definition of WOTUS. Under the proposal, the first step would be to rescind the 2015 final rule and put back into effect the narrower language defining WOTUS under the Clean Water Act that existed prior to the rule. The second step would be a notice-and-comment rule-making in which the agencies will conduct a substantive reevaluation of the definition of WOTUS. In September 2019, the EPA finalized the first step in this process. In January 2020, the EPA finalized the second step in this process, finalizing a rule that narrowed the regulatory definition of WOTUS. Litigation challenging the repeal of the August 2015 rule is pending.
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 states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the Texas Railroad Commission, or TRC, adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. TRC has used this authority to deny permits for waste disposal wells. The potential adoption of federal, state and local legislation and regulations intended to address induced seismic activity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays.
We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells in which we act as operator. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional plays like the Eagle Ford formation, and is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The EPA also released the results of its comprehensive research study to investigate the potential adverse impacts of hydraulic fracturing on drinking water and ground water in December 2016, finding that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. These developments could establish an additional level of regulation, including a removal of the exemption for hydraulic fracturing from the SDWA, and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating and compliance costs and additional regulatory burdens that could make it more difficult or commercially impracticable for us to perform hydraulic fracturing. Such costs and burdens could delay the development of unconventional gas resources from shale formations, which are not commercially feasible without the use of hydraulic fracturing.
Chemical Disclosures Related to Hydraulic Fracturing. Texas has implemented chemical disclosure requirements for hydraulic fracturing operations. We currently disclose 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.
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 is in the process of finalizing the amendments, which it originally expected to do in late 2019. Separately, on August 28, 2019, the EPA proposed amendments to the 2012 and 2016 NSPS for the Oil and Natural Gas Industry that would remove all sources in the transmission and storage segment of the oil and natural gas industry from regulation under the NSPS, both for ozone-forming VOCs, and for “greenhouse gases,” or GHGs. The existing NSPS regulates GHGs through limitations on emissions of methane. The amendments also would rescind the methane requirements in the 2016 NSPS that apply to sources in the production and processing segments of the industry. As an alternative, the EPA also is proposing to rescind the methane requirements that apply to all sources in the oil and natural gas industry, without removing any sources from the current source category. The U.S. Bureau of Land Management, or BLM, finalized its own rules in November 2016 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements. The BLM 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 September 2018, the BLM announced 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 GHGs, present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of GHGs under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources.
Both in the United States and worldwide, there is increasing attention being paid to the issue of climate change and the contributing effect of GHG emissions. Most recently in April 2016, the United States signed the Paris Agreement, which requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in November 2019, the Trump administration formally moved to exit the Paris Agreement, initiating the treaty-mandated one-year process at the end of which the United States can officially exit the agreement. 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. In August 2019, the EPA finalized the repeal of the 2015 regulations and replaced them with the Affordable Clean Energy rule, or ACE, that designates heat rate improvement, or efficiency improvement, as the best system of emissions reduction for carbon dioxide from existing coal-fired electric utility generating units. Both the appropriateness of the repeal of the 2015 regulations and the adequacy of ACE are currently subject to litigation.
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.
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 94 employees as of December 31, 2019. 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, Audit Committee Charter, Compensation and Benefits Committee Charter, Nominating and Governance Committee Charter and Reserves Committee Charter, and we will provide copies of such documents to any shareholder who so requests. We also make available free of charge on or through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Investors can obtain current and important information about the company from our website on a regular basis. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we furnish or file with the SEC. We intend for our website to serve as a means of public dissemination of information for purposes of Regulation FD.
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 our General Business
Prices for crude oil, NGLs and natural gas are dependent on many factors that are beyond our control and strongly affect our financial condition, results of operations and cash flows.
Prices for crude oil, NGLs and natural gas are dependent on many factors that are beyond our control, including:
domestic and foreign supplies of crude oil, NGLs and natural gas;
domestic and foreign consumer demand for crude oil, NGLs and natural gas;
political and economic conditions in oil or gas producing regions;
the extent to which the members of the Organization of Petroleum Exporting Countries and other oil exporting nations agree upon and maintain production constraints and oil price controls;
overall domestic and foreign economic conditions, including adverse conditions driven by political, health or weather events;
prices and availability of, and demand for, alternative fuels;
the effect of energy conservation efforts, alternative fuel requirements and climate change-related initiatives;
shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil, natural gas and NGLs so as to minimize emissions of carbon dioxide and methane GHGs;
volatility and trading patterns in the commodity-futures markets;
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political and economic events that directly or indirectly impact the relative strength or weakness of the United States dollar, on which crude oil prices are benchmarked globally, against foreign currencies;
changes in trade relations and policies, including the imposition of tariffs by the United States or China;
risks related to the concentration of our operations in the Eagle Ford Shale field in South Texas;
speculation by investors in oil and gas;
the availability, cost, proximity and capacity of gathering, processing, refining and transportation facilities;
the cost and availability of products and personnel needed for us to produce oil and gas;
weather conditions;
the impact and uncertainty of world health events; and
domestic and foreign governmental relations, regulation and taxation, including limits on the United States’ ability to export crude oil.
The long-term effects of these and other conditions on the prices of oil and natural gas are uncertain, and there can be no assurance that the demand or pricing for our products will follow historic patterns or recover meaningfully in the near term. For example, oil and natural gas prices continued to be volatile in 2019, and the recent oil and gas industry downturn has (and current market conditions have) resulted in reduced demand for our products, which have had, and may in the future have, a material adverse impact on its financial condition, results of operations and cash flows. For example, the NYMEX oil prices in 2019 ranged from a high of $66.30 to a low of $46.54 per Bbl and the NYMEX natural gas prices in 2019 ranged from a high of $4.12 to a low of $1.82 per MMBtu. Further, the NYMEX oil prices and NYMEX natural gas prices ranged from highs to lows of $63.27 to $49.59 per Bbl and $2.17 to $1.85 per MMBtu, respectively, during the period from January 1, 2020 to February 14, 2020. 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, or sustained market uncertainty, in the actual prices of crude oil, NGLs or natural gas would have a material adverse effect on our business, financial position, results of operations, cash flows and borrowing capacity, stock price, the quantities of oil and gas reserves that we can economically produce, the quantity of estimated proved reserves that may be attributed to our properties and our ability to fund our capital program.
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;
risks associated with downspacing and multi-well pad drilling;
fracture stimulation accidents or failures;
reductions in oil, natural gas and NGL prices;
elevated pressure or irregularities in geologic formations;
loss of title or other title related issues;
equipment failures or accidents;
costs, shortages or delays in the availability of drilling rigs, frac fleets, crews, equipment and materials;
shortages in experienced labor;
crude oil, NGLs or natural gas gathering, transportation, processing, storage and export facility availability
restrictions or limitations;
surface access restrictions;
delays imposed by or resulting from compliance with regulatory requirements, including any hydraulic fracturing regulations and other applicable regulations, and the failure to secure or delays in securing necessary regulatory, contractual and third-party approvals and permits;
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
limited availability of financing at acceptable terms;
limitations in the market for crude oil, natural gas and NGLs;
fires, explosions, blow-outs and surface cratering;
adverse weather conditions; and
actions by third-party operators of our properties.
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.
Multi-well pad drilling and project development may result in volatility in our operating results.
We utilize multi-well pad drilling and project development where practical. Project development may involve more than one multi-well pad being drilled and completed at one time in a relatively confined area. Wells drilled on a pad or in a project may not be brought into production until all wells on the pad or project are drilled and completed. Problems affecting one pad or a single well could adversely affect production from all of the wells on the pad or in the entire project. As a result, multi-well pad drilling and project development can cause delays in the scheduled commencement of production, or interruptions in ongoing production. These delays or interruptions may cause declines or volatility in our operating results due to timing as well as declines in oil and natural gas prices. Further, any delay, reduction or curtailment of our development and producing operations, due to operational delays caused by multi-well pad drilling or project development, or otherwise, could result in the loss of acreage through lease expirations.
Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity.
We could experience adverse impacts associated with a high concentration of activity and tighter drilling spacing.
We are subject to drilling, completion and operating risks, including our ability to efficiently execute large-scale project development, as we could experience delays, curtailments and other adverse impacts associated with a high concentration of activity and tighter drilling spacing. A higher concentration of activity and tighter drilling spacing may increase the risk of unintentional communication with other adjacent wells and the potential to reduce total recoverable reserves from the reservoir. If these risks materialize and negatively impact our results of operations relative to guidance or market expectations, the research analysts who cover us may downgrade our common stock or change their recommendations or earnings or performance estimates, which may result in a decline in the market price of our common stock.
We may not adhere to our proposed drilling schedule.
Our final determination of whether to drill any wells will be dependent on a number of factors, including:
the results of our exploration efforts and the acquisition, review and analysis of the seismic data;
the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
the approval of the prospects by the other participants after additional data has been compiled;
economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and gas and the availability and prices of drilling rigs and crews, frac crews, and related equipment and material; and
the availability of leases and permits on reasonable terms for the prospects.
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.
We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third-party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs and frac crews at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. Shortages of drilling rigs, frac crews, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Our future performance depends on our ability to find or acquire additional oil and gas reserves that are economically recoverable.
Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and gas production and lower revenues and cash flows from operating activities. We must make substantial capital expenditures to find, acquire, develop and produce new oil and gas reserves. We may not be able to make the necessary capital investments to maintain or expand our oil and gas reserves with our cash flows from operating activities. Furthermore, external sources of capital may be limited.
The ability to attract and retain key members of management, qualified Board members and other key personnel is critical to the success of our business and may be challenging.
Our success will depend to a large extent upon the efforts and abilities of our management team and having experienced individuals serving on our Board who are also knowledgeable about our operations and our industry. We experienced turnover on our executive team and Board in both 2018 and 2019. If we experience similar turnover in the future, we may be unable to timely replace the talents and skills of our management team or directors if one or more did not continue serving. The success of our business also depends on other key personnel. The ability to attract and retain these key personnel may be difficult in light of the volatility of our business. We may need to enter into retention or other arrangements that could be costly to maintain. We do not maintain key-man life insurance with respect to any of our employees. Acquiring and keeping personnel could prove more difficult or cost substantially more than estimated. These factors could cause us to incur greater costs or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them adequately or in a timely manner and we could experience significant declines in productivity.
Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on the acreage.
Leases on oil and gas properties typically have a term after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. While we seek to actively manage our leasehold inventory through drilling wells to hold the leasehold acreage that we believe is material to our operations, our drilling plans for these areas are subject to change and subject to the availability of capital.
Certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that they own.
The drilling and production of potential locations by us or other operators could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells by us or other operators could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
We are exposed to the credit risk of our customers, and nonpayment or nonperformance by these parties would reduce our cash flows.
We are subject to risk from loss resulting from our customers’ nonperformance or nonpayment. We depend on a limited number of customers for a significant portion of our revenues. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly affect our overall credit risk. Recently, many of our customers’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payments or perform on their obligations to us. In 2019, approximately 76 percent of our total consolidated product revenues resulted from four 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.
Estimates of oil and gas reserves and future net cash flows are not precise, and undeveloped reserves may not ultimately be converted into proved producing reserves.
This Annual Report on Form 10-K contains estimates of our proved oil and gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various factors and assumptions, including assumptions relating to crude oil, NGL and natural gas prices, drilling and operating expenses, capital expenditures, development costs and workover and remedial costs, the quantity, quality and interpretation of relevant data, taxes and availability of funds. The process of estimating oil and gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent on many variables and inherently uncertain, therefore, changes often occur as these variables evolve and commodity prices fluctuate. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data, and improvements or other changes in geological, geophysical and engineering evaluation methods may cause reserve estimates to change over time. Any material inaccuracies in these reserve estimates, cash flow estimates or underlying assumptions could materially affect the estimated quantities and present value of our reserves.
Actual future production, crude oil, NGL and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by us. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil, NGL and natural gas prices and other factors, many of which are beyond our control.
At December 31, 2019, approximately 58 percent of our estimated proved reserves were proved undeveloped, compared to 62 percent at December 31, 2018. 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, 2019, includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $1,136 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, 2019, we wrote-off 32.1 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 based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. With all other factors held constant, if commodity prices used in the reserve report were to decrease by 10%, our standardized measure and PV-10 would have decreased to approximately $1,213.9 million and $1,304.6 million, respectively. Any adjustments to the estimates of proved reserves or decreases in the price of our commodities may decrease the value of our securities.
We may record impairments on our oil and gas properties.
Quantities of proved reserves are estimated based on economic conditions in existence in the period of assessment. Lower crude oil, NGL and natural gas prices may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all reserves within such fields, thus reducing proved property reserve estimates. If such revisions in the estimated quantities of proved reserves occur, it will have the effect of increasing the rates of depreciation, depletion and amortization, or DD&A, on the affected properties, which would decrease earnings or result in losses through higher DD&A expense. The revisions may also be significant enough to result in a write-down that would further decrease reported earnings.
The full cost method of accounting for oil and gas properties under GAAP requires that at the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated 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 $370 million in acquisition, exploration and development costs during the year ended December 31, 2019. We intend to finance our future capital expenditures, other than significant acquisitions, through cash flow from operations and, if necessary, through borrowings under our credit agreement (as defined below). However, our cash flow from operations and access to capital are subject to a number of variables, including: (i) the volume of oil and gas we are able to produce from existing wells, (ii) our ability to transport our oil and gas to market, (iii) the prices at which our commodities are sold, (iv) the costs of producing oil and gas, (v) global credit and securities markets, (vi) the ability and willingness of lenders and investors to provide capital and the cost of the capital, (vii) our ability to acquire, locate and produce new reserves, (viii) the impact of potential changes in our credit ratings and (ix) our proved reserves. Additionally, a negative shift in investor sentiment towards the oil and gas industry could adversely affect our ability to raise equity and debt capital.
We may not generate expected cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or anticipated levels. A decline in cash flow from operations or our financing needs may require us to revise our capital program or alter or increase our capitalization substantially through the issuance of debt or equity securities. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. Additional borrowings under our credit agreement or the issuance of additional debt securities will require that a greater portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. In addition, our credit agreements impose certain limitations on our ability to incur additional indebtedness. If we desire to issue additional debt securities other than as expressly permitted under our credit agreements, we will be required to seek the consent of the lenders in accordance with the requirements of our credit agreements, which consent may be withheld by the lenders at their discretion. In the future, we may not be able to obtain financing in sufficient amounts or on acceptable terms when needed, which could adversely affect our operating results and prospects. If we cannot raise the capital required to implement our business strategy, we may be required to curtail operations, which could adversely affect our financial condition, results of operations and cash flows.
Our property acquisitions carry significant risks.
Acquisition of oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive candidates, we may not be able to complete the acquisition or do so on commercially acceptable terms. In the event we do complete an acquisition, 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.
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.
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 $562.4 million of outstanding debt at December 31, 2019, including $362.4 million under the Company’s revolving 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) increasing our exposure to a rise in interest rates, which will generate greater interest expense, (v) limiting our ability to engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes and (vi) limiting our flexibility in planning for or reacting to changes in our business and industry in which we operate. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are out of our control.
Additionally, we may incur substantially more debt in the future. Our Credit Facility and the Second Lien Facility contain restrictions that limit our ability to incur indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. If we were to incur additional indebtedness without retiring existing debt, the risks described above could be magnified.
The borrowing base under our credit facility may be reduced in the future if commodity prices decline.
The borrowing base under the Credit Facility, was $500 million as of December 31, 2019. Our borrowing base is redetermined at least twice each year and is scheduled to next be redetermined in April 2020. During a borrowing baseredetermination, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Credit Facility.In the event of a decline in crude oil, NGL or natural gas prices or for other reasons deemed relevant by our lenders, the borrowing base under the Credit Facility may be reduced. Additionally, the lenders may, at their discretion, initiate a redetermination at any time during the six-month period between scheduled redeterminations. As a result, we may be unable to obtain funding under the Credit Facility. If funding is not available when or in the amounts needed, or is available only on unfavorable terms, it might adversely affect our development plan and our ability to make new acquisitions. Furthermore, a determination to lower the borrowing base in the future to a level less than our outstanding indebtedness thereunder would require us to repay any indebtedness in excess of the redetermined borrowing base. Any such repayment or reduced access to funds could have a material adverse effect on our production, financial condition, results of operations and cash flows.
The Credit Facility and the Second Lien Facility have restrictive covenants that could limit our financial flexibility.
The Credit Facility and Second Lien Facility contain financial and other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under the Credit Facility is subject to compliance with certain financial covenants, including leverage, interest coverage and current ratios.
The Credit Facility and the Second Lien Facility include other restrictions that, among other things, limit our ability to incur indebtedness; grant liens; engage in mergers, consolidations and liquidations; make asset dispositions, restricted payments and investments; enter into transactions with affiliates; and amend, modify or prepay certain indebtedness.
Our business plan and our compliance with these covenants are based on a number of assumptions, the most important of which is relatively stable oil and gas prices at economically sustainable levels. If the price that we receive for our oil and gas production deteriorates significantly from current levels it could lead to lower revenues, cash flows and earnings, which in turn could lead to a default under certain financial covenants contained in our Credit Facility. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period as the amounts outstanding under our Credit Facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings. Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our debts. We may not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.
We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Exploration, development, production and sale of oil and gas are subject to extensive federal, state and local laws and regulations, including complex environmental laws. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations, inability to obtain necessary regulatory approvals or a failure to comply with existing legal requirements may harm our business, results of operations, financial condition or cash flows. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations or other environmental, health or safety impacts, we may be charged with remedial costs and land owners may file claims for alternative water supplies, property damage or bodily injury. Laws and regulations protecting the environment have become more stringent in recent years, and may, in some circumstances, result in liability for environmental damage regardless of negligence or fault. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. 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.”
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.
In addition, we must dispose of the fluids produced from oil and natural gas production operations, including produced water. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern arises from recent seismic events near underground disposal wells that are used for the disposal by injection of produced water resulting from oil and natural gas activities. In March 2016, the United States Geological Survey identified Texas and Colorado as being among the states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and natural gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells to assess any relationship between seismicity and the use of such wells. For example, in Texas, the RRC adopted new rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. States may issue orders to temporarily shut down or to curtail the injection depth of existing wells in the vicinity of seismic events. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil and natural gas activities utilizing injection wells for produced water disposal.
Climate change legislation, laws and regulations restricting emissions of greenhouse gases or legal or other action taken by public or private entities related to climate change could force us to incur increased capital and operating costs and could have a material adverse effect on our financial condition, results of operations and cash flows,as well as our reputation.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. For example, the EPA issued rules restricting methane emissions from hydraulically fractured and refractured gas wells, compressors, pneumatic controls, storage vessels, and natural gas processing plants. For more information on GHG regulation, see Part I, Item 1, “Business - Government Regulation and Environmental Matters.”
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of Congressional action, many states have established rules aimed at reducing GHG emissions, including GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In the future, the United States may also choose to adhere to international agreements targeting GHG reductions. The adoption of legislation or regulatory programs 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 such climactic events were to occur more frequently or with greater intensity, our exploration and development activities and ability to transport our production to market could be adversely affected, as these events could cause a loss of production from temporary cessation of activity or damaged facilities and equipment. If any such events were to occur, they could have an adverse effect on our financial condition, results of operations and cash flows. For a more complete discussion of environmental laws and regulations intended to address climate change and their impact on our business and operations, see Part I, Item 1, “Business - Government Regulation and Environmental Matters.”
There have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, as well as other stakeholders, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital and adversely impact our reputation. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and gas companies in connection with their GHG emissions. Should we be targeted by any such litigation or investigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
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 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 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents; however, this initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. The CFTC has subsequently issued proposals for new rules that would place position limits on certain core futures contracts and equivalent swap contracts for or linked to certain physical commodities, subject to certain exceptions for bona fide hedging transactions, though these rules have not been finalized and the impact of those provisions on us is uncertain at this time.
While the CFTC has designated certain interest rate swaps and credit default swaps subject to mandatory clearing, and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. The CFTC has not yet proposed rules subjecting any other classes of swaps, including physical commodity swaps, to mandatory clearing. Although we believe we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If our swaps do not qualify for the end-user exception from mandatory clearing, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or our ability to hedge may be impacted. The ultimate effect of the rules and any additional regulations on our business is uncertain at this time.
In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to be exempt from such requirements for the mandatory exchange of margin for uncleared swaps, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. Further, if we did not qualify for an exemption and were required to post collateral for our swaps, it could reduce our liquidity and cash available for capital expenditures and our ability to manage commodity price volatility and the volatility in cash flows.
The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. When fully implemented, the Dodd-Frank Act and any new regulations could increase the operational and transactional cost of derivatives contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize and restructure our existing derivatives contracts and affect the number and/or creditworthiness of available counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.
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 10 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data,” we have substantial NOL carryforwards. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of our stock by 5 percent shareholders and our offering of stock during any three-year period resulting in an aggregate change of more than 50 percent in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. As of December 31, 2019, we do not believe that an ownership change has occurred; however, to the extent an ownership change has occurred or were to occur in the future, it is possible that the limitations imposed on our ability to use pre-ownership change losses could cause a significant net increase in our U.S. federal income tax liability and could cause U.S. federal income taxes to be paid earlier than they otherwise would be paid if such limitations were not in effect. In addition, U.S. NOLs generated on or after January 1, 2018, can be limited to 80 percent of taxable income. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.
Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated. Additional state taxes on oil and gas extraction may be imposed, as a result of future legislation.
In recent years, lawmakers and Treasury have proposed certain significant changes to U.S. tax laws applicable to oil and gas companies. These changes include, but are not limited to: (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or if enacted, when such changes could be effective. If such proposed changes are ever made, as well as any similar changes in state law, it could eliminate or postpone certain tax deductions that are currently available to us with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition, results of operations and cash flows.
Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our crude oil, NGLs and natural gas.
We may not be able to keep pace with technological developments in our industry.
The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations and cash flows could be adversely affected.
A cybersecurity incident could result in theft of confidential information, data corruption or operational disruption.
The oil and gas industry is increasingly dependent on digital technologies to conduct certain exploration, development and production activities. Software programs are used for, among other things, reserve estimates, seismic interpretation, modeling and compliance reporting. In addition, the use of mobile communication is widespread. Increasingly, we must protect our business against potential cyber incidents including attacks as we have experienced and will continue to experience varying degrees of cyber incidents in the normal conduct of our business.
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 Regarding Directorstechnology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. A cyber attack involving our information systems and related infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways, including but not limited to, the following:
Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;
Data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;
Data corruption or operational disruptions of production-related infrastructure could result in a loss of production, or accidental discharge;
A cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects;
A cyber attack on third-party gathering, pipeline, or other transportation systems could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;
A cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
A cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market;
A cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
A cyber attack on our automated and surveillance systems could cause a loss in production and potential environmental hazards;
A deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and
A cyber attack resulting in the loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
Additionally, certain cyber incidents may remain undetected for an extended period. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operations or cash flows. Furthermore, the growth of cyber attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.
A negative shift in investor sentiment towards the oil and gas industry could adversely affect our ability to raise equity and debt capital.
Certain segments of the investor community have recently developed negative sentiment towards investing in our industry. The negative sentiment toward our sector versus other industry sectors has led to lower oil and gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and gas sector based on social and environment considerations. Such development could result in a reduction of available capital funding for potential development projects or diminution of capital to fund our business which could impact our future financial results.
We may be involved in legal proceedings that could result in substantial liabilities.
Like many oil and gas companies, from time to time, we expect to be involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
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.
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, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this report. Significant sales of our common stock, or the expectation of these sales, by significant shareholders, officers or directors could materially and adversely affect the market price of our common stock.
Our business and the trading prices of our securities could be negatively affected as a result of actions of so-called “activist” shareholders, and such activism could impact the trading value of our securities.
Shareholders may from time to time attempt to effect changes, engage in proxy solicitations or advance shareholder proposals. Activist shareholders may make strategic proposals, suggestions or requested changes concerning our operations, strategy, management, assets or other matters. If we become the subject of activity by activist shareholders, responding to such actions could be costly and time-consuming, diverting the attention of our management and employees. Furthermore, activist campaigns can create perceived uncertainties as to our future direction, strategy, or leadership and may result in the loss of potential business opportunities and cause our stock price to experience periods of volatility.
There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.
We are not restricted from issuing additional common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. Any issuance of additional shares of our common stock or convertible securities will dilute the ownership interest of our common stockholders. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market, or the perception that these sales could occur, could depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.
| |
| Item 1B | Unresolved Staff Comments |
None.
As of December 31, 2019, our oil and gas assets were located in Gonzales, Lavaca, Fayette and Dewitt Counties in South Texas.
Facilities
Our corporate headquarters and field office facilities are leased and we believe that they are adequate for our current needs.
Title to Oil and Gas Properties
Prior to completing an acquisition of producing oil and gas assets, we review title opinions on all material leases. As is customary in the oil and gas industry, however, we make a cursory review of title when we acquire farmout acreage or undeveloped oil and gas leases. Prior to the commencement of drilling operations, a thorough title examination is conducted. To the extent the title examination reflects defects, we cure such title defects. If we are unable to cure any title defect of a nature such that it would not be prudent to commence drilling operations on a property, we could suffer a loss of our investment in the property. Our oil and gas properties are subject to customary royalty interests, liens for debt obligations, current taxes and other burdens that we believe do not materially interfere with the use or materially affect the value of such properties. We believe that we have satisfactory title to all of our properties and the associated oil and gas in accordance with standards generally accepted in the oil and gas industry.
Summary of Oil and Gas Reserves
Proved Reserves
The following tables summarize certain information regarding our estimated proved reserves as of December 31 for each of the years presented:
|
| | | | | | | | | | | | | | | | | | | |
| | Crude Oil | | NGLs | | Natural Gas | | Oil Equivalents | | Standardized Measure | | PV10 1 |
| | (MMBbl) | | (MMBbl) | | (Bcf) | | (MMBOE) | | $ in millions | | $ in millions |
| 2019 | |
| | | | |
| | |
| | |
| | |
|
| Developed | | | | | | |
| | | | |
| Producing | 40.1 |
| | 8.7 |
| | 41.0 |
| | 55.6 |
| | | | |
| Non-producing | 0.5 |
| | 0.2 |
| | 0.8 |
| | 0.8 |
| | | | |
| | 40.6 |
| | 8.9 |
| | 41.8 |
| | 56.4 |
| | | | |
| Undeveloped | 58.3 |
| | 10.3 |
| | 48.6 |
| | 76.7 |
| | | | |
| | 98.9 |
| | 19.2 |
| | 90.4 |
| | 133.1 |
| | $ | 1,488.9 |
| | $ | 1,600.1 |
|
| | | | | | | | | | | | |
| Price measurement used | $55.67/Bbl |
| | $13.36/Bbl |
| | $2.58/MMBtu |
| | | | | | |
| | | | | | | | | | | | |
| 2018 |
| |
| |
| |
| |
| | |
| Developed | | | | | | | | | | | |
| Producing | 35.2 |
| | 6.3 |
| | 31.8 |
| | 46.8 |
| | | | |
| Non-producing | — |
| | — |
| | — |
| | — |
| | | | |
| | 35.2 |
| | 6.3 |
| | 31.8 |
| | 46.8 |
| | | | |
| Undeveloped | 54.5 |
| | 11.7 |
| | 59.7 |
| | 76.2 |
| | | | |
| | 89.7 |
| | 18.0 |
| | 91.5 |
| | 123.0 |
| | $ | 1,623.9 |
| | $ | 1,769.4 |
|
| | | | | | | | | | | | |
| Price measurement used | $65.56/Bbl |
| | $23.60/Bbl |
| | $3.10/MMBtu |
| | | | | | |
| | | | | | | | | | | | |
| 2017 | | | | | | | | | | | |
| Developed | | | | | | | | | | | |
| Producing | 22.4 |
| | 4.9 |
| | 27.2 |
| | 31.8 |
| | | | |
| Non-producing | — |
| | — |
| | — |
| | — |
| | | | |
| | 22.4 |
| | 4.9 |
| | 27.2 |
| | 31.8 |
| | | | |
| Undeveloped | 33.4 |
| | 4.0 |
| | 20.1 |
| | 40.8 |
| | | | |
| | 55.8 |
| | 8.9 |
| | 47.3 |
| | 72.6 |
| | $ | 590.5 |
| | $ | 609.0 |
|
| | | | | | | | | | | | |
| Price measurement used | $51.34/Bbl |
| | $18.48/Bbl |
| | $2.98/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. 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.”
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, 2019:
|
| | | | | | | | | | | |
| | Crude Oil | | NGLs | | Natural Gas | | Oil Equivalents |
| | (MMBbl) | | (MMBbl) | | (Bcf) | | (MMBOE) |
| Proved undeveloped reserves at beginning of year | 54.5 |
| | 11.8 |
| | 59.7 |
| | 76.2 |
|
| Revisions of previous estimates | (22.7 | ) | | (4.6 | ) | | (26.5 | ) | | (31.8 | ) |
| Extensions and discoveries | 37.4 |
| | 6.3 |
| | 29.7 |
| | 48.7 |
|
| Purchase of reserves | 0.6 |
| | — |
| | 0.2 |
| | 0.7 |
|
| Conversion to proved developed reserves | (11.5 | ) | | (3.2 | ) | | (14.5 | ) | | (17.1 | ) |
| Proved undeveloped reserves at end of year | 58.3 |
| | 10.3 |
| | 48.6 |
| | 76.7 |
|
The marginal increase in our proved undeveloped reserves over the quantities at the end of 2018 is due primarily to substantial changes in our development plans from the southeast portion of our acreage position in the Eagle Ford to the central region. The overall shift to this region will allow us to develop wells with a lower gas content than what we experienced in the southeast region through the first half of 2019. After achieving more favorable results with certain wells in the central region, we proceeded to drill a total of 11 gross wells, or approximately 23 percent of our total wells drilled and completed in 2019, in the central region that were not considered proved undeveloped locations at the end of 2018. Accordingly, we have prioritized our drilling schedule to exploit these more favorable opportunities. While we still believe that the southeastern sites have economic merit, despite a higher gas content, we have deferred drilling them beyond the five-year window which results in revisions due to timing. Accordingly, our current five-year drilling plan is substantially weighted to the lower gas content central region.
The aforementioned shift in regional focus is reflected in the changes as follows: we experienced net negative revisions of 31.8 MMBOE including: (i) 32.1 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, (ii) reductions in lateral lengths and net revenue interests of 1.7 MMBOE and (iii) declines in pricing of 1.0 MMBOE partially offset by (iv) 3.0 MMBOE due to improved performance from treatable lateral lengths in certain locations. Extensions and discoveries of 48.7 MMBOE are substantially attributable to a regional shift in our development plan, the creation of additional extended reach lateral locations and our recent leasing activities. We acquired 0.7 MMBOE in connection with the acquisition of certain non-operating partners’ working interests in locations in which we are the operator. In addition, we converted 17.1 MMBOE from proved undeveloped to proved developed reserves in the Eagle Ford. During 2019, we incurred capital expenditures of approximately $254 million attributable to 38 gross (33.9 net) wells in connection with the conversion of proved undeveloped reserves to proved developed reserves. Our conversion rates for proved undeveloped reserves were 22 percent, 33 percent and 21 percent in 2019, 2018 and 2017, respectively. The conversion rate decline experienced in 2019 was impacted by the aforementioned shift in the focus of the development plan during 2019.
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 February 19, 2020, 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, 2019 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. In addition to conducting these internal reviews and external reserves audits, we also have a Reserves Committee that consists of four independent members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process.
There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. For additional information about the risks inherent in our estimates of proved reserves, see Part I, Item 1A, “Risk Factors.”
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.
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 | | 2019 | | 2018 | | 2017 |
| | | (MBOE) |
| South Texas | | 10,121 |
| | 7,780 |
| | 3,487 |
|
Mid-Continent 1 | | — |
| | 165 |
| | 292 |
|
| | | 10,121 |
| | 7,944 |
| | 3,779 |
|
| | | | | | | |
| | | Average Daily Production |
| | | Year Ended December 31, |
| Region | | 2019 | | 2018 | | 2017 |
| | | (BOEPD) |
| South Texas | | 27,730 |
| | 21,314 |
| | 9,553 |
|
Mid-Continent 1 | | — |
| | 451 |
| | 800 |
|
| | | 27,730 |
| | 21,765 |
| | 10,353 |
|
1 Mid-Continent operations were sold on July 31, 2018.
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:
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| Average prices: | | | | | | |
| Crude oil ($ per Bbl) | | $ | 58.33 |
| | $ | 66.23 |
| | $ | 50.96 |
|
| NGLs ($ per Bbl) | | $ | 11.13 |
| | $ | 20.99 |
| | $ | 19.25 |
|
| Natural gas ($ per Mcf) | | $ | 2.51 |
| | $ | 3.08 |
| | $ | 2.89 |
|
| Aggregate ($ per BOE) | | $ | 46.34 |
| | $ | 55.33 |
| | $ | 42.20 |
|
| Average production and lifting cost ($ per BOE): | | | | | | |
| Lease operating | | $ | 4.26 |
| | $ | 4.52 |
| | $ | 5.76 |
|
| Gathering processing and transportation | | 2.29 |
| | 2.34 |
| | 2.84 |
|
| | | $ | 6.55 |
| | $ | 6.86 |
| | $ | 8.60 |
|
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, 2019.
The following table sets forth certain information regardingwith respect to this field for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Production: | | | |
| | |
|
| Crude oil (MBbl) | 7,453 |
| | 6,050 |
| | 2,716 |
|
| NGLs (MBbl) | 1,491 |
| | 944 |
| | 418 |
|
| Natural gas (MMcf) | 7,067 |
| | 4,713 |
| | 2,120 |
|
| Total (MBOE) | 10,121 |
| | 7,780 |
| | 3,487 |
|
| Percent of total company production | 100 | % | | 98 | % | | 92 | % |
| Average prices: | | | | | |
| Crude oil ($ per Bbl) | $ | 58.33 |
| | $ | 66.24 |
| | $ | 51.08 |
|
| NGLs ($ per Bbl) | $ | 11.13 |
| | $ | 21.10 |
| | $ | 18.13 |
|
| Natural gas ($ per Mcf) | $ | 2.51 |
| | $ | 3.16 |
| | $ | 2.95 |
|
| Aggregate ($ per BOE) | $ | 46.34 |
| | $ | 55.99 |
| | $ | 43.74 |
|
| Average production and lifting cost ($ per BOE): | | | | | |
| Lease operating | $ | 4.26 |
| | $ | 4.47 |
| | $ | 5.79 |
|
| Gathering processing and transportation | 2.29 |
| | 2.27 |
| | 2.49 |
|
| | $ | 6.55 |
| | $ | 6.74 |
| | $ | 8.28 |
|
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, 2019, 2018 and 2017, 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.
|
| | | | | | | | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Development | |
| | |
| | |
| | |
| | |
| | |
|
| Productive | 48 |
| | 43.3 |
| | 53 |
| | 45.5 |
| | 29 |
| | 16.9 |
|
Dry well 1 | — |
| | — |
| | — |
| | — |
| | 1 |
| | 0.7 |
|
| Total | 48 |
| | 43.3 |
| | 53 |
| | 45.5 |
| | 30 |
| | 17.6 |
|
| | | | | | | | | | | | |
Wells in progress at end of year 2 | 8 |
| | 7.3 |
| | 11 |
| | 10.2 |
| | 11 |
| | 8.2 |
|
1 Represents the Zebra Hunter 05H well in the northern portion of our directors:Eagle Ford acreage.
2 Includes three gross (2.6 net) wells completing, two gross (1.9 net) wells waiting on completion and three gross (2.8 net) wells being drilled as of December 31, 2019.
Present Activities
As of December 31, 2019, we had eight gross (7.3 net) wells in progress. As of February 21, 2020, two gross (1.9 net) wells were completing and seven gross (5.5 net) wells were in progress.
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 Nuevo Dos Gathering and Transportation, LLC and Nuevo Dos Marketing LLC. Our production and reserves are currently sufficient to fulfill the current 8,000 BOPD delivery commitment under these agreements.
Productive Wells
The following table sets forth our productive wells in which we had a working interest as of December 31, 2019:
|
| | | | | | | | | | | | | | | | | | |
| | | Primarily Oil | | Primarily Natural Gas | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Total productive wells | | 509 |
| | 429.1 |
| | 1 |
| | 1.0 |
| | 510 |
| | 430.1 |
|
Of the total wells presented in the table above, we are the operator of 498 gross (497 oil and one natural gas) and 428.2 net (427.2 oil and 1.0 natural gas) wells. In addition to the above working interest wells, we own overriding royalty interests in 18 gross wells.
Acreage
The following table sets forth our developed and undeveloped acreage as of December 31, 2019 (in thousands):
|
| | | | | | | | | | | | | | | | | | |
| | | Developed | | Undeveloped | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Total acreage | | 91.4 |
| | 79.7 |
| | 8.8 |
| | 7.7 |
| | 100.2 |
| | 87.4 |
|
The primary terms of our leases generally range from three to five years, and we do not have any concessions. As of December 31, 2019, our net undeveloped acreage is scheduled to expire as shown in the table below, unless the primary lease terms are, where appropriate, extended, HBP or otherwise changed (in thousands):
|
| | | | | | | | |
| | | 2020 | | 2021 | | 2022 | | Thereafter |
| Expirations by year | | 4.8 | | 0.9 | | 2.0 | | 0.0 |
We anticipate paying options to extend a substantial portion of the acreage scheduled to expire in 2020. 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.
See Note 14 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” We are not aware of any material legal or governmental proceedings against us, or threatened to be brought against us, under the various environmental protection statutes to which we are subject.
| |
| Item 4 | Mine Safety Disclosures |
Not applicable.
Part II
| |
| Item 5 | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Market Information
Since December 28, 2016, our common stock has been listed and traded on the Nasdaq under the symbol “PVAC.”
Equity Holders
As of February 13, 2020, there were 111 record holders of our common stock.
Dividends
We have not paid nor do we currently have plans to pay any cash dividends on our common stock in the foreseeable future. Furthermore, we are limited in our ability to pay dividends under the Credit Facility and the Second Lien Facility.
Securities Authorized for Issuance Under Equity Compensation Plans
See Part III, Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” and Note 16 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data” for information regarding shares of common stock authorized for issuance under our stock compensation plans.
Issuer Purchases of Equity Securities
We did not repurchase any shares of our common stock in the fourth quarter of 2019.
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, 2019. As of December 31, 2019, there were seventeen exploration and production companies in the Standard & Poor’s 600 Oil & Gas Exploration and Production Index: Bonanza Creek Energy Inc., Callon Petroleum Company, Denbury Resources Inc., Gulfport Energy Corporation, Highpoint Resources Corporation, Jagged Peak Energy, Laredo Petroleum Inc., Oasis Petroleum Inc., PDC Energy Inc., QEP Resources Inc., Range Resources Corporation, Ring Energy Inc., SM Energy Co., Southwestern Energy Company, SRC Energy Inc., Talos Energy Inc. and Whiting Petroleum Corp. 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:
|
| | | | | | | | | | | | | | | | | | | |
| | November 15, | | December 31, |
| | 2016 | | 2016 | | 2017 | | 2018 | | 2019 |
| Penn Virginia Corporation | $ | 100.00 |
| | $ | 120.62 |
| | $ | 96.27 |
| | $ | 133.07 |
| | $ | 74.71 |
|
| S&P SmallCap 600 Index | $ | 100.00 |
| | $ | 116.34 |
| | $ | 131.74 |
| | $ | 120.56 |
| | $ | 148.03 |
|
| S&P 600 Oil & Gas Exploration & Production Index | $ | 100.00 |
| | $ | 114.11 |
| | $ | 70.37 |
| | $ | 42.30 |
| | $ | 31.04 |
|
| |
| 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 1 | | | Predecessor 1 |
| | | | | | | | September 13 | | | January 1 | | |
| | Year Ended | | Through | | | Through | | Year Ended |
| | December 31, | | December 31, | | | September 12, | | December 31, |
| | 2019 | | 2018 | | 2017 | | 2016 | | | 2016 | | 2015 |
| Statements of Operations and Other Data: | | | | | | | |
| | | |
| | |
|
Revenues 2 | $ | 471,216 |
| | $ | 440,832 |
| | $ | 160,054 |
| | $ | 39,003 |
| | | $ | 94,310 |
| | $ | 305,298 |
|
Operating income (loss) 3 | $ | 176,821 |
| | $ | 208,755 |
| | $ | 51,872 |
| | $ | 11,413 |
| | | $ | (20,867 | ) | | $ | (1,564,976 | ) |
Net income (loss) 4 | $ | 70,589 |
| | $ | 224,785 |
| | $ | 32,662 |
| | $ | (5,296 | ) | | | $ | 1,054,602 |
| | $ | (1,582,961 | ) |
| Preferred stock dividends | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | 5,972 |
| | $ | 22,789 |
|
| Income (loss) attributable to common shareholders | $ | 70,589 |
| | $ | 224,785 |
| | $ | 32,662 |
| | $ | (5,296 | ) | | | $ | 1,048,630 |
| | $ | (1,605,750 | ) |
| Income (loss) per common share, basic | $ | 4.67 |
| | $ | 14.93 |
| | $ | 2.18 |
| | $ | (0.35 | ) | | | $ | 11.91 |
| | $ | (21.81 | ) |
| Income (loss) per common share, diluted | $ | 4.67 |
| | $ | 14.70 |
| | $ | 2.17 |
| | $ | (0.35 | ) | | | $ | 8.50 |
| | $ | (21.81 | ) |
| Weighted-average shares outstanding: | | | | | | | | | | |
| | |
|
| Basic | 15,110 |
| | 15,059 |
| | 14,996 |
| | 14,992 |
| | | 88,013 |
| | 73,639 |
|
| Diluted | 15,126 |
| | 15,292 |
| | 15,063 |
| | 14,992 |
| | | 124,087 |
| | 73,639 |
|
| Dividends declared per share | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | |
| Cash provided by operating activities | $ | 320,194 |
| | $ | 272,132 |
| | $ | 81,710 |
| | $ | 30,774 |
| | | $ | 30,247 |
| | $ | 169,303 |
|
| Cash paid for capital expenditures | $ | 362,743 |
| | $ | 430,592 |
| | $ | 115,687 |
| | $ | 4,812 |
| | | $ | 15,359 |
| | $ | 364,844 |
|
| | | | | | | | | | | | | |
| Total production (MBOE) | 10,121 |
| | 7,944 |
| | 3,779 |
| | 1,039 |
| | | 3,346 |
| | 7,923 |
|
| | | | | | | | | | | | | |
| | December 31, | | | September 12, | | December 31, |
| | 2019 | | 2018 | | 2017 | | 2016 | | | 2016 | | 2015 |
| Balance Sheet and Other Data: | | | | | | | | | | | | |
| Property and equipment, net | $ | 1,120,425 |
| | $ | 927,994 |
| | $ | 529,059 |
| | $ | 247,473 |
| | | $ | 253,510 |
| | $ | 344,395 |
|
| Total assets | $ | 1,218,238 |
| | $ | 1,068,954 |
| | $ | 629,597 |
| | $ | 291,686 |
| | | $ | 333,974 |
| | $ | 517,725 |
|
| Total debt | $ | 555,028 |
| | $ | 511,375 |
| | $ | 265,267 |
| | $ | 25,000 |
| | | $ | 75,350 |
| | $ | 1,224,383 |
|
| Shareholders’ equity (deficit) | $ | 520,745 |
| | $ | 447,355 |
| | $ | 221,639 |
| | $ | 185,548 |
| | | $ | 190,895 |
| | $ | (915,121 | ) |
| | | | | | | | | | | | | |
| Actual shares outstanding at period-end | 15,136 |
| | 15,081 |
| | 15,019 |
| | 14,992 |
| | | 14,992 |
| | 81,253 |
|
| Proved reserves as of December 31, (MMBOE) | 133 |
| | 123 |
| | 73 |
| | 49 |
| | | N/A |
| | 44 |
|
| |
1 | Upon our emergence from bankruptcy, we adopted and applied fresh start accounting. Accordingly, our financial statements for periods after September 12, 2016 are not comparable to those prior to that date. Financial information for the periods up to and including September 12, 2016 are referred to herein as those of the “Predecessor” while those beginning on September 13, 2016 and all periods thereafter are referenced as those of the “Successor.” |
| |
2 | Revenues for the years ended after December 31, 2017 reflect the application of Accounting Standards Codification, or ASC, Topic 606, Revenues from Contracts with Customers, or ASC Topic 606. The adoption of ASC Topic 606 impacts the presentation and comparability of NGL product revenues between the years beginning after December 31, 2017 with those years ending on that date and all prior periods. See “Presentation of Financial Information and Changes in Accounting Principles” included in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” |
| |
3 | Operating income (loss) for the year ended December 31, 2019 reflects the application of ASC Topic 842, Leases, or ASC Topic 842. The adoption of ASC Topic 842 impacts the presentation and comparability of lease expense between the year ended December 31, 2019 with all prior periods. See “Presentation of Financial Information and Changes in Accounting Principles” included in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and 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 resulting in income attributable to our bankruptcy proceedings of $3.3 million and $1.1 billion, respectively. |
| |
| Item 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Part II, Item 8, “Financial Statements and Supplementary Data.” All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Also, due to the combination of different units of volumetric measure and the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables.
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 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.
Industry Environment and Recent Operating and Financial Highlights
Commodity Price and Other Economic Conditions
Crude oil prices exhibited significant volatility throughout 2019 with a range between high and low prices of approximately $20 per barrel. This volatility has continued into February of 2020 and has included significant swings on a daily basis. In addition to the traditional domestic (i.e., significant production from the Permian Basin and mature shale plays including the Eagle Ford, etc.) and global (i.e., Middle East capacity, etc.) supply and demand factors, the impact of certain geopolitical and other dynamics have had a significant daily impact on crude oil and other commodity prices as well. For example, Middle East tensions have approached levels with military involvement not experienced in many years. In addition, the global economic impact of the coronavirus is continuing to evolve and its uncertainty has been reflected in daily commodity price volatility. While impacting us to a lesser extent, NGL and natural gas pricing has steadily declined from year-end 2018 levels due primarily to excess domestic supply and milder winter weather through January of 2020. Collectively, these trends have had a substantial impact on the rate of growth in our product revenues. These factors are anticipated to maintain downward pressure on commodity prices for the near term.
Since February 2019, we have contracted for our drilling rigs on a pad-to-pad basis and the day rates charged for these services as well as casing costs have declined throughout 2019. In addition, costs associated with our dedicated frac services agreement including certain component stimulation product and service costs have also declined in 2019. We anticipate that many of these costs will continue a declining trend into 2020. Costs incurred for most oilfield products and services associated with operating our properties remained relatively stable during 2019 and are anticipated to behave similarly into 2020 with moderate declines in certain costs consistent with recent industry experience.
Capital Expenditures and Development Progress
During 2019, we incurred capital expenditures of approximately $356 million with 97 percent directed to drilling and completion projects. We drilled and completed a total of 48 gross (43.3 net) wells. In a series of transactions, we acquired certain of our joint venture partners’ working interests in selected properties for which we are the operator for approximately $6.5 million. Through our drilling program and these acquisitions, we operated a total of 510 gross (430.1 net) wells in the Eagle Ford as of December 31, 2019. Through selected acquisitions, certain property exchanges and other transactions, we added or renewed approximately 3,500 net acres to our Eagle Ford lease portfolio during 2019.
Sequential Quarterly Analysis
The following summarizes certain key operating and financial highlights for the three months ended December 31, 2019 with comparison to the three months ended September 30, 2019 as presented in the table that follows. The year-over-year highlights for 2019 and 2018 are addressed in further detail in the discussions for Financial Condition and Results of Operations that follow.
Daily production increased one percent to 29,314 BOEPD, from 29,003 BOEPD due primarily to the number of wells turned to sales in the second half of 2019. During the fourth quarter of 2019, we turned to sales 11 gross (9.9 net) wells compared to 20 gross (18.3 net) wells turned to sales in the third quarter of 2019. Of the wells turned to sales in the third quarter of 2019, ten gross (9.0 net) wells were turned to sales in late August and September of 2019. Total production increased one percent to 2,697 MBOE from 2,668 MBOE.
Product revenues increased approximately four percent to $123.2 million from $118.4 million due primarily to six percent higher crude oil volume partially offset by one percent lower crude oil prices. NGL revenues were 13 percent higher due to 26 percent higher prices partially offset by 10 percent lower volume. Natural gas revenues declined six percent due to an 11 percent decrease in volume partially offset by a five percent increase in prices.
Production and lifting costs (consisting of LOE and GPT) declined on an absolute and per unit basis to $16.1 million and $5.98 per BOE from $18.5 million and $6.92 per BOE due primarily to lower utility charges, maintenance costs and chemical costs.
Production and ad valorem taxes were relatively consistent on an absolute basis at $7.4 million for each period and declined marginally on per unit basis to $2.74 per BOE from $2.77 per BOE, respectively, due to three percent lower overall product pricing and one percent higher production volume partially offset by the effect of higher estimated valuations for ad valorem tax assessments that were recorded in prior quarters of 2019.
G&A expenses decreased on an absolute and per unit basis to $5.3 million and $1.97 per BOE from $6.9 million and $2.57 per BOE, respectively, due primarily to lower benefits charges as well as lower occupancy and consulting costs.
Our DD&A, decreased on an absolute basis and per unit basis to $44.9 million and $16.64 per BOE from $46.5 million and $17.43 per BOE due primarily to higher reserve quantity estimates.
Our operating income increased to $50.2 million from $40.0 million due to the combined impact of the matters noted in the bullets above.
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 | | | | | | |
| | December 31, | | September 30, | | Year Ended December 31, |
| | 2019 | | 2019 | | 2019 | | 2018 | | 2017 |
| Total production (MBOE) | 2,697 |
| | 2,668 |
| | 10,121 |
| | 7,944 |
| | 3,779 |
|
| Average daily production (BOEPD) | 29,314 |
| | 29,003 |
| | 27,730 |
| | 21,765 |
| | 10,353 |
|
| Crude oil production (MBbl) | 2,043 |
| | 1,937 |
| | 7,453 |
| | 6,077 |
| | 2,764 |
|
| Crude oil production as a percent of total | 76 | % | | 73 | % | | 74 | % | | 76 | % | | 73 | % |
| Product revenues | $ | 123,196 |
| | $ | 118,379 |
| | $ | 469,035 |
| | $ | 439,530 |
| | $ | 159,469 |
|
| Crude oil revenues | $ | 115,252 |
| | $ | 110,618 |
| | $ | 434,713 |
| | $ | 402,485 |
| | $ | 140,886 |
|
| Crude oil revenues as a percent of total | 94 | % | | 93 | % | | 93 | % | | 92 | % | | 88 | % |
| Realized prices: | | | | | | | | | |
| Crude oil ($ per Bbl) | $ | 56.40 |
| | $ | 57.12 |
| | $ | 58.33 |
| | $ | 66.23 |
| | $ | 50.96 |
|
NGL ($ per Bbl) 1 | $ | 10.74 |
| | $ | 8.54 |
| | $ | 11.13 |
| | $ | 20.99 |
| | $ | 19.25 |
|
| Natural gas ($ per Mcf) | $ | 2.34 |
| | $ | 2.22 |
| | $ | 2.51 |
| | $ | 3.08 |
| | $ | 2.89 |
|
| Aggregate ($ per BOE) | $ | 45.68 |
| | $ | 44.37 |
| | $ | 46.34 |
| | $ | 55.33 |
| | $ | 42.20 |
|
| Prices, adjusted for derivatives:: | | | | | | | | | |
| Crude oil ($ per Bbl) | $ | 56.50 |
| | $ | 56.90 |
| | $ | 57.78 |
| | $ | 58.28 |
| | $ | 49.69 |
|
| Aggregate ($ per BOE) | $ | 45.75 |
| | $ | 44.21 |
| | $ | 45.93 |
| | $ | 49.25 |
| | $ | 41.27 |
|
| Production and lifting costs ($ per BOE): | | | | | | | | | |
| Lease operating | $ | 3.65 |
| | $ | 4.45 |
| | $ | 4.26 |
| | $ | 4.52 |
| | $ | 5.76 |
|
Gathering, processing and transportation 1 | $ | 2.32 |
| | $ | 2.47 |
| | $ | 2.29 |
| | $ | 2.34 |
| | $ | 2.84 |
|
| Production and ad valorem taxes ($ per BOE) | $ | 2.74 |
| | $ | 2.77 |
| | $ | 2.77 |
| | $ | 2.96 |
| | $ | 2.33 |
|
General and administrative ($ per BOE) 2 | $ | 1.97 |
| | $ | 2.58 |
| | $ | 2.52 |
| | $ | 3.28 |
| | $ | 4.82 |
|
| Depreciation, depletion and amortization ($ per BOE) | $ | 16.64 |
| | $ | 17.43 |
| | $ | 17.25 |
| | $ | 16.11 |
| | $ | 12.87 |
|
Capital expenditure program costs 3 | $ | 64,623 |
| | $ | 99,068 |
| | $ | 355,851 |
| | $ | 418,951 |
| | $ | 129,827 |
|
Cash provided by operating activities 4 | $ | 75,981 |
| | $ | 89,851 |
| | $ | 320,194 |
| | $ | 272,132 |
| | $ | 81,710 |
|
Cash paid for capital expenditures 5 | $ | 71,010 |
| | $ | 115,792 |
| | $ | 362,743 |
| | $ | 430,592 |
| | $ | 115,687 |
|
| Cash and cash equivalents at end of period | $ | 7,798 |
| | $ | 11,387 |
| | $ | 7,798 |
| | $ | 17,864 |
| | $ | 11,017 |
|
| Debt outstanding, net of discount and issue costs, at end of period | $ | 555,028 |
| | $ | 562,445 |
| | $ | 555,028 |
| | $ | 511,375 |
| | $ | 265,267 |
|
| Credit available under credit facility at end of period | $ | 137,200 |
| | $ | 129,200 |
| | $ | 137,200 |
| | $ | 128,600 |
| | $ | 159,745 |
|
| Net development wells drilled and completed | 9.9 |
| | 18.3 |
| | 43.3 |
| | 45.5 |
| | 16.9 |
|
| Proved reserves at the end of the period (MMBOE) | 133 |
| | N/A |
| | 133 |
| | 123 |
| | 73 |
|
| |
1 | The effects of the adoption of ASC Topic 606, if applied to the year ended December 31, 2017, would have resulted in realized prices for NGLs of $16.40 per BOE and GPT of $2.45 per BOE, respectively. |
| |
2 | Includes combined amounts of $0.36 and $0.39 per BOE for the three months ended December 31, 2019 and September 30, 2019, respectively, and $0.48, $1.11 and 1.36 per BOE for the years ended December 31, 2019, 2018 and 2017, respectively, attributable to equity-classified share-based compensation and significant special charges, including acquisition, divestiture and strategic transaction costs, among others costs, as described in the discussion of “Results of Operations - General and Administrative” that follows. |
| |
3 | Includes amounts accrued and excludes capitalized interest and capitalized labor. |
| |
4 | Includes net cash received for derivative settlements of $0.2 million and net cash paid for derivative settlements of $0.4 million for the three months ended December 31, 2019 and September 30, 2019, respectively, and net cash paid for derivative settlements of $4.1 million, $48.3 million and $3.5 million for the years ended December 31, 2019, 2018 and 2017, respectively. Reflects changes in operating assets and liabilities of $(12.7) million and $10.9 million for the three months ended December 31, 2019 and September 30, 2019, respectively, and $0.2 million, $(2.8) million and $(15.0) million for the years ended December 31, 2019, 2018 and 2017, respectively. |
| |
5 | Represents actual cash paid for capital expenditures including capitalized interest and capitalized labor. |
Key Developments
The following general business developments and corporate actions had or may have a significant impact on our results of operations, financial position and cash flows:
Production and Development Progress
Total production for the quarter and year ended December 31, 2019 was 2,697 MBOE and 10,121, or 29,314 and 27,730 BOEPD, with approximately 76 percent and 74 percent, or 2,043 MBbls and 7,453 MBbls, of production from crude oil, 14 and 15 percent from NGLs and 10 percent and 11 percent from natural gas, respectively.
We drilled and turned 11 and 48 gross (9.9 and 43.3 net) wells to sales during the quarter and year ended December 31, 2019, respectively. Subsequent to December 31, 2019, we turned an additional six gross (5.4 net) wells to sales through February 21, 2020. As of February 21, 2020, we were in the process of drilling seven gross (5.5 net) wells and two gross (1.9 net) wells were completing.
As of February 21, 2020, we had approximately 100,200 gross (87,400 net) acres in the Eagle Ford, net of expirations. Approximately 91 percent of our acreage is held by production and substantially all is operated by us.
Commodity and Interest Rate Hedging Program
As of January 31, 2020 and including hedges we entered into after December 31, 2019, we have hedged a portion of our estimated future crude oil and natural gas production from February 1, 2020 through the end of 2021 with a mix of WTI- , MEH-, and Henry Hub indexed swaps, enhanced swaps and collars. We are currently unhedged with respect to NGL production. The following table summarizes our hedge positions for the periods presented:
|
| | | | | | | | | | | | | |
| | WTI - Oil Volumes | | WTI Average Price | | MEH - Oil Volumes | | MEH Average Price |
| Swaps | (Barrels per day) | | ($ per barrel) | | (Barrels per day) | | ($ per barrel) |
| 1Q - 2020 | 15,648 |
| | $ | 55.34 |
| | 2,000 |
| | $ | 61.03 |
|
| 2Q - 2020 | 10,648 |
| | $ | 55.35 |
| | 2,000 |
| | $ | 61.03 |
|
| 3Q - 2020 | 8,630 |
| | $ | 55.20 |
| | 2,000 |
| | $ | 61.03 |
|
| 4Q - 2020 | 8,630 |
| | $ | 55.20 |
| | 2,000 |
| | $ | 61.03 |
|
| 1Q - 2021 | 3,333 |
| | $ | 55.89 |
| | — |
| | $ | — |
|
| 2Q - 2021 | 3,297 |
| | $ | 55.89 |
| | — |
| | $ | — |
|
| 3Q - 2021 | 1,630 |
| | $ | 55.50 |
| | — |
| | $ | — |
|
| 4Q - 2021 | 1,630 |
| | $ | 55.50 |
| | — |
| | $ | — |
|
|
| | | | | | | | | | |
| | WTI - Oil Volumes | | WTI Floor Price | | WTI Ceiling Price |
| Collars | (Barrels per day) | | ($ per barrel) | | ($ per barrel) |
| 2Q - 2020 | 5,297 |
| | $ | 52.36 |
| �� | $ | 57.60 |
|
| 3Q - 2020 | 6,891 |
| | $ | 52.97 |
| | $ | 58.03 |
|
| 4Q - 2020 | 2,000 |
| | $ | 48.00 |
| | $ | 57.10 |
|
| 1Q - 2021 | 1,667 |
| | $ | 55.00 |
| | $ | 58.00 |
|
| 2Q - 2021 | 1,648 |
| | $ | 55.00 |
| | $ | 58.00 |
|
|
| | | | | | |
| | WTI - Oil Volumes | | WTI Put Price |
| Sold Puts | (Barrels per day) | | ($ per barrel) |
| 1Q - 2021 | 5,000 |
| | $ | 44.00 |
|
| 2Q - 2021 | 4,945 |
| | $ | 44.00 |
|
| 3Q - 2021 | 1,630 |
| | $ | 44.00 |
|
| 4Q - 2021 | 1,630 |
| | $ | 44.00 |
|
As of January 31, 2020, we have hedged over 40% of our estimated 2020 natural gas production.
|
| | | | | | | | | | |
| | Henry Hub - Gas Volumes | | Henry Hub Floor Price | | Henry Hub Ceiling Price |
| Collars | (MMBtu/d) | | ($/MMBtu) | | ($/MMBtu) |
| 1Q - 2020 | 5,934 |
| | $ | 2.00 |
| | $ | 2.18 |
|
| 2Q - 2020 | 8,901 |
| | $ | 2.00 |
| | $ | 2.18 |
|
| 3Q - 2020 | 8,804 |
| | $ | 2.00 |
| | $ | 2.18 |
|
| 4Q - 2020 | 8,804 |
| | $ | 2.00 |
| | $ | 2.18 |
|
In February 2020, we began hedging our exposure to variable interest rates as we entered into a series of interest rate swaps contracts through May 2022 for a notional amount of $300 million, paying a weighted-average fixed rate of 1.36%.
Amendment to Credit Facility and Affirmation of Borrowing Base
In May 2019, we entered into the Borrowing Base Increase Agreement and Amendment No. 6 to the Credit Facility, or the Sixth Amendment, to our credit agreement, or Credit Facility, increasing the lender commitment to $1.0 billion from $450 million and the borrowing base to $500 million from $450 million and extending the maturity to May 2024 from September 2020 (subject to certain conditions as described in Note 9 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data,”) among other things. In addition, the applicable margin ranges associated with borrowings under the Credit Facility were each reduced by 150 basis points. We incurred and capitalized approximately $2.6 million of issue and other costs associated with the Sixth Amendment.
In November 2019, we completed our fall borrowing base redetermination and our lenders affirmed the $500 million borrowing base. Our next redetermination is currently scheduled for April 2020.
Executive Transition
On November 4, 2019, the Company announced that Russell T Kelley, Jr. had been appointed as the Company’s Senior Vice President, Chief Financial Officer and Treasurer, or SVP and CFO, effective November 13, 2019. In connection with the transition, Steven A. Hartman, the former SVP and CFO resigned in accordance with a separation and transition agreement with the Company.
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 $1.0 billion in borrowing commitments. The current borrowing base under the Credit Facility is also $500 million. As of February 27, 2020, we had $133.2 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. In order to mitigate this volatility, we entered into derivative contracts with a number of financial institutions, all of which are participants in the Credit Facility, hedging a portion of our estimated future crude oil production through the end of 2021. 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.
Capital Resources
Under our capital program for 2020, we anticipate capital expenditures, excluding acquisitions, of up to $310 million with approximately 95 percent of capital being directed to drilling and completions on our Eagle Ford acreage. We plan to fund our 2020 capital spending primarily with cash from operating activities and, to the extent necessary, supplemental borrowings under the Credit Facility. Based upon current price and production expectations for 2020, we believe that our cash from operating activities and borrowings under our Credit Facility, as necessary, will be sufficient to fund our operations through year-end 2020; 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 27, 2020, we had over $15 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 2019, we borrowed $41.4 million, net of repayments, 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 | | |
| | End of Period | | Weighted- Average | | Maximum | | Weighted- Average Rate |
| Three months ended December 31, 2019 | $ | 362,400 |
| | $ | 381,465 |
| | $ | 384,400 |
| | 4.06 | % |
| Year ended December 31, 2019 | $ | 362,400 |
| | $ | 349,713 |
| | $ | 384,400 |
| | 4.79 | % |
Proceeds from Sales of Assets. We continually evaluate potential sales of assets, including certain non-strategic oil and gas properties and undeveloped acreage, among others. For additional information and an analysis of our historical proceeds from sales of assets, see the “Cash Flows” discussion that follows.
Capital Markets 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.
Cash Flows
The following table summarizes our cash flows for the periods presented:
|
| | | | | | | |
| | Year Ended |
| | December 31, |
| | 2019 | | 2018 |
| Cash flows from operating activities | | | |
| Operating cash flows, net of working capital changes | $ | 356,321 |
| | $ | 346,780 |
|
| Crude oil derivative settlements paid, net | (4,136 | ) | | (48,291 | ) |
| Interest payments, net of amounts capitalized | (32,398 | ) | | (22,599 | ) |
| Income tax refunds | 2,471 |
| | — |
|
| Acquisition, divestiture and strategic transaction costs paid | (1,985 | ) | | (2,968 | ) |
| Reorganization-related administration fees and costs paid, net | (79 | ) | | (540 | ) |
| Consulting costs paid to former Executive Chairman | — |
| | (250 | ) |
| Net cash provided by operating activities | 320,194 |
| | 272,132 |
|
| Cash flows from investing activities | |
| | |
|
| Acquisitions, net | (6,516 | ) | | (85,387 | ) |
| Capital expenditures | (362,743 | ) | | (430,592 | ) |
| Proceeds from sales of assets, net | 215 |
| | 7,683 |
|
| Net cash used in investing activities | (369,044 | ) | | (508,296 | ) |
| Cash flows from financing activities | |
| | |
|
| Proceeds from credit facility borrowings, net | 41,400 |
| | 244,000 |
|
| Debt issuance costs paid | (2,616 | ) | | (989 | ) |
| Net cash provided by financing activities | 38,784 |
| | 243,011 |
|
| Net increase (decrease) in cash and cash equivalents | $ | (10,066 | ) | | $ | 6,847 |
|
Cash Flows from Operating Activities. The increase of $48.1 million in net cash from operating activities for 2019 compared to 2018 was primarily attributable to: (i) approximately 27 percent higher production volume in 2019 despite approximately 16 percent lower overall product pricing, (ii) substantially lower net payments of derivative settlements during 2019 resulting primarily from the narrowing of the margin between hedged and actual settlement prices, (iii) the receipt in 2019 of a refund of alternative minimum tax, or AMT, credits in connection with the filing of our 2018 federal income tax return, (iv) lower payments in 2019 for acquisition, divestiture and strategic transaction costs as a merger agreement was terminated in early 2019, (v) lower bankruptcy-related administration costs as the case was closed in November 2018 and (vi) less executive retirement costs in 2019 compared to 2018. These items were partially offset by higher interest payments due to greater outstanding borrowings in 2019.
Cash Flows from Investing Activities. In 2019, we paid $6.5 million for the acquisition of working interests in certain properties for which we are the operator from our joint working interest partners. 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. As illustrated in the tables below, our cash payments for capital expenditures were significantly lower during 2019 as compared to 2018, due primarily to the employment of two drilling rigs through most of 2019 compared to three drilling rigs utilized during most of 2018. The cash payments for capital expenditures for 2019 and 2018 also reflect refunds of $3.8 million and $0.6 million, respectively, received for sales and use taxes that were applicable to capital expenditures in prior years. In addition, we received $0.2 million in proceeds from the sale of scrap tubular and well materials in 2019 while 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 deep leasehold rights in Oklahoma, (iv) certain pipeline assets in our former Marcellus Shale operating region and (iv) scrap tubular and well materials.
The following table sets forth costs related to our capital expenditure program for the periods presented:
|
| | | | | | | |
| | Year Ended |
| | December 31, |
| | 2019 | | 2018 |
| Drilling and completion | $ | 344,542 |
| | $ | 405,677 |
|
| Lease acquisitions and other land-related costs | 3,433 |
| | 5,180 |
|
| Geological, geophysical (seismic) and delay rental costs | 363 |
| | 377 |
|
| Pipeline, gathering facilities and other equipment, net | 7,513 |
| | 7,717 |
|
| | $ | 355,851 |
| | $ | 418,951 |
|
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:
|
| | | | | | | |
| | Year Ended |
| | December 31, |
| | 2019 | | 2018 |
| Total capital expenditures program costs (from above) | $ | 355,851 |
| | $ | 418,951 |
|
| Decrease (increase) in accrued capitalized costs | 3,602 |
| | (44 | ) |
| Less: | | | |
| Transfers from tubular inventory and well materials | (10,971 | ) | | (10,056 | ) |
| Sales & use tax refunds received and applied to property accounts | (3,816 | ) | | (643 | ) |
| Other, net | (115 | ) | | — |
|
| Add: | | | |
| Tubular inventory and well materials purchased in advance of drilling | 9,967 |
| | 9,578 |
|
| Capitalized internal labor | 4,089 |
| | 3,688 |
|
| Capitalized interest | 4,136 |
| | 9,118 |
|
| Total cash paid for capital expenditures | $ | 362,743 |
| | $ | 430,592 |
|
Cash Flows from Financing Activities. During 2019, we borrowed $76.4 million and made repayments of $35.0 million under the Credit Facility which were used to fund a portion of our capital program as well as the aforementioned acquisition of working interests. During 2018, we borrowed $244 million under the Credit Facility to fund the three-rig capital program and the Hunt Acquisition. We also paid $2.6 million and $1.0 million of debt issue costs in 2019 and 2018, respectively, in connection with amendments to the Credit Facility.
Capitalization
The following table summarizes our total capitalization as of the dates presented:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| Credit Facility borrowings | $ | 362,400 |
| | $ | 321,000 |
|
| Second Lien Facility term loans, net of original issue discount and issuance costs | 192,628 |
| | 190,375 |
|
| Total debt | 555,028 |
| | 511,375 |
|
| Shareholders’ equity | 520,745 |
| | 447,355 |
|
| Total capitalization | $ | 1,075,773 |
| | $ | 958,730 |
|
| Debt as a % of total capitalization | 52 | % | | 53 | % |
Credit Facility. The Credit Facility provides for a $1.0 billion revolving commitment and $500 million borrowing base, including a $25.0 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. We had $0.4 million in letters of credit outstanding as of December 31, 2019 and 2018, respectively.
The Credit Facility is scheduled to mature in May 2024; provided that on June 30, 2022, unless we have either extended the maturity date of our $200 million Second Lien Credit Agreement dated as of September 29, 2017, or the Second Lien Facility, to a date that is at least 91 days after May 7, 2024 or have repaid our Second Lien Facility in full, the maturity date of the Credit Facility will mean June 30, 2022.
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 0.50% to 1.50%, 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 1.50% to 2.50%, 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, 2019, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.75%. Unused commitment fees are charged at a rate of 0.375% to 0.50%, depending upon utilization.
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%. As of December 31, 2019, the actual interest rate on outstanding borrowings under the Second Lien Facility was 8.81%. 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 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 remaining prepayment premiums (in addition to customary “breakage” costs with respect to eurocurrency loans): during the period ending September 29, 2020, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following remaining 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 the period ended September 29, 2020, 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 current ratio (as defined in the Credit Facility, which considers the the unused portion of the total commitment as a current asset) of 1.00 to 1.00, and (2) a maximum leverage ratio (consolidated indebtedness to EBITDAX, each as defined in the Credit Facility), in each case measured as of the last day of each fiscal quarter of 4.00 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), limitations 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, as applicable, 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, 2019, we were in compliance with all of the covenants under the Credit Facility and the Second Lien Facility.
Reference Rate Reform. In July 2017, the U.K.’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. At the present time, the Credit Facility and Second Lien Facility are, at our option, contractually subject to LIBOR rates and both have terms that extend beyond 2021. We have not yet pursued any technical amendment or other contractual alternative to address this matter. We are currently evaluating the potential impact of the eventual replacement of the LIBOR interest rate.
Results of Operations
Presentation of Financial Information and Changes in Accounting Principles
Adoption of New Accounting Standards
As discussed in further detail in Notes 2, 5 and 11 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data,” we have adopted two accounting standards that impact the comparability of our financial statements: Accounting Standards Codification, or ASC, Topic 842, Leases, or ASC Topic 842, effective January 1, 2019 and ASC Topic 606, Revenues from Contracts with Customers, or ASC Topic 606, effective January 1, 2018. The adoption of ASC Topic 842 impacts the presentation and comparability of (i) Lease operating, or LOE, expense and (ii) General and administrative, or G&A, expenses. We adopted ASC Topic 842 utilizing the cumulative effect transition method effective January 1, 2019. Accordingly, our LOE and G&A expenses for the year ended December 31, 2019 are not comparable to the 2018 and 2017 presentation of these items. The adoption of ASC Topic 606 impacts the presentation and comparability of (i) NGL product revenues and (ii) Gathering, processing and transportation, or GPT, expense. We adopted ASC Topic 606 utilizing the cumulative effect transition method effective January 1, 2018. Accordingly, our NGL revenues and GPT expense for the year ended December 31, 2017 are not comparable to the 2019 and 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 842 and ASC Topic 606.
Impact of Acquisitions and Divestitures
A portion of the components of our year-over-year variances for 2018 to 2017 are also due to the effects of the Hunt Acquisition in March 2018 and the Devon Acquisition in September 2017. Partially offsetting the impact of these transactions are the effects of our divestiture of our former assets in the Mid-Continent region that we sold in July 2018.
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: |
| | | | | | | | |
| | Total Production |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Crude oil (MBbl) | 7,453 |
| | 6,077 |
| | 2,764 |
|
| NGLs (MBbl) | 1,491 |
| | 1,004 |
| | 523 |
|
| Natural gas (MMcf) | 7,067 |
| | 5,181 |
| | 2,949 |
|
| Total (MBOE) | 10,121 |
| | 7,944 |
| | 3,779 |
|
| 2019 vs 2018 Variance (MBOE) | | | 2,177 |
| |
|
| % Change | | | 27 | % | |
|
| 2018 vs. 2017 Variance (MBOE) | | | | | 4,165 |
|
| % Change | | | | | 110 | % |
| | Average Daily Production |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Crude oil (Bbl per day) | 20,418 |
| | 16,650 |
| | 7,573 |
|
| NGLs (Bbl per day) | 4,085 |
| | 2,750 |
| | 1,432 |
|
| Natural gas (MMcf per day) | 19 |
| | 14 |
| | 8 |
|
| Total (BOEPD) | 27,730 |
| | 21,765 |
| | 10,353 |
|
| 2019 vs 2018 Variance (BOEPD) | | | 5,965 |
| |
|
| % Change | | | 27 | % | |
|
| 2018 vs. 2017 Variance (BOEPD) | | | | | 11,412 |
|
| % Change | | | | | 110 | % |
|
| | | | | | | | |
| | Total Production by Region |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| South Texas | 10,121 |
| | 7,780 |
| | 3,487 |
|
Mid-Continent 1 | — |
| | 165 |
| | 292 |
|
| Total (MBOE) | 10,121 |
| | 7,944 |
| | 3,779 |
|
| 2019 vs 2018 Variance (MBOE) | | | 2,177 |
| | |
| % Change | | | 27 | % | | |
| 2018 vs. 2017 Variance (MBOE) | | | | | 4,165 |
|
| % Change | | | | | 110 | % |
| | Average Daily Production by Region |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| South Texas | 27,730 |
| | 21,314 |
| | 9,553 |
|
Mid-Continent 1 | — |
| | 451 |
| | 800 |
|
| Total (BOEPD) | 27,730 |
| | 21,765 |
| | 10,353 |
|
| 2019 vs 2018 Variance (BOEPD) | | | 5,965 |
| | |
| % Change | | | 27 | % | | |
| 2018 vs. 2017 Variance (BOEPD) | | | | | 11,412 |
|
| % Change | | | | | 110 | % |
1 Mid-Continent operations were sold on July 31, 2018.
2019 vs. 2018. Total production increased 27 percent during 2019 compared to 2018 due primarily to a greater number of higher working interest wells turned to sales in the fourth quarter of 2018 through December 31, 2019 when compared to the corresponding periods from the fourth quarter of 2017 through December 31, 2018 as well as the effect of a full year of production from the Hunt Acquisition. 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 more mature Eagle Ford wells.
We operated two drilling rigs during the majority of 2019 compared to three during the majority of 2018. During 2019, we turned 48 gross (43.3 net) wells to sales compared to 53 gross (45.5 net) wells during 2018. When considering the wells turned to sales in the fourth quarters of the prior years for which we would receive a full year of subsequent production, we had 58 gross (52.2 net) wells for the year ended December 31, 2019 as compared to 62 gross (50.8 net) wells for the year ended December 31, 2018.
Approximately 74 percent of total production during 2019 was attributable to crude oil when compared to approximately 76 percent during 2018. The decline in the crude oil composition of total production was due primarily to a higher gas content experienced with some of our recently drilled wells, primarily in the southeastern portion of our acreage holdings.
2018 vs. 2017. Total production increased 110 percent during 2018 compared to 2017 due primarily to a greater number of wells turned to sales in 2018 under an 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 more mature 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.
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:
|
| | | | | | | | | | | |
| | Total Product Revenues |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Crude oil | $ | 434,713 |
| | $ | 402,485 |
| | $ | 140,886 |
|
| NGLs | 16,589 |
| | 21,073 |
| | 10,066 |
|
| Natural gas | 17,733 |
| | 15,972 |
| | 8,517 |
|
| Total | $ | 469,035 |
| | $ | 439,530 |
| | $ | 159,469 |
|
| 2019 vs. 2018 Variance | | | $ | 29,505 |
| |
|
| % Change | | | 7 | % | |
|
| 2018 vs. 2017 Variance | | | | | $ | 280,061 |
|
| % Change | | | | | 176 | % |
| | Product Revenues per Unit of Volume |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Crude oil ($ per barrel) | $ | 58.33 |
| | $ | 66.23 |
| | $ | 50.96 |
|
| NGLs ($ per barrel) | $ | 11.13 |
| | $ | 20.99 |
| | $ | 19.25 |
|
| Natural gas ($ per Mcf) | $ | 2.51 |
| | $ | 3.08 |
| | $ | 2.89 |
|
| Total ($ per BOE) | $ | 46.34 |
| | $ | 55.33 |
| | $ | 42.20 |
|
| 2019 vs. 2018 Variance ($ per BOE) | | | $ | (8.99 | ) | |
|
| % Change | | | (16 | )% | |
|
| 2018 vs. 2017 Variance ($ per BOE) | | | | | $ | 13.13 |
|
| % Change | | | | | 31 | % |
|
| | | | | | | | | | | |
| | Product Revenues by Region |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| South Texas | $ | 469,035 |
| | $ | 435,599 |
| | $ | 152,521 |
|
Divested properties 1 | — |
| | 3,931 |
| | 6,948 |
|
| Total | $ | 469,035 |
| | $ | 439,530 |
| | $ | 159,469 |
|
| 2019 vs. 2018 Variance | | | $ | 29,505 |
| | |
| % Change | | | 7 | % | | |
| 2018 vs. 2017 Variance | | | | | $ | 280,061 |
|
| % Change | | | | | 176 | % |
| | Product Revenues per BOE by Region |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| South Texas | $ | 46.34 |
| | $ | 55.99 |
| | $ | 43.74 |
|
Divested properties 1 | $ | — |
| | $ | 23.87 |
| | $ | 23.79 |
|
| Total ($ per BOE) | $ | 46.34 |
| | $ | 55.33 |
| | $ | 42.20 |
|
| 2019 vs. 2018 Variance ($ per BOE) | | | $ | (8.99 | ) | | |
| % Change | | | (16 | )% | | |
| 2018 vs. 2017 Variance ($ per BOE) | | | | | $ | 13.13 |
|
| % Change | | | | | 31 | % |
1 Mid-Continent operations were sold on July 31, 2018.
The following table provides an analysis of the changes in our revenues for the periods presented:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2019 vs. | | Year Ended December 31, 2018 vs. |
| | Year Ended December 31, 2018 | | Year Ended December 31, 2017 |
| | Revenue Variance Due to | | Revenue Variance Due to |
| | Volume | | Price | | Total | | Volume | | Price | | Total |
| Crude oil | $ | 91,108 |
| | $ | (58,880 | ) | | $ | 32,228 |
| | $ | 168,812 |
| | $ | 92,787 |
| | $ | 261,599 |
|
| NGLs | 10,227 |
| | (14,711 | ) | | (4,484 | ) | | 9,259 |
| | 1,748 |
| | 11,007 |
|
| Natural gas | 5,815 |
| | (4,054 | ) | | 1,761 |
| | 6,448 |
| | 1,007 |
| | 7,455 |
|
| | $ | 107,150 |
| | $ | (77,645 | ) | | $ | 29,505 |
| | $ | 184,519 |
| | $ | 95,542 |
| | $ | 280,061 |
|
2019 vs. 2018. Our product revenues increased seven percent during 2019 over 2018 due primarily to approximately 23 percent higher crude oil volumes partially offset by 12 percent lower crude oil pricing resulting in higher overall product revenues. NGL revenues declined approximately 21 percent in 2019 due to substantially lower pricing (47 percent) partially offset by approximately 49 percent higher volumes. Natural gas revenues increased approximately 11 percent due primarily to approximately 36 percent higher volumes substantially offset by approximately 19 percent lower pricing. Crude oil revenues were approximately 93 percent of our total revenues during 2019 as compared to approximately 92 percent during 2018.
2018 vs. 2017. Our product revenues increased 176 percent during 2018 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. 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 compared to 88 percent during 2017. Total Eagle Ford revenues were approximately 99 percent of total revenues in 2018 and 96 percent during 2017. Effective August 2018, all of our revenues were derived from the Eagle Ford.
Realized Differentials
The following table reconciles our realized price differentials from weighted-average NYMEX-quoted prices for WTI crude oil for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Realized crude oil prices per barrel | $ | 58.33 |
| | $ | 66.23 |
| | $ | 50.96 |
|
| Weighted-average WTI prices | 57.04 |
| | 65.56 |
| | 51.34 |
|
| Realized differential to WTI per barrel | $ | 1.29 |
| | $ | 0.67 |
| | $ | (0.38 | ) |
We have realized premiums to the WTI index price for crude oil over the past two years as the majority of our production during those periods was sold based on LLS or MEH index pricing due to the proximity of our operating region to the Gulf Coast markets.
Effects of Derivatives
The following table reconciles crude oil revenues to realized prices, as adjusted for derivative activities, for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Crude oil revenues as reported | $ | 434,713 |
| | $ | 402,485 |
| | $ | 140,886 |
|
| Derivative settlements, net | (4,136 | ) | | (48,291 | ) | | (3,511 | ) |
| | $ | 430,577 |
| | $ | 354,194 |
|
| $ | 137,375 |
|
| | | | | | |
| Crude oil prices per Bbl, as reported | $ | 58.33 |
| | $ | 66.23 |
| | $ | 50.96 |
|
| Derivative settlements per Bbl | (0.55 | ) | | (7.95 | ) | | (1.27 | ) |
| | $ | 57.78 |
| | $ | 58.28 |
|
| $ | 49.69 |
|
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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Gain (loss) on sales of assets, net | $ | 5 |
| | $ | (177 | ) | | $ | (36 | ) |
2019, 2018 and 2017. In 2019, 2018 and 2017, we recognized insignificant net gains and losses attributable to sale or trade of certain support equipment and surplus and scrap tubular inventory and well materials.
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 current operations.
The following table sets forth the total other revenues, net for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Other revenues, net | $ | 2,176 |
| | $ | 1,479 |
| | $ | 621 |
|
2019 vs. 2018. Other revenues, net increased during 2019 from 2018 due primarily to higher water disposal revenues attributable to higher production partially offset by certain unscheduled repairs and maintenance costs incurred during the second quarter of 2019 at our water disposal facilities
2018 vs. 2017. Other revenues, net increased during 2018 from 2017 due primarily to higher marketing fees charged to third parties resulting from substantially higher production.
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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Lease operating | $ | 43,088 |
| | $ | 35,879 |
| | $ | 21,784 |
|
| Per unit of production ($/BOE) | $ | 4.26 |
| | $ | 4.52 |
| | $ | 5.76 |
|
2019 vs. 2018. LOE increased on an absolute basis, but declined on a per unit basis during 2019 when compared to 2018 due primarily to the overall effect of 27 percent higher production volume during 2019. The volume-based absolute increases were primarily attributable to compression and gas lift, water disposal, utilities and environmental costs for a combined effect of $5.6 million. Higher maintenance costs of $1.3 million were incurred in 2019. In addition, the 2019 period includes the effects of two additional months of production attributable to the Hunt Acquisition.
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.
Gathering Processing and Transportation
GPT expense 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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Gathering, processing and transportation | $ | 23,197 |
| | $ | 18,626 |
| | $ | 10,734 |
|
| Per unit of production ($/BOE) | $ | 2.29 |
| | $ | 2.34 |
| | $ | 2.84 |
|
2019 vs. 2018. GPT expense increased on an absolute basis during 2019 when compared to 2018 due primarily to substantially higher production volumes as discussed above. Per unit costs declined marginally in 2019 compared to 2018 due primarily to a shift in the mix of crude oil production sold at the wellhead with no corresponding GPT expense subsequent to the achievement of required minimum crude oil volumes transported by pipeline partially offset by a scheduled rate increase effective August 1, 2019, for crude oil gathering services provided by Nuevo Dos Gathering & Transportation, LLC, or Nuevo G&T, successor to Republic Midstream, LLC.
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.
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 assessed 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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Production and ad valorem taxes | | | | | |
| Production/severance taxes | $ | 21,774 |
| | $ | 20,619 |
| | $ | 7,533 |
|
| Ad valorem taxes | 6,283 |
| | 2,928 |
| | 1,281 |
|
| | $ | 28,057 |
| | $ | 23,547 |
| | $ | 8,814 |
|
| Per unit of production ($/BOE) | $ | 2.77 |
| | $ | 2.96 |
| | $ | 2.33 |
|
| Production/severance tax rate as a percent of product revenues | 4.6 | % | | 4.7 | % | | 4.7 | % |
2019 vs. 2018. Production taxes increased on an absolute basis, but declined on a per unit basis during 2019 when compared to 2018 due primarily to increased production volume despite lower overall commodity sales prices. Accruals for ad valorem taxes also increased substantially for the 2019 periods due to a higher commodity-price based valuation assumption and the effects of growing our assessable property base and increased working interests from acquisition activity.
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.
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 expenses, 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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Primary G&A | $ | 20,602 |
| | $ | 17,236 |
| | $ | 13,072 |
|
| Share-based compensation - equity-classified | 4,082 |
| | 4,618 |
| | 3,809 |
|
| Significant special charges | | | | | |
| Acquisition, divestiture and strategic transaction costs | 800 |
| | 3,960 |
| | 1,340 |
|
| Executive retirement costs | — |
| | 250 |
| | — |
|
| Restructuring expense adjustment | — |
| | — |
| | (20 | ) |
| Total general and administrative expenses | $ | 25,484 |
| | $ | 26,064 |
| | $ | 18,201 |
|
| Per unit of production ($/BOE) | $ | 2.52 |
| | $ | 3.28 |
| | $ | 4.82 |
|
| Per unit of production excluding all share-based compensation and other significant special charges identified above ($/BOE) | $ | 2.04 |
| | $ | 2.17 |
| | $ | 3.46 |
|
2019 vs. 2018. Our primary G&A expenses increased on an absolute basis and decreased on a per unit basis during 2019 compared to 2018. The absolute increases are due primarily to the effects of higher payroll, benefits and support costs attributable to a higher overall employee headcount. In addition, we incurred higher occupancy costs and higher consulting and related costs including those associated with the SVP/CFO transition in the second half of 2019. Higher production volume had the effect of reducing G&A per unit of production during 2019.
Equity-classified share-based compensation charges during the periods presented 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 16 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 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.
We incurred consulting and other costs in the second half of 2018 which continued into the first quarter of 2019 associated with the previously terminated merger transaction. In addition to these costs, we incurred transaction costs in 2018 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.
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.
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. In 2017, we recorded adjustments to severance-related restructuring accruals that were originally established prior to 2017.
Depreciation, Depletion and Amortization (DD&A)
DD&A expense includes charges for the allocation of property costs based on the volume of production, depreciation of fixed assets other than oil and gas assets as well as the accretion of our ARO liabilities. The following table sets forth total and per unit costs for DD&A for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| DD&A expense | $ | 174,569 |
| | $ | 127,961 |
| | $ | 48,649 |
|
| DD&A rate ($/BOE) | $ | 17.25 |
| | $ | 16.11 |
| | $ | 12.87 |
|
2019 vs. 2018. DD&A increased on an absolute and per unit basis during 2019 when compared to 2018. Higher production volume provided for an increase of approximately $35.1 million while $11.5 million was attributable to the higher DD&A rates in 2019. The higher DD&A rates in 2019 are attributable to higher costs added to the full cost pool in 2019.
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 September 2016.
Interest Expense
Interest expense includes charges for outstanding borrowings under the Credit Facility and the Second Lien Facility derived from internationally-recognized interest rates with a premium based on our credit profile and the level of credit outstanding. In addition, we are assessed certain fees for the overall credit commitments provided to us as well as fees for utilization and letters of credit. Also included is the accretion of original issue discount on the Second Lien Facility and the amortization of costs capitalized attributable to the Credit Facility and the Second Lien Facility. These costs are partially offset by interest costs that we capitalize on unproved property costs while we are engaged in the evaluation of projects for the underlying acreage.
The following table summarizes the components of our interest expense for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Interest on borrowings and related fees | $ | 36,593 |
| | 32,164 |
| | $ | 6,995 |
|
| Accretion of original issue discount | 743 |
| | 680 |
| | 161 |
|
| Amortization of debt issuance costs | 2,611 |
| | 2,736 |
| | 1,961 |
|
| Capitalized interest | (4,136 | ) | | (9,118 | ) | | (2,725 | ) |
| | $ | 35,811 |
| | $ | 26,462 |
|
| $ | 6,392 |
|
2019 vs. 2018. Interest expense increased during 2019 as compared to 2018 due primarily to higher outstanding balances under the Credit Facility partially offset by the effect of lower interest rates. Weighted-average balances under the Credit Facility were higher in 2019 compared to 2018 by approximately $119 million while the weighted-average interest rates were lower during the same period by 97 basis points. The accretion of original issue discount is entirely attributable to the Second Lien Facility and the amortization of debt issuance costs includes amounts attributable to both the Credit Facility and Second Lien Facility. We capitalized a smaller portion of interest during 2019 as we maintained a substantially smaller portion of unproved property as compared to 2018.
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 were subject to periodic increases in LIBOR rates on a consistent basis since 2017. 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.
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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Crude oil derivative gains (losses) | $ | (68,131 | ) | | $ | 37,427 |
| | $ | (17,819 | ) |
2019 vs. 2018. In 2019, the forward curve for commodity prices increased relative to our weighted-average hedged prices resulting in net losses for our derivative portfolio. We paid net cash settlements of $4.1 million and $48.3 million in 2019 and 2018, respectively.
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.
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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Other, net | $ | (153 | ) | | $ | 2,266 |
| | $ | 58 |
|
2019. Other, net income (expense) decreased during 2019 as compared to 2018 due primarily to the write-off in 2019 of $0.2 million attributable to acquisition transactions in prior years that were no longer deemed recoverable. This charge was partially offset in 2019 by recoveries of sales and use taxes attributable to previously divested properties.
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.
Reorganization Items, Net
The following table summarizes the components included in “Reorganization items, net” for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Legal and professional fees and expenses | $ | — |
| | $ | 200 |
| | $ | — |
|
| Other reorganization items | — |
| | 3,122 |
| | — |
|
| | $ | — |
| | $ | 3,322 |
|
| $ | — |
|
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 upon emergence from bankruptcy for legal and professional fees and administrative costs. In addition, we reversed the $2.7 million unallocated portion of a reserve that was established upon emergence 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 date of emergence 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.”
Income Taxes
The following table summarizes our income tax provision for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Income tax (expense) benefit | $ | (2,137 | ) | | $ | (523 | ) | | $ | 4,943 |
|
| Effective tax rate | 3.0 | % | | 0.2 | % | | 17.8 | % |
2019. The provision for the year ended December 31, 2019 includes current federal benefits of $1.2 million attributable to the anticipated refund of alternative minimum tax, or AMT, credits for the 2019 tax year. The amount for 2019 has been recognized on our Consolidated Balance Sheet as of December 31, 2019 as a current asset. These benefits have been offset by corresponding decreases in the deferred tax asset associated with AMT credit carryforwards giving rise to deferred federal expense for the year ended December 31, 2019. In addition, we have recognized a deferred state tax expense of $2.1 million attributable to property and equipment for an overall effective tax rate of 3.0%.
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 AMT credits for the 2018 tax year. The $2.5 million attributable to 2018 was refunded to us in 2019. 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 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.
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, 2019, the material off-balance sheet arrangements and transactions that we have entered into included information technology licensing, service agreements and letters of credit, all of which are customary in our business. See “Contractual Obligations” summarized below and Note 14 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, 2019:
|
| | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| | Total | | Less than 1 Year | | 1-3 Years | | 3-5 Years | | More Than 5 Years |
Credit Facility 1 | $ | 362,400 |
| | $ | — |
| | $ | — |
| | $ | 362,400 |
| | $ | — |
|
Second Lien Facility 2 | 200,000 |
| | — |
| | — |
| | 200,000 |
| | — |
|
Interest payments on long-term debt 3 | 107,405 |
| | 31,209 |
| | 57,879 |
| | 18,317 |
| | — |
|
Operating leases 4 | 3,483 |
| | 847 |
| | 1,664 |
| | 972 |
| | — |
|
Crude oil gathering and transportation commitments 5 | 102,598 |
| | 12,962 |
| | 25,924 |
| | 25,924 |
| | 37,788 |
|
Asset retirement obligations 6 | 113,050 |
| | — |
| | — |
| | — |
| | 113,050 |
|
| Derivatives | 20,488 |
| | 19,853 |
| | 635 |
| | — |
| | — |
|
Other commitments 7 | 499 |
| | 289 |
| | 210 |
| | — |
| | — |
|
| Total contractual obligations | $ | 909,923 |
| | $ | 65,160 |
| | $ | 86,312 |
| | $ | 607,613 |
| | $ | 150,838 |
|
1 Assumes that the amount outstanding of $362 million as of December 31, 2019 will remain outstanding until its maturity in 2024. 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 9 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, 2019 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 9 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, 2019 remain in effect and the amounts outstanding of $362.4 million and $200 million as of December 31, 2019, respectively, will remain outstanding until their maturities in 2024 and 2022, respectively.
| |
4 | Relates primarily to office facilities and equipment leases as described in Note 11 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” |
| |
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 | Represents the undiscounted balance payable, primarily for the plugging of inactive wells, in periods more than five years in the future for which $4.9 million, on a discounted basis, has been recognized on our Consolidated Balance Sheet as of December 31, 2019 and illustrated in Note 8 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” 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. |
| |
7 | Represents all other significant obligations including information technology licensing and service agreements, among others as described in Note 14 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” |
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.
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
We apply 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, 2019, the carrying value of our proved oil and gas properties was below the limit determined by the Ceiling Test by approximately $480 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.
Leases
Implicit in the recognition and measurement of our lease obligations and the related right-of-use, or ROU, assets are certain assumptions regarding discount rates, renewal options, cost escalations and other factors. Depending upon the length of term, including extensions if applicable, the magnitude of certain contractual costs and the applicable discount rate, certain of these critical assumptions could have a material impact on the underlying measurement.
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, 2019, we had a full valuation allowance for all of our 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. 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. We will adopt ASU 2016–13 effective January 1, 2020. While we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures, we will be applying new procedures and controls to our customer and partner billing processes in order to apply the expected loss model on a monthly basis.
| |
| 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, 2019, we had borrowings of $362.4 million under the Credit Facility at an interest rate of 3.75%. As of December 31, 2019, we had borrowings of $192.6 million under the Second Lien Facility, net of OID and issuance costs, at an interest rate of 8.81%. 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 $5.6 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. As of December 31, 2019, we were not utilizing any derivative instruments with respect to NGLs and natural gas, although we may do so in the future.
As of December 31, 2019, we reported net commodity derivative liabilities of $20.0 million. The contracts associated with this position are with nine 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, 2019, we reported net commodity derivative losses of $68.1 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in crude oil, NGL and natural gas prices. These fluctuations could be significant in a volatile pricing environment. See Note 6 to our Consolidated Financial Statements included in Part II, Item 8, included in Part II, Item 8, “Financial Statements and Supplementary Data” for a further description of our price risk management activities.
The following table sets forth our commodity derivative positions as of December 31, 2019:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 1Q2020 | | 2Q2020 | | 3Q2020 | | 4Q2020 | | 1Q2021 | | 2Q2021 | | 3Q2021 | | 4Q2021 |
| NYMEX WTI Crude Swaps | |
| |
| |
| |
| |
| |
| |
| |
|
| Average Volume Per Day (barrels) | | 15,648 |
| | 12,648 |
| | 10,630 |
| | 10,630 |
| | 3,333 |
| | 3,297 |
| | 1,630 |
| | 1,630 |
|
| Weighted Average Swap Price ($/barrel) | | $ | 55.34 |
| | $ | 54.96 |
| | $ | 54.77 |
| | $ | 54.77 |
| | $ | 55.89 |
| | $ | 55.89 |
| | $ | 55.50 |
| | $ | 55.50 |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| NYMEX WTI Purchased Puts/Sold Calls | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| Average Volume Per Day (barrels) | |
|
| | 3,297 |
| | 4,891 |
| |
|
| | 1,667 |
| | 1,648 |
| |
|
| |
|
|
| Weighted Average Purchased Put Price ($/barrel) | |
|
| | $ | 55.00 |
| | $ | 55.00 |
| |
|
| | $ | 55.00 |
| | $ | 55.00 |
| |
|
| |
|
|
| Weighted Average Sold Call ($/barrel) | |
|
| | $ | 57.69 |
| | $ | 58.42 |
| |
|
| | $ | 58.00 |
| | $ | 58.00 |
| |
|
| |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| NYMEX WTI Sold Puts | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| Average Volume Per Day (barrels) | |
|
| |
|
| |
|
| |
|
| | 5,000 |
| | 4,945 |
| | 1,630 |
| | 1,630 |
|
| Weighted Average Sold Put Price ($/barrel) | |
|
| |
|
| |
|
| |
|
| | $ | 44.00 |
| | $ | 44.00 |
| | $ | 44.00 |
| | $ | 44.00 |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| MEH Crude Swaps | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| Average Volume Per Day (barrels) | | 2,000 |
| | 2,000 |
| | 2,000 |
| | 2,000 |
| |
|
| |
|
| |
|
| |
|
|
| Weighted Average Swap Price ($/barrel) | | $ | 61.03 |
| | $ | 61.03 |
| | $ | 61.03 |
| | $ | 61.03 |
| |
|
| |
|
| |
|
| |
|
|
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) |
| | Increase |
| | Decrease |
|
Effect on the fair value of crude oil derivatives 1 | $ | (69.8 | ) | | $ | 66.6 |
|
Effect on 2020 operating income, excluding crude oil derivatives 2 | $ | 29.0 |
| | $ | (27.0 | ) |
1 Based on derivatives outstanding as of December 31, 2019.
2 Based on our 2020 Business Plan consistent with the assumptions used to determine our proved reserves as disclosed in Item 2, “Properties – Summary of Oil and Gas Reserves.” These sensitivities are subject to significant change
| |
| Item 8 | Financial Statements and Supplementary Data |
PENN VIRGINIA CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
| |
| Page |
Age, Business Experience, Other Directorships and QualificationsReports of Independent Registered Public Accounting Firm | | Director of the Company Since |
John A. Brooks, age 57
Consolidated Statements of Operations | | 2017 |
Mr. John A. Brooks has served on the Board and as President and CEOConsolidated Statements of the Company since August 2017. Mr. Brooks had previously served in several management roles for Penn Virginia, including as Interim Principal Executive OfficerComprehensive Income | |
| Consolidated Balance Sheets | |
Consolidated Statements of Penn Virginia Corporation from September 2016Cash Flows | |
| Consolidated Statements of Shareholders’ Equity | |
Notes to August 2017, as Executive Vice President and Chief Operating Officer from January 2014 to August 2017, as Executive Vice President, Operations from February 2013 to January 2014, Senior Vice President from February 2012 to February 2013 and Vice President from May 2008 to February 2012 and as Penn Virginia Oil & Gas Corporation’s Vice President and Regional Manager from October 2007 to February 2012, Operations Manager from January 2005 to October 2007 and Drilling Manager from February 2002 to January 2005. Mr. Brooks received his B.S. in Petroleum Engineering from the University of Texas at Austin in 1984. The Board believes that Mr. Brooks’ experience in the exploration and production industry and detailed knowledge of our operations lends critical support to the Board’s decision making process. | Consolidated Financial Statements: | |
| 1. Nature of Operations | |
| 2. Basis of Presentation | |
| 3. Summary of Significant Accounting Policies | |
| 4. Acquisitions and Divestitures | |
| 5. Accounts Receivable and Major Customers | |
| 6. Derivative Instruments | |
| 7. Property and Equipment | |
| 8. Asset Retirement Obligations | |
| 9. Long-Term Debt | |
| 10. Income Taxes | |
| 11. Leases | |
| 12. Additional Balance Sheet Detail | |
| 13. Fair Value Measurements | |
| 14. Commitments and Contingencies | |
| 15. Shareholders’ Equity | |
| 16. Share-Based Compensation and Other Benefit Plans | |
| 17. Interest Expense | |
| 18. Earnings per Share | |
| Supplemental Quarterly Financial Information (unaudited) | |
| Supplemental Information on Oil and Gas Producing Activities (unaudited) | |
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, 2019 and 2018, the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, thefinancial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2019 and 2018, and the results of itsoperations and itscash flows for each of the three years in the period ended December 31, 2019, 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, 2019, 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 28, 2020 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 28, 2020
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, 2019, 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, 2019, 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, 2019, and our report dated February 28, 2020 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 28, 2020
PENN VIRGINIA CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Revenues | | | | | |
|
| Crude oil | $ | 434,713 |
| | $ | 402,485 |
| | $ | 140,886 |
|
| Natural gas liquids | 16,589 |
| | 21,073 |
| | 10,066 |
|
| Natural gas | 17,733 |
| | 15,972 |
| | 8,517 |
|
| Gain (loss) on sales of assets, net | 5 |
| | (177 | ) | | (36 | ) |
| Other revenues, net | 2,176 |
| | 1,479 |
| | 621 |
|
| Total revenues | 471,216 |
| | 440,832 |
| | 160,054 |
|
| Operating expenses | | | | | |
|
| Lease operating | 43,088 |
| | 35,879 |
| | 21,784 |
|
| Gathering, processing and transportation | 23,197 |
| | 18,626 |
| | 10,734 |
|
| Production and ad valorem taxes | 28,057 |
| | 23,547 |
| | 8,814 |
|
| General and administrative | 25,484 |
| | 26,064 |
| | 18,201 |
|
| Depreciation, depletion and amortization | 174,569 |
| | 127,961 |
| | 48,649 |
|
| Total operating expenses | 294,395 |
| | 232,077 |
| | 108,182 |
|
| Operating income | 176,821 |
| | 208,755 |
| | 51,872 |
|
| Other income (expense) | | | | | |
|
| Interest expense, net of amounts capitalized | (35,811 | ) | | (26,462 | ) | | (6,392 | ) |
| Derivatives | (68,131 | ) | | 37,427 |
| | (17,819 | ) |
| Other, net | (153 | ) | | 2,266 |
| | 58 |
|
| Reorganization items, net | — |
| | 3,322 |
| | — |
|
| Income before income taxes | 72,726 |
| | 225,308 |
| | 27,719 |
|
| Income tax (expense) benefit | (2,137 | ) | | (523 | ) | | 4,943 |
|
| Net income | $ | 70,589 |
| | $ | 224,785 |
| | $ | 32,662 |
|
| | | | | | |
| Net income per share: | | | | | |
|
| Basic | $ | 4.67 |
| | $ | 14.93 |
| | $ | 2.18 |
|
| Diluted | $ | 4.67 |
| | $ | 14.70 |
| | $ | 2.17 |
|
| | | | | | |
| Weighted average shares outstanding – basic | 15,110 |
| | 15,059 |
| | 14,996 |
|
| Weighted average shares outstanding – diluted | 15,126 |
| | 15,292 |
| | 15,063 |
|
See accompanying notes to consolidated financial statements.
PENN VIRGINIA CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Net income | $ | 70,589 |
| | $ | 224,785 |
| | $ | 32,662 |
|
| Other comprehensive income (loss): | | | | | |
| Change in pension and postretirement obligations, net of tax | (141 | ) | | 82 |
| | (73 | ) |
| | (141 | ) | | 82 |
| | (73 | ) |
| Comprehensive income | $ | 70,448 |
| | $ | 224,867 |
| | $ | 32,589 |
|
See accompanying notes to consolidated financial statements.
PENN VIRGINIA CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| Assets | |
| | |
|
| Current assets | |
| | |
|
| Cash and cash equivalents | $ | 7,798 |
| | $ | 17,864 |
|
| Accounts receivable, net of allowance for doubtful accounts | 70,716 |
| | 66,038 |
|
| Derivative assets | 4,131 |
| | 34,932 |
|
| Income taxes receivable | 1,236 |
| | 2,471 |
|
| Other current assets | 4,458 |
| | 5,125 |
|
| Total current assets | 88,339 |
| | 126,430 |
|
| Property and equipment, net (full cost method) | 1,120,425 |
| | 927,994 |
|
| Derivative assets | 2,750 |
| | 10,100 |
|
| Deferred income taxes | — |
| | 1,949 |
|
| Other assets | 6,724 |
| | 2,481 |
|
| Total assets | $ | 1,218,238 |
| | $ | 1,068,954 |
|
| | | | |
| Liabilities and Shareholders’ Equity | |
| | |
|
| Current liabilities | |
| | |
|
| Accounts payable and accrued liabilities | $ | 105,824 |
| | $ | 103,700 |
|
| Derivative liabilities | 23,450 |
| | 991 |
|
| Total current liabilities | 129,274 |
| | 104,691 |
|
| Other liabilities | 8,382 |
| | 5,533 |
|
| Deferred income taxes | 1,424 |
| | — |
|
| Derivative liabilities | 3,385 |
| | — |
|
| Long-term debt, net | 555,028 |
| | 511,375 |
|
| | | | |
| Commitments and contingencies (Note 14) |
|
| |
|
|
| | | | |
| 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; 15,135,598 and 15,080,594 shares issued as of December 31, 2019 and December 31, 2018, respectively | 151 |
| | 151 |
|
| Paid-in capital | 200,666 |
| | 197,630 |
|
| Retained earnings | 319,987 |
| | 249,492 |
|
| Accumulated other comprehensive income (loss) | (59 | ) | | 82 |
|
| Total shareholders’ equity | 520,745 |
| | 447,355 |
|
| Total liabilities and shareholders’ equity | $ | 1,218,238 |
| | $ | 1,068,954 |
|
See accompanying notes to consolidated financial statements.
PENN VIRGINIA CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 70,589 |
| | $ | 224,785 |
| | $ | 32,662 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Non-cash reorganization items | — |
| | (3,322 | ) | | — |
|
| Depreciation, depletion and amortization | 174,569 |
| | 127,961 |
| | 48,649 |
|
| Derivative contracts: | | | | | |
| Net (gains) losses | 68,131 |
| | (37,427 | ) | | 17,819 |
|
| Cash settlements, net | (4,136 | ) | | (48,291 | ) | | (3,511 | ) |
| Deferred income tax expense (benefit) | 3,373 |
| | 2,994 |
| | (4,943 | ) |
| Loss (gain) on sales of assets, net | (5 | ) | | 177 |
| | 36 |
|
| Non-cash interest expense | 3,354 |
| | 3,416 |
| | 2,122 |
|
| Share-based compensation (equity-classified) | 4,082 |
| | 4,618 |
| | 3,809 |
|
| Other, net | 52 |
| | 44 |
| | 61 |
|
| Changes in operating assets and liabilities: | | | | | |
| Accounts receivable, net | (5,079 | ) | | (23,674 | ) | | (43,318 | ) |
| Accounts payable and accrued expenses | 4,690 |
| | 21,109 |
| | 28,542 |
|
| Other assets and liabilities | 574 |
| | (258 | ) | | (218 | ) |
| Net cash provided by operating activities | 320,194 |
| | 272,132 |
| | 81,710 |
|
| Cash flows from investing activities | | | | | |
| Acquisitions, net | (6,516 | ) | | (85,387 | ) | | (200,849 | ) |
| Capital expenditures | (362,743 | ) | | (430,592 | ) | | (115,687 | ) |
| Proceeds from sales of assets, net | 215 |
| | 7,683 |
| | 869 |
|
| Net cash used in investing activities | (369,044 | ) | | (508,296 | ) | | (315,667 | ) |
| Cash flows from financing activities | | | | | |
| Proceeds from credit facility borrowings | 76,400 |
| | 244,000 |
| | 59,000 |
|
| Repayment of credit facility borrowings | (35,000 | ) | | — |
| | (7,000 | ) |
| Proceeds from second lien note | — |
| | — |
| | 196,000 |
|
| Debt issuance costs paid | (2,616 | ) | | (989 | ) | | (9,787 | ) |
| Proceeds received from rights offering, net | — |
| | — |
| | 55 |
|
| Other, net | — |
| | — |
| | (55 | ) |
| Net cash provided by financing activities | 38,784 |
| | 243,011 |
| | 238,213 |
|
| Net increase (decrease) in cash and cash equivalents | (10,066 | ) | | 6,847 |
| | 4,256 |
|
| Cash and cash equivalents - beginning of period | 17,864 |
| | 11,017 |
| | 6,761 |
|
| Cash and cash equivalents - end of period | $ | 7,798 |
| | $ | 17,864 |
| | $ | 11,017 |
|
| Supplemental disclosures: | | | | | |
| Cash paid for: | | | | | |
| Interest, net of amounts capitalized | $ | 32,398 |
| | $ | 22,599 |
| | $ | 4,102 |
|
| Income taxes, net of (refunds) | $ | (2,471 | ) | | $ | — |
| | $ | — |
|
| Reorganization items, net | $ | 79 |
| | $ | 540 |
| | $ | 954 |
|
| Non-cash investing and financing activities: | | | | | |
| Changes in accounts receivable, net related to acquisitions | $ | (152 | ) | | $ | (27,107 | ) | | $ | (2,583 | ) |
| Changes in other assets related to acquisitions | $ | — |
| | $ | (743 | ) | | $ | 3,201 |
|
| Changes in accrued liabilities related to acquisitions | $ | (540 | ) | | $ | (11,182 | ) | | $ | (2,507 | ) |
| Changes in accrued liabilities related to capital expenditures | $ | (3,602 | ) | | $ | 44 |
| | $ | 19,910 |
|
| Changes in other liabilities for asset retirement obligations related to acquisitions | $ | 83 |
| | $ | 385 |
| | $ | 494 |
|
See accompanying notes to consolidated financial statements.
PENN VIRGINIA CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in thousands)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Shares Outstanding | | Preferred Stock | | Common Stock | | Paid-in Capital | | Retained Earnings (Accumulated Deficit) | | Accumulated Other Comprehensive Income (Loss) | | Total Shareholders’ Equity |
| December 31, 2016 | 14,992 |
| | $ | — |
| | $ | 150 |
| | $ | 190,621 |
| | $ | (5,296 | ) | | $ | 73 |
| | $ | 185,548 |
|
| Net Income | — |
| | — |
| | — |
| | — |
| | 32,662 |
| | — |
| | 32,662 |
|
| Share-based compensation | — |
| | — |
| | — |
| | 3,809 |
| | — |
| | — |
| | 3,809 |
|
| Restricted stock unit vesting | 27 |
| | — |
| | — |
| | (351 | ) | | — |
| | — |
| | (351 | ) |
| All other changes | — |
| | — |
| | — |
| | 44 |
| | — |
| | (73 | ) | | (29 | ) |
| December 31, 2017 | 15,019 |
| | — |
| | 150 |
| | 194,123 |
| | 27,366 |
| | — |
| | 221,639 |
|
| Net Income | — |
| | — |
| | — |
| | — |
| | 224,785 |
| | — |
| | 224,785 |
|
| Share-based compensation | — |
| | — |
| | — |
| | 4,618 |
| | — |
| | — |
| | 4,618 |
|
| Restricted stock unit vesting | 61 |
| | — |
| | 1 |
| | (1,111 | ) | | — |
| | — |
| | (1,110 | ) |
| Cumulative effect of change in accounting principle (see Note 5) | — |
| | — |
| | — |
| | — |
| | (2,659 | ) | | — |
| | (2,659 | ) |
| All other changes | — |
| | — |
| | — |
| | — |
| | — |
| | 82 |
| | 82 |
|
| December 31, 2018 | 15,080 |
| | — |
| | 151 |
| | 197,630 |
| | 249,492 |
| | $ | 82 |
| | 447,355 |
|
| Net Income | — |
| | — |
| | — |
| | — |
| | 70,589 |
| | — |
| | 70,589 |
|
| Share-based compensation | — |
| | — |
| | — |
| | 4,082 |
| | — |
| | — |
| | 4,082 |
|
| Restricted stock unit vesting | 56 |
| | — |
| | — |
| | (1,046 | ) | | — |
| | — |
| | (1,046 | ) |
| Cumulative effect of change in accounting principle (see Note 11) | — |
| | — |
| | — |
| | — |
| | (94 | ) | | — |
| | (94 | ) |
| All other changes | — |
| | — |
| | — |
| | — |
| | — |
| | (141 | ) | | (141 | ) |
| December 31, 2019 | 15,136 |
| | $ | — |
| | $ | 151 |
| | $ | 200,666 |
| | $ | 319,987 |
| | $ | (59 | ) | | $ | 520,745 |
|
See accompanying notes to consolidated financial statements.
PENN VIRGINIA CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except per share amounts or where otherwise indicated)
|
| | |
Michael Hanna, age 39
| 1. | 2018 (2)Nature of Operations
|
Mr. Michael Hanna has served on the Board since January 2018 and is a Partner and Portfolio Manager of KLS Diversified Asset Management LP (“KLS”), one of our shareholders. Mr. Hanna joined KLS in July 2015 and has 16 years of investment banking and portfolio management experience. Prior to joining KLS, Mr. Hanna was a Portfolio Manager and Head of Trading at BulwarkBay Investment Group, LLC, an investment firm he co-founded in 2011. Previously, he was a portfolio manager with Concordia Advisors LLC, where he co-managed the firm’s Distressed Debt Fund. Mr. Hanna joined Concordia in 2005. Prior to joining Concordia, he worked in the Leveraged Finance/Financial Sponsors and Global Corporate Investment Banking groups of RBC Capital Markets from 2004 to 2005 and Bank of America Merrill Lynch from 2001 to 2004. Mr. Hanna’s industry experience includes oil & gas, industrials, paper and forest products, insurance and financials, aerospace and energy. He is a member of the board of directors of Modular Space Corporation and Sensei, Inc. Mr. Hanna received a B.A. from the University of Michigan in 2001 and is a CFA Charter holder. The Board believes that Mr. Hanna’s prior experience in finance and his affiliation with one of the Company’s shareholders provides significant contributions to our Board. | | |
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 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.
|
| | |
Darin G. Holderness, age 55
| 2. | 2016 (1)(2)(3)Basis of Presentation
|
Mr. Darin G. Holderness, CPA has served on the Board since September 2016 and as Chairman of the Board since February 2018. Mr. Holderness was the Senior Vice President, Chief Financial Officer and Treasurer of Concho Resources Inc., an oil and gas exploration and development company, until May 2016. Mr. Holderness has over 20 years of experience in the energy sector, including nine years with KPMG LLP where his practice was focused in the energy industry, and over 17 years in the industry in increasing roles of responsibility, including serving as Vice President and Controller of Pure Resources, Inc., Vice President and Chief Financial Officer of Basic Energy Services, Inc., Vice President and Chief Accounting Officer of Pioneer Natural Resources Company, and most recently as Senior Vice President and Chief Financial Officer of Eagle Rock Energy Partners, L.P. Mr. Holderness is a 1986 graduate of Boise State University with a Bachelor of Business Administration in Accounting and is a Certified Public Accountant. The Board believes that Mr. Holderness’ prior experience as an executive and his past audit, accounting and financial reporting experience provide significant contributions to our Board. | | |
Adoption of Recently Issued Accounting Pronouncements and Comparability to Prior Periods
Effective January 1, 2019, we adopted and began applying the relevant guidance provided in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Update (“ASU”) 2016–02, Leases (“ASU 2016–02”) and related amendments to accounting principles generally accepted in the United States of America (“GAAP”) which, together with ASU 2016–02, represent Accounting Standards Codification (“ASC”) Topic 842, Leases (“ASC Topic 842”). We adopted ASC Topic 842 using the optional transition approach with a charge to the beginning balance of retained earnings as of January 1, 2019 (see Note 11 for the impact and disclosures associated with the adoption of ASC Topic 842).
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 ASC Topic 606, Revenues from Contracts with Customers (“ASC Topic 606”). We adopted ASC Topic 606 using the cumulative effect transition method (see Note 5 for the impact and disclosures associated with the adoption of ASC Topic 606).
Comparative periods and related disclosures have not been restated for the application of ASC Topic 842 and ASC Topic 606. Accordingly, certain components of our Consolidated Financial Statements are not comparable between periods and the Consolidated Statement of Operations for the year ended December 31, 2017 is presented based on prior GAAP for both revenue recognition and leases in their entirety.
Recently Issued Accounting Pronouncements Pending Adoption
In June 2016, the 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. We will adopt ASU 2016–13 effective January 1, 2020. While we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures, we will be applying new procedures and controls to our customer and partner billing processes in order to apply the expected loss model on a monthly basis.
Going Concern Presumption
Our Consolidated Financial Statements 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, other than the entry into additional commodity derivative contracts including crude oil and natural gas hedges and certain interest rate swap agreements (see Note 6), all in the ordinary course of business, no subsequent events have occurred that would require recognition in our Consolidated Financial Statements or disclosure in the Notes thereto.
|
| | |
V. Frank Pottow, age 55
3. | | 2018 (1)(3)
|
Mr. V. Frank Pottow has served on the Board since September 2018. Mr. Pottow is the Co-FounderSummary of GCP Capital Partners LLC (“GCP Capital”) and has been a Managing Director and member of the investment committee of GCP Capital and Greenhill Capital Partners since July 2002. Mr. Pottow has more than 25 years of private equity investment experience, with a focus on energy companies. Prior to GCP Capital, Mr. Pottow was a founding partner of Société Générale’s US private equity affiliate SG Capital Partners and a Principal of Odyssey Partners, L.P. Mr. Pottow graduated cum laude from The Wharton School of the University of Pennsylvania in 1986 and from Harvard Business School with high distinction as a Baker Scholar in 1990. The Board believes that Mr. Pottow’s more than 20 years' experience with energy companies and his financial expertise provide significant contributions to our Board. | | 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 the underlying 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. 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.
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.
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.
Leases
We determine if an arrangement is a lease at the inception of the underlying contractual arrangement. In addition, we determine whether the lease is classified as operating or financing. As of the date of adoption of ASC Topic 842 and through December 31, 2019, we do not have any financing leases. Leases are included in the captions “Other assets,” “Accounts payable and accrued liabilities” and “Other liabilities” on our Consolidated Balance Sheets and are identified as Right-of-use (“ROU”) assets, Current lease obligations and Noncurrent lease obligations, respectively, in Notes 11 and 12.
ROU assets represent our right to use an underlying asset for the lease term and lease obligations represent our obligation to make lease payments arising from the underlying contractual arrangement. Operating lease ROU assets and obligations are recognized at the commencement date based on the present value of lease payments over the lease term. The operating lease ROU assets include any lease payments made in advance and excludes lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise such options. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.
Most of our leasing arrangements do not identify or otherwise provide for an implicit interest rate. Accordingly, we utilize a secured incremental borrowing rate based on information available at the commencement date in the determination of the present value of the lease payments. As most of our lease arrangements have terms ranging from two to 5 years, our secured incremental borrowing rate is primarily based on the rates applicable to our credit agreement (the “Credit Facility”).
We have lease arrangements that include lease and certain non-lease components, including amounts for related taxes, insurance, common area maintenance and similar terms. We have elected to apply a practical expedient provided in ASC Topic 842 to not separate the lease and non-lease components. Accordingly, the ROU assets and lease obligations for such leases will include the present value of the estimated payments for the non-lease components over the lease term.
Certain of our lease arrangements with contractual terms of 12 months or less are classified as short-term leases. Accordingly, we have elected to not include the underlying ROU assets and lease obligations on our Consolidated Balance Sheets. The associated costs are aggregated with all of our other lease arrangements and are disclosed in the tables in Note 11.
Certain of our lease arrangements result in variable lease payments which, in accordance with ASC Topic 842, do not give rise to lease obligations. Rather, the basis and terms and conditions upon which such variable lease payments are determined are disclosed in Note 11.
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 Recognitionand 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, 2019, 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.
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 equity-classified awards are generally amortized on a straight-line basis over the applicable vesting period except for those that are based on performance which are amortized on a graded basis over the term of the applicable performance periods. Compensation cost associated with 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. 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.
Reorganization Items
We emerged from bankruptcy in September 2016 and a final decree was issued in November 2018, at which time we recognized all final adjustments associated with the discharge action. These adjustments included certain gains and losses and are included in this caption on our Consolidated Statement of Operations as these items of income are directly attributable to the final administration of our bankruptcy case and not a part of our continuing operations.
4. Acquisitions and Divestitures
Acquisitions
Eagle Ford Working Interests
In 2019, we acquired working interests in certain properties for which we are the operator from our joint venture partners in a series of transactions for cash consideration of $6.5 million. Funding for these acquisition was provided by borrowings under the Credit Facility.
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, covering approximately 9,700 net acres primarily in Gonzales County, Texas for $86.0 million in cash (the “Hunt Acquisition”). The Hunt Acquisition had an effective date of October 1, 2017 and closed in 2018. We paid total cash consideration of $83.0 million, net of suspended revenues received, for the Hunt Acquisition in 2018. 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, along with $0.2 million of certain working capital adjustments which we have reflected as components of the total net assets acquired. We funded the Hunt Acquisition with borrowings under the Credit Facility.
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 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 | | $ | 82,443 |
|
| Oil and gas properties - unproved | | 16,339 |
|
| Liabilities | | |
| Revenue suspense | | 1,448 |
|
| Asset retirement obligations | | 356 |
|
| Net assets acquired | | $ | 96,978 |
|
| | | |
| Cash consideration paid to Hunt, net | | $ | 82,955 |
|
| Application of working capital adjustments | | 245 |
|
| Accumulated costs, net of suspended revenues, for wells in which Hunt had rights to participate | | 13,778 |
|
| Total acquisition costs incurred | | $ | 96,978 |
|
Devon Acquisition
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”). We also acquired working interests in the Devon Properties from parties that had tag-along rights to sell their interests under the Purchase Agreement. The Devon Acquisition had an effective date of March 1, 2017 andclosed in September 2017. We paid total cash consideration of $199.8 million for the Devon Acquisition including $200.9 million paid in 2017 net of $1.1 million of suspended revenues and other adjustments paid to us in 2018 in connection with a final settlement. The Devon Acquisition was financed with the net proceeds received from borrowings under the $200 million Second Lien Credit Agreement dated as of September 29, 2017 (the “Second Lien Facility”) (see Note 9 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.
We accounted for the Devon Acquisition by applying the acquisition method of accounting as of September 29, 2017. 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 | | $ | 42,866 |
|
| Oil and gas properties - unproved | | 146,686 |
|
| Other property and equipment | | 8,642 |
|
| Liabilities | | |
| Revenue suspense | | 355 |
|
| Asset retirement obligations | | 494 |
|
| Net assets acquired | | $ | 197,345 |
|
| | | |
| Cash consideration paid to Devon and tag-along parties, net | | $ | 199,796 |
|
| Application of working capital adjustments, net | | (2,451 | ) |
| Total consideration | | $ | 197,345 |
|
Valuation of Acquisitions
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.
|
| | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 |
| Total revenues | $ | 446,077 |
| | $ | 209,015 |
|
| Net income | $ | 227,930 |
| | $ | 30,861 |
|
| Net income per share - basic | $ | 15.14 |
| | $ | 2.06 |
|
| Net income per share - diluted | $ | 14.91 |
| | $ | 2.05 |
|
Divestitures
Mid-Continent Divestiture
In June 2018, we entered into a purchase and sale agreement with a third party to fully divest our Mid-Continent operations and sell all of our remaining 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 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 all of 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 our former Mid-Continent operating region 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.
|
| | |
Jerry R. Schuyler, age 64
| 5. | 2016 (1)(2)(3)Accounts Receivable and Major Customers
|
Mr. Jerry R. Schuyler has served on the Board since October 2016. Mr. Schuyler is currently interim Chief Executive Officer and Chairman of the Board of Gastar Exploration Inc. He served as Executive Vice President, Chief Operating Officer and Director of Laredo Petroleum, Inc. beginning in June 2007, was promoted to President and Chief Operating Officer in July 2008 and retired in July 2013. Mr. Schuyler served as an independent director for Yates Petroleum Corporation from December 2015 until the sale of the company in October 2016; an independent director for Rosetta Resources Inc. from December 2013 until the company was sold in July 2015 and an independent director for Gulf Coast Energy Resources, LLC from 2010 until the sale of the company in April 2015. Mr. Schuyler holds a B.S. in Petroleum Engineering from Montana College of Mineral Science and Technology and attended several graduate business courses at the University of Houston. The Board believes that Mr. Schuyler’s prior experience as an executive and director of numerous energy companies provides significant contributions to our Board. | | |
The following table summarizes our accounts receivable by type as of the dates presented:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| Customers | $ | 63,165 |
| | $ | 59,030 |
|
| Joint interest partners | 6,929 |
| | 6,404 |
|
| Other | 674 |
| | 640 |
|
| | 70,768 |
| | 66,074 |
|
| Less: Allowance for doubtful accounts | (52 | ) | | (36 | ) |
| | $ | 70,716 |
| | $ | 66,038 |
|
For the year ended December 31, 2019, 4 customers accounted for $354.6 million, or approximately 76% of our consolidated product revenues. The revenues generated from these customers during 2019 were $172.3 million, $84.6 million, $50.7 million and $47.0 million or 37%, 18%, 11% and 10% of the consolidated total, respectively. As of December 31, 2019, $44.5 million, or approximately 70% of our consolidated accounts receivable from customers was related to these customers. For the year ended December 31, 2018, 3 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 approximately 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. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers. The allowance for doubtful accounts is entirely attributable to certain receivables from joint interest partners.
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.
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.
|
| | |
Brian Steck, age 52
6. | Derivative Instruments |
We utilize derivative instruments, typically swaps, two- and three-way collars and enhanced swaps which are placed with financial institutions that we believe are acceptable credit risks, to mitigate our financial exposure to commodity price volatility associated with anticipated sales of our future production and volatility in interest rates attributable to our variable rate debt instruments. Our derivative instruments are not formally designated as hedges in the context of GAAP. While the use of derivative instruments limits the risk of adverse commodity price and interest rate movements, such use may also limit future product revenues and interest expense from favorable price and rate movements. In addition, we do not utilize derivative instruments for speculative purposes. As of December 31, 2019, we were unhedged with respect to NGL and natural gas production and we had no interest rate hedges outstanding. The following is a general description of the derivative instruments we have employed:
Swaps. The counterparty to a swap contract is required to make a payment to us if the settlement price for any settlement period is below the 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 swap price for such contract.
Two-Way Collars. The counterparty to a two-way collar contract is required to make a payment to us if the settlement price for any settlement period is below the floor 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 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.
Three-Way Collars. A three-way collar consists of (i) a purchased put option which establishes a floor price for the collar, (ii) a sold call option which establishes a ceiling price of the collar and (iii) a sold put option which establishes a sub-floor price. Three-way collars are settled based on differences between the floor or ceiling prices and the settlement price of a referenced index or the difference between the floor price and sub-floor price. If the settlement price of the referenced index is below the sub-floor price, the counterparty is required to make a payment to us for the difference between the floor price and sub-floor price. If the settlement price of the referenced index is between the floor price and sub-floor price, the counterparty is required to make a payment to us for the difference between the floor price and the settlement price of the referenced index. If the settlement price of the referenced index is between the floor price and ceiling price, no payments are due to or from either party. If the settlement price of the referenced index is above the ceiling price, we are required to make a payment to the counterparty for the difference.
Enhanced Swaps. An enhanced swap consists of a sold put option with the associated premiums rolled into an enhanced fixed price swap. The counterparty to an enhanced swap contract is required to make a payment to us if the settlement price for any settlement period is below the 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 swap price for such contract. Additionally, we are required to make a payment to the counterparty if the settlement price for any settlement period is below the sold-put strike price. Effectively, when the settlement price for any settlement period is below the sold-put strike price, we receive the swap price minus the sold put strike price.
We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate (“WTI”), Louisiana Light Sweet (“LLS”) and Magellan East Houston (“MEH”) 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.
Subsequent Events
In January of 2020, we entered into additional commodity hedge contracts as well as certain interest rate swap transactions. We replaced a portion of two crude oil swaps with a costless collar for 2,000 BOPD for April through December 2020 with floor and ceiling prices of $48.00 and $57.10 per barrel. We entered into a costless collar for Henry Hub natural gas for 270,000 MMBTU per month with a term from February through December of 2020 with floor and ceiling prices of $2.00 and $2.18 per MMBTU, respectively. In January and February 2020, we entered into interest rate swaps contracts through May 2022 for a notional amount of $300 million, paying a weighted-average fixed rate of 1.36%.
The following table sets forth our commodity derivative contracts as of December 31, 2019:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 1Q2020 | | 2Q2020 | | 3Q2020 | | 4Q2020 | | 1Q2021 | | 2Q2021 | | 3Q2021 | | 4Q2021 |
| NYMEX WTI Crude Swaps | |
| |
| |
| |
| |
| |
| |
| |
|
| Average Volume Per Day (barrels) | | 15,648 |
| | 12,648 |
| | 10,630 |
| | 10,630 |
| | 3,333 |
| | 3,297 |
| | 1,630 |
| | 1,630 |
|
| Weighted Average Swap Price ($/barrel) | | $ | 55.34 |
| | $ | 54.96 |
| | $ | 54.77 |
| | $ | 54.77 |
| | $ | 55.89 |
| | $ | 55.89 |
| | $ | 55.50 |
| | $ | 55.50 |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| NYMEX WTI Purchased Puts/Sold Calls | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| Average Volume Per Day (barrels) | |
|
| | 3,297 |
| | 4,891 |
| |
|
| | 1,667 |
| | 1,648 |
| |
|
| |
|
|
| Weighted Average Purchased Put Price ($/barrel) | |
|
| | $ | 55.00 |
| | $ | 55.00 |
| |
|
| | $ | 55.00 |
| | $ | 55.00 |
| |
|
| |
|
|
| Weighted Average Sold Call ($/barrel) | |
|
| | $ | 57.69 |
| | $ | 58.42 |
| |
|
| | $ | 58.00 |
| | $ | 58.00 |
| |
|
| |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| NYMEX WTI Sold Puts | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| Average Volume Per Day (barrels) | |
|
| |
|
| |
|
| |
|
| | 5,000 |
| | 4,945 |
| | 1,630 |
| | 1,630 |
|
| Weighted Average Sold Put Price ($/barrel) | |
|
| |
|
| |
|
| |
|
| | $ | 44.00 |
| | $ | 44.00 |
| | $ | 44.00 |
| | $ | 44.00 |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| MEH Crude Swaps | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| Average Volume Per Day (barrels) | | 2,000 |
| | 2,000 |
| | 2,000 |
| | 2,000 |
| |
|
| |
|
| |
|
| |
|
|
| Weighted Average Swap Price ($/barrel) | | $ | 61.03 |
| | $ | 61.03 |
| | $ | 61.03 |
| | $ | 61.03 |
| |
|
| |
|
| |
|
| |
|
|
Financial Statement Impact of Derivatives
The impact of our derivatives activities on income is included in the “Derivatives” caption on our Consolidated Statements of Operations. The effects of derivative gains and (losses) and cash settlements 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 (gains) losses” and “Cash settlements, net.”
The following table summarizes the effects of our derivative activities for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Derivative gains (losses) recognized in the Consolidated Statements of Operations | $ | (68,131 | ) | | $ | 37,427 |
| | $ | (17,819 | ) |
| Cash settlements recognized in the Consolidated Statements of Cash Flows | $ | (4,136 | ) | | $ | (48,291 | ) | | $ | (3,511 | ) |
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:
|
| | | | | | | | | | | | | | | | | | |
| | | | | Fair Values |
| | | | | December 31, 2019 | | December 31, 2018 |
| | | | | Derivative | | Derivative | | Derivative | | Derivative |
| Type | | Balance Sheet Location | | Assets | | Liabilities | | Assets | | Liabilities |
| Commodity contracts | | Derivative assets/liabilities – current | | $ | 4,131 |
| | $ | 23,450 |
| | $ | 34,932 |
| | $ | 991 |
|
| Commodity contracts | | Derivative assets/liabilities – noncurrent | | 2,750 |
| | 3,385 |
| | 10,100 |
| | — |
|
| | | | | $ | 6,881 |
| | $ | 26,835 |
| | $ | 45,032 |
| | $ | 991 |
|
As of December 31, 2019, we reported net commodity derivative liabilities of $20.0 million. The contracts associated with this position are with 9 counterparties, all of which are investment grade financial institutions and are participants in the Credit Facility. 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.
| 2019 |
Mr. Brian Steck has served on the Board since April 2019. Mr. Steck is a Partner, Senior Analyst at Mangrove Partners, one of our shareholders, where he has worked since 2011. Since 2017, Mr. Steck has also served as a board member7. | Property and Chairman of the Nominating & Corporate Governance Committee of Bonanza Creek Energy, Inc. Through early 2011, Mr. Steck managed The Laurel Capital Group, LLC, the general partner of a hedge fund he founded in 2009. From 2006 until 2008, Mr. Steck was Head of US Equities at Tisbury Capital where he built and managed a team focused on event- and fundamentally-driven investment opportunities. From 2000 until 2005, Mr. Steck was a partner at K Capital where he focused on European and U.S. opportunities that included special situations, merger arbitrage, deep value and shareholder activism. Prior to K Capital, Mr. Steck spent 10 years at UBS and its predecessors Swiss Bank Corporation and O'Connor & Associates, where he focused on equity derivative trading and risk management, built equity derivative and event-driven client businesses and was Global Co-Head of Equity Hedge Fund Coverage. Mr. Steck received a B.S., with highest honors, from the University of Illinois at Urbana Champaign. The Board believes that Mr. Steck’s financial experience, experience as a director and experience as an investor in the energy sector provides significant contributions to our Board. | | Equipment |
The following table summarizes our property and equipment as of the dates presented:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| Oil and gas properties: | |
| | |
|
| Proved | $ | 1,409,219 |
| | $ | 1,037,993 |
|
| Unproved | 53,200 |
| | 63,484 |
|
| Total oil and gas properties | 1,462,419 |
| | 1,101,477 |
|
| Other property and equipment | 25,915 |
| | 20,383 |
|
| Total property and equipment | 1,488,334 |
| | 1,121,860 |
|
| Accumulated depreciation, depletion and amortization | (367,909 | ) | | (193,866 | ) |
| | $ | 1,120,425 |
| | $ | 927,994 |
|
Unproved property costs of $53.2 million and $63.5 million have been excluded from amortization as of December 31, 2019 and December 31, 2018, respectively. An additional $0.3 million of costs, associated with wells in-progress for which we had not previously recognized any proved undeveloped reserves, were excluded from amortization as of December 31, 2018. The total costs not subject to amortization as of December 31, 2019 were incurred in the following periods: $1.3 million in 2019, $6.1 million in 2018, $43.1 million in 2017 and the remaining $2.7 million in 2016. We transferred $16.8 million and $82.8 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, 2019 and 2018, respectively. We capitalized internal costs of $4.1 million, $3.7 million and $2.4 million and interest of $4.1 million, $9.1 million and $2.7 million during the year ended December 31, 2019, 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 $17.25, $16.11 and $12.87 for the years ended December 31, 2019, 2018 and 2017, respectively.
| |
| 8. | 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:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| Balance at beginning of period | $ | 4,314 |
| | $ | 3,286 |
|
| Changes in estimates | (2 | ) | | 354 |
|
| Liabilities incurred | 290 |
| | 335 |
|
| Liabilities settled | (67 | ) | | (8 | ) |
| Acquisitions of properties | 83 |
| | 385 |
|
| Sale of properties | — |
| | (310 | ) |
| Accretion expense | 316 |
| | 272 |
|
| Balance at end of period | $ | 4,934 |
| | $ | 4,314 |
|
The following table summarizes our long-term debt as of the dates presented:
|
| | | | | | | | | | | | | | | |
| | December 31, 2019 | | December 31, 2018 |
| | Principal | | Unamortized Discount and Issuance Costs 1 | | Principal | | Unamortized Discount and Issuance Costs 1 |
Credit facility 2 | $ | 362,400 |
| | | | $ | 321,000 |
| | |
| Second lien term loan | 200,000 |
| | $ | 7,372 |
| | 200,000 |
| | $ | 9,625 |
|
| Totals | 562,400 |
| | 7,372 |
| | 521,000 |
| | 9,625 |
|
| Less: Unamortized discount | (2,415 | ) | | | | (3,159 | ) | | |
| Less: Unamortized deferred issuance costs | (4,957 | ) | | | | (6,466 | ) | | |
| Long-term debt, net | $ | 555,028 |
| | | | $ | 511,375 |
| | |
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.
| |
(1)2
| MemberIssuance costs of the Nominating & Governance Committee.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 12) and are being amortized over the term of the Credit Facility using the straight-line method. |
Credit Facility
The Credit Facility provides for a $1.0 billion revolving commitment and $500 million borrowing base including a $25 million sublimit for the issuance of letters of credit. In December 2019, we completed our fall borrowing base redetermination and our lenders affirmed the $500 million borrowing base. In the years ended December 31, 2019 and December 31, 2018, we paid and capitalized issue costs of $2.6 million and $0.9 million, respectively in connection with amendments to the Credit Facility. 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. We had $0.4 million in letters of credit outstanding as of December 31, 2019 and December 31, 2018.
In May 2019, maturity of the Credit Facility was extended to May 2024 from September 2020; provided that on June 30, 2022, unless we have either extended the maturity date of the Second Lien Facility described below to a date that is at least 91 days after the May 7, 2024 or have repaid our Second Lien Facility in full, the maturity date of the Credit Facility will mean June 30, 2022.
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 0.50% to 1.50%, 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 1.50% to 2.50%, 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, 2019, the actual interest rate on the outstanding borrowings under the Credit Facility was 3.75%. Unused commitment fees are charged at a rate of 0.375% to 0.50%, depending upon utilization.
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. 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.
The Credit Facility requires us to maintain (1) 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 (2) a maximum leverage ratio (consolidated indebtedness to adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses, both as defined in the Credit Facility), measured as of the last day of each fiscal quarter, of 4.00 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), limitations 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 contains customary events of default and remedies for credit facilities of this nature. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility.
As of December 31, 2019, 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 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, 2019, the actual interest rate of outstanding borrowings under the Second Lien Facility was 8.81%. 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): from October 2019 through September 2020, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following prepayment premiums in the event of a change in control that results in an offer of prepayment that is accepted by the lenders under the Second Lien Facility: from October 2019 through September 2020, 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), limitations on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends 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 loan. These costs are subject to amortization using the interest method over the five-year term of the Second Lien Facility.
As of December 31, 2019, 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.
The following table summarizes our provision for income taxes for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Current income taxes (benefit) | | | | | |
|
| Federal | $ | (1,236 | ) | | $ | (2,471 | ) | | $ | — |
|
| | (1,236 | ) | | (2,471 | ) | | — |
|
| Deferred income taxes (benefit) | | | | | |
|
| Federal | 1,236 |
| | 2,471 |
| | (4,943 | ) |
| State | 2,137 |
| | 523 |
| | — |
|
| | 3,373 |
| | 2,994 |
| | (4,943 | ) |
| | $ | 2,137 |
| | $ | 523 |
| | $ | (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:
|
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Computed at federal statutory rate | $ | 15,272 |
| | 21.0 | % | | $ | 47,315 |
| | 21.0 | % | | $ | 9,701 |
| | 35.0 | % |
| State income taxes, net of federal income tax benefit | 1,494 |
| | 2.1 | % | | 1,743 |
| | 0.8 | % | | (1,383 | ) | | (5.0 | )% |
| Change in valuation allowance | (14,240 | ) | | (19.6 | )% | | (48,820 | ) | | (21.7 | )% | | (24,353 | ) | | (87.8 | )% |
| Effect of rate change on the valuation allowance | — |
| | — | % | | — |
| | — | % | | (86,612 | ) | | (312.5 | )% |
| Effect of rate change | — |
| | — | % | | — |
| | — | % | | 86,612 |
| | 312.5 | % |
| Reorganization adjustments | — |
| | — | % | | — |
| | — | % | | 10,760 |
| | 38.8 | % |
| Other, net | (389 | ) | | (0.5 | )% | | 285 |
| | 0.1 | % | | 332 |
| | 1.2 | % |
| | $ | 2,137 |
| | 3.0 | % | | $ | 523 |
| | 0.2 | % | | $ | (4,943 | ) | | (17.8 | )% |
The following table summarizes the principal components of our deferred income tax assets and liabilities as of the dates presented:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| Deferred tax assets: | |
| | |
|
| Net operating loss (“NOL”) carryforwards | $ | 175,221 |
| | $ | 163,437 |
|
| Alternative minimum tax (“AMT”) credit carryforwards | 1,236 |
| | 2,471 |
|
| Asset retirement obligations | 1,073 |
| | 647 |
|
| Pension and postretirement benefits | 340 |
| | 441 |
|
| Share-based compensation | 880 |
| | 546 |
|
| Fair value of derivative instruments | 4,191 |
| | — |
|
| Interest expense limitation | 11,463 |
| | 3,128 |
|
| Other | 2,441 |
| | 2,590 |
|
| | 196,845 |
| | 173,260 |
|
| Less: Valuation allowance | (114,939 | ) | | (128,650 | ) |
| Total net deferred tax assets | 81,906 |
| | 44,610 |
|
| Deferred tax liabilities: | | | |
| Property and equipment | 83,330 |
| | 33,413 |
|
| Fair value of derivative instruments | — |
| | 9,248 |
|
| Total deferred tax liabilities | 83,330 |
| | 42,661 |
|
| Net deferred tax assets (liabilities) | $ | (1,424 | ) | | $ | 1,949 |
|
Continuing Impact of 2017 Tax Reform
In 2017, the U.S. Congress enacted the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (the “TCJA”). The TCJA provided for broad and complex changes to the U.S. tax code (the “Code”). In addition to the reduction in the U.S. federal corporate income tax rate from 35% to 21%, the most significant aspects of the TCJA that continue to have a material impact on us are those attributable to: (i) the repeal of the corporate AMT, (ii) limitations on deductible interest expense and (iii) the utilization and limitations on NOLs. The specific impact of these TCJA-related items are described in further detail below in our discussion of the income tax provision and our deferred tax assets and liabilities.
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.
Income Tax Provision
The provision for the years ended December 31, 2019 and 2018 includes current federal benefits of $1.2 million and $2.5 million attributable to the anticipated refund of AMT credits for the 2019 and 2018 tax years, respectively. The amount for 2019 has been recognized on our Consolidated Balance Sheet as of December 31, 2019 as a current asset. The $2.5 million attributable to 2018 was refunded to us in 2019. These benefits have been offset by corresponding decreases in the deferred tax asset associated with AMT credit carryforwards giving rise to deferred federal expenses for the years ended December 31, 2019 and 2018, respectively. In addition, we have a recognized deferred state tax expenses of $2.1 million and $0.5 million attributable to property and equipment for overall effective tax rates of 3.0% and 0.2% for the years ended December 31, 2019 and 2018, respectively. The remaining AMT credit carryforwards of approximately $1.2 million will be reclassified from deferred tax assets, where they are classified as of December 31, 2019, to income taxes receivable upon the filing of federal returns in future years.
In connection with the TCJA, we recorded an income tax charge of $86.6 million for the year ended December 31, 2017, which consisted 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, our provision for the year ended December 31, 2017 included federal income taxes of $9.7 million applied at the statutory rate of 35% 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.
Deferred Tax Assets and Liabilities
As of December 31, 2019, we had federal NOL carryforwards of approximately $613.4 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 NOLs may be limited in future periods. As of December 31, 2019, we carried a valuation allowance against our federal and state deferred tax assets of $114.9 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 assets 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 is no longer present and additional weight is given to subjective positive evidence, including projections for growth.
The net deferred tax liability recognized on the Consolidated Balance Sheet as of December 31, 2019 is attributable to certain state deferred tax liabilities associated with property and equipment in excess of federal deferred tax assets associated with refundable AMT credit carryforwards for tax years ending after 2019. The net deferred tax asset recognized on the Consolidated Balance Sheet as of December 31, 2018 is attributable to federal deferred tax assets associated with AMT credit carryforwards in excess of certain state deferred tax liabilities attributable to property and equipment. The valuation allowance related to all other net deferred tax assets remains in full as of December 31, 2019 and 2018.
Other Income Tax Matters
We had no liability for unrecognized tax benefits as of December 31, 2019 and 2018. There were no interest and penalty charges recognized during the years ended December 31, 2019, 2018 and 2017. Tax years from 2015 forward remain open for examination by the Internal Revenue Service and various state jurisdictions.
Adoption of ASC Topic 842
Effective January 1, 2019, we adopted ASC Topic 842 and have applied the guidance therein to all of our contracts and agreements explicitly identified as leases as well as other contractual arrangements that we have determined to include or otherwise have the characteristics of a lease as defined in ASC Topic 842. As illustrated in the disclosures below, the adoption of ASC Topic 842 resulted in the recognition of certain assets and liabilities on our Consolidated Balance Sheet and changes in the amounts and timing of lease cost recognition in our Consolidated Statements of Operations as compared to prior GAAP. We have adopted ASC Topic 842 using the optional transition approach with an adjustment to the beginning balance of retained earnings as of January 1, 2019. Accordingly, our 2019 financial statements are not comparable with respect to leases in effect during all periods prior to January 1, 2019. On January 1, 2019, we recognized operating lease right-of-use (“ROU”) assets of $2.5 million and operating lease obligations of $2.8 million on our Consolidated Balance Sheet for operating leases in effect on that date. We recorded an immaterial adjustment to the beginning balance of retained earnings as of January 1, 2019 representing the difference between the operating lease ROU assets and operating lease obligations recognized upon adoption net of amounts already included in our liabilities as of December 31, 2018 that were attributable to straight-line lease expense in excess of amounts paid for certain operating leases. We did not identify any finance leases, as defined in ASC Topic 842, upon the date of initial adoption.
Lease Arrangements and Supplemental Disclosures
We have lease arrangements for office facilities and certain office equipment, certain field equipment including compressors, drilling rigs, land easements and similar arrangements for rights-of-way, and certain gas gathering and gas lift assets. Our short-term leases are primarily comprised of our contractual arrangements with certain vendors for operated drilling rigs and our field compressors. Our primary variable lease includes our field gas gathering and gas lift agreement with a midstream service provider and the lease payments are charged on a volumetric basis at a contractual fixed rate.
The following table summarizes the components of our total lease cost, as determined in accordance with ASC Topic 842, for the twelve months ended December 31, 2019:
|
| | | | |
| Operating lease cost | | $ | 773 |
|
| Short-term lease cost | | 36,202 |
|
| Variable lease cost | | 23,762 |
|
Less: Amounts charged as drilling costs 1 | | (33,354 | ) |
Total lease cost recognized in the Condensed Consolidated Statement of Operations 2 | | $ | 27,383 |
|
___________________
| |
1 | Represents the combined gross amounts paid and (i) capitalized as drilling costs for our working interest share and (ii) billed to joint interest partners for their working interest share for short-term leases of operated drilling rigs. |
| |
(2)2
| Member ofIncludes $12.1 million recognized in Gathering, processing and transportation, $14.5 million recognized in Lease operating and $0.8 million recognized in G&A for the Compensation & Benefits Committeetwelve months ended December 31, 2019. |
Operating lease rental expense, as determined in accordance with prior GAAP was $2.7 million and $1.0 million, for the years ended December 31, 2018 and 2017, related primarily to field equipment, office equipment and office leases. The substantial difference between operating lease rental expense disclosed in accordance with prior GAAP and that provided in the table above for 2019 in accordance with ASC Topic 842 is attributable to the aforementioned field gas gathering and gas lift agreement which has been determined to be a variable lease under ASC Topic 842.
The following table summarizes supplemental cash flow information, as determined in accordance with ASC Topic 842, related to leases for the twelve months ended December 31, 2019:
|
| | | | |
| Cash paid for amounts included in the measurement of lease liabilities: | | |
| Operating cash flows from operating leases | | $ | 659 |
|
| ROU assets obtained in exchange for lease obligations: | | |
Operating leases 1 | | $ | 3,325 |
|
___________________
1 Includes $2.5 million recognized upon adoption of ASC Topic 842 and $0.8 million obtained during the twelve months ended December 31, 2019.
The following table summarizes supplemental balance sheet information related to leases as of December 31, 2019:
|
| | | | |
| ROU assets - operating leases | | $ | 2,740 |
|
| Current operating lease obligations | | $ | 847 |
|
| Noncurrent operating lease obligations | | 2,232 |
|
| Total operating lease obligations | | $ | 3,079 |
|
| Weighted-average remaining lease term | | |
| Operating leases | | 4.1 Years |
|
| Weighted-average discount rate | | |
| Operating leases | | 5.97 | % |
| Maturities of operating lease obligations for the years ending December 31, | | |
| 2020 | | $ | 847 |
|
| 2021 | | 830 |
|
| 2022 | | 834 |
|
| 2023 | | 833 |
|
| 2024 | | 139 |
|
| Total undiscounted lease payments | | 3,483 |
|
| Less: imputed interest | | (404 | ) |
| Total operating lease obligations | | $ | 3,079 |
|
| |
| 12. | (3)Additional Balance Sheet Detail
|
The following table summarizes components of selected balance sheet accounts as of the dates presented:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| Other current assets: | |
| | |
|
| Tubular inventory and well materials | $ | 2,989 |
| | $ | 4,061 |
|
| Prepaid expenses | 1,469 |
| | 1,064 |
|
| | $ | 4,458 |
| | $ | 5,125 |
|
| Other assets: | |
| | |
|
| Deferred issuance costs of the Credit Facility, net of amortization | $ | 3,952 |
| | $ | 2,437 |
|
| Right-of-use assets - operating leases | 2,740 |
| | — |
|
| Other | 32 |
| | 44 |
|
| | $ | 6,724 |
| | $ | 2,481 |
|
| Accounts payable and accrued liabilities: | |
| | |
|
| Trade accounts payable | $ | 30,098 |
| | $ | 16,507 |
|
| Drilling costs | 18,832 |
| | 22,434 |
|
| Royalties | 44,537 |
| | 51,212 |
|
| Production, ad valorem and other taxes | 3,244 |
| | 2,418 |
|
| Compensation and benefits | 5,272 |
| | 4,489 |
|
| Interest | 730 |
| | 670 |
|
| Current operating lease obligations | 847 |
| | — |
|
| Other | 2,264 |
| | 5,970 |
|
| | $ | 105,824 |
| | $ | 103,700 |
|
| Other liabilities: | |
| | |
|
| Asset retirement obligations | $ | 4,934 |
| | $ | 4,314 |
|
| Noncurrent operating lease obligations | 2,232 |
| | — |
|
| Defined benefit pension obligations | 873 |
| | 857 |
|
| Postretirement health care benefit obligations | 343 |
| | 362 |
|
| | $ | 8,382 |
| | $ | 5,533 |
|
Member | |
| 13. | 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).
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:
|
| | | | | | | | | | | | | | | | |
| | | As of December 31, 2019 |
| | | Fair Value | | Fair Value Measurement Classification |
| Description | | Measurement | | Level 1 | | Level 2 | | Level 3 |
| Assets: | | |
| | |
| | |
| | |
|
| Commodity derivative assets – current | | $ | 4,131 |
| | $ | — |
| | $ | 4,131 |
| | $ | — |
|
| Commodity derivative assets – noncurrent | | 2,750 |
| | — |
| | 2,750 |
| | — |
|
| Liabilities: | | |
| | |
| | |
| | |
|
| Commodity derivative liabilities – current | | $ | (23,450 | ) | | $ | — |
| | $ | (23,450 | ) | | $ | — |
|
| Commodity derivative liabilities – noncurrent | | (3,385 | ) | | — |
| | (3,385 | ) | | — |
|
|
| | | | | | | | | | | | | | | | |
| | | As of December 31, 2018 |
| | | Fair Value | | Fair Value Measurement Classification |
| Description | | Measurement | | Level 1 | | Level 2 | | Level 3 |
| Assets: | | |
| | |
| | |
| | |
|
| Commodity derivative assets – current | | $ | 34,932 |
| | $ | — |
| | $ | 34,932 |
| | $ | — |
|
| Commodity derivative assets – noncurrent | | 10,100 |
| | — |
| | 10,100 |
| | — |
|
| Liabilities: | | |
| | |
| | |
| | |
|
| Commodity derivative liabilities – current | | $ | (991 | ) | | $ | — |
| | $ | (991 | ) | | $ | — |
|
| Commodity derivative liabilities – noncurrent | | — |
| | — |
| | — |
| | — |
|
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, 2019, 2018 and 2017.
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, LLS and MEH crude oil closing prices as of the Audit Committeeend 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. |
Executive OfficersNon-Recurring Fair Value Measurements
In addition to the fair value measurements applied with respect to the Hunt and Devon Acquisitions, as described in Note 4, the most significant non-recurring fair value measurements utilized in the preparation of our Consolidated Financial Statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties. 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.
| |
| 14. | Commitments and Contingencies |
The following table sets forth our significant commitments as of December 31, 2019, by category, for the next 5 years and thereafter:
|
| | | | | | | | |
| Year | | Gathering and Intermediate Transportation | | Other Commitments |
| 2020 | | $ | 12,962 |
| | $ | 289 |
|
| 2021 | | 12,962 |
| | 140 |
|
| 2022 | | 12,962 |
| | 70 |
|
| 2023 | | 12,962 |
| | — |
|
| 2024 | | 12,962 |
| | — |
|
| Thereafter | | 37,789 |
| | — |
|
| Total | | $ | 102,599 |
| | $ | 499 |
|
Drilling and Completion Commitments
As of December 31, 2019, we had contractual commitments on a pad-to-pad basis for 2 drilling rigs. Additionally, we have a one-year agreement, effective January 1, 2020, which can be terminated with 30 days' notice by either party, to utilize certain information regarding eachfrac services and related materials, with 0 minimum commitment.
Gathering and Intermediate Transportation Commitments
We have long-term agreements with Nuevo Dos Gathering and Transportation, LLC (“Nuevo G&T”) and Nuevo Dos Marketing, LLC (“Nuevo Marketing” and together with Nuevo G&T, collectively “Nuevo”), successor to Republic Midstream, LLC and affiliates, to provide gathering and intermediate pipeline transportation services for a substantial portion of our executive officers:crude oil and condensate production in South Texas as well as volume capacity support for certain downstream interstate pipeline transportation.
Nuevo is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party through 2041. We have a minimum volume commitment of 8,000 gross barrels of oil per day to Nuevo through 2031 under the gathering agreement. |
| | |
Age, Position with the Company and Business Experience | | Officer of the Company Since |
John A. Brooks (see above)
| | 2011 |
Steven A. Hartman, age 52
| | 2010 |
Mr. Hartman has served as our Senior Vice President, Chief Financial Officer and Treasurer since December 2010. He served as our Vice President and Treasurer from July 2006 to December 2010, as our Assistant Treasurer and Treasury Manager from September 2004 to July 2006 and as our Manager, Corporate Development from August 2003 to September 2004. Mr. Hartman also served as Vice President and Treasurer of PVG GP, LLC, the general partner of Penn Virginia GP Holdings, L.P., from September 2006 to June 2010 and of Penn Virginia Resource GP, LLC, the general partner of Penn Virginia Resource Partners, L.P., from July 2006 to June 2010. Prior to joining the Company, Mr. Hartman was employed by El Paso Corporation and its publicly traded spin-off, GulfTerra Energy Partners, L.P., in a variety of financial and corporate-development related positions. | | |
Under a marketing agreement, we have a commitment to sell 8,000 barrels per day of crude oil (gross) to Nuevo, or to any third party, utilizing Nuevo Marketing's capacity in a downstream interstate pipeline through 2026.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.
|
| | |
Benjamin A. Mathis, age 48 | | 2017 |
Mr. Mathis has served as our Senior Vice President, Operations and Engineering since July 2018. Prior to such time, he served as our Vice President, Operations since September 2017. Mr. Mathis has more than 25 years of energy industry experience, all of which has been in operations with a primary focus on the drilling and completion functions. Mr. Mathis served as Drilling and Completions Manager - US Onshore for Statoil from October 2015 to September 2017, where he was responsible for Statoil’s drilling, completions and workover operations for the Eagle Ford, Bakken and Marcellus/Utica areas. Prior to that role, Mr. Mathis served as Statoil’s Operations Manager - Eagle Ford from November 2014 to October 2015, Drilling and Completions Manager - Eagle Ford from October 2012 to November 2014 and Drilling Engineer Manager - Onshore from August 2011 to September 2012. Prior to his tenure at Statoil, Mr. Mathis also held positions of increasing responsibility at Occidental Petroleum Corporation and Unocal, both domestically and internationally. Mr. Mathis received a B.S. in Petroleum Engineering from Texas A&M University in 1992. | | |
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, 2019, we had a reserve in the amount of $0.3 million included in Accounts payable and accrued liabilities for the estimated settlement of disputes with a joint venture partner regarding certain transactions that occurred in prior years.
Environmental Compliance
RoleExtensive 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 Board
Our business is managed under the direction of the Board. The Board has adopted Corporate Governance Principles describing its duties. A copy of our Corporate Governance Principles is available at the “Corporate Governance” section of our website, http://www.pennvirginia.com. The Board meets regularly to review significant developments affecting the Company and to act on matters requiring Board approval.
Communications with the Board
Shareholders and other interested parties may communicate with our Board, including any concerns they have, by contacting the Board in writing at c/o Corporate Secretary, Penn Virginia Corporation, 16285 Park Ten Place, Suite 500, Houston, Texas 77084. The Corporate Secretary of the Company reviews communications to the Board and forwards the communications to the Board as appropriate. All such communications should identify the author as a shareholder and clearly state whether the intended recipients are all members of the Board or just certain specified individual directors. Our Corporate Secretary will make copies of all such communications and circulate them to the appropriate director or directors. Communications involving substantive accounting or auditing matters will be immediately forwarded to the Chairperson of the Audit Committee. Communications that pertain to non-financial matters will be forwarded promptly to the appropriate committee. Certain items that are unrelated to the duties and responsibilities of the Board will not be forwarded such as: business solicitation or advertisements; product related inquiries; junk mail or mass mailings; resumes or other job related inquiries; spam and overly hostile, threatening, potentially illegal or similarly unsuitable communications.
Code of Business Conduct and Ethics
The Board has adopted a Code of Business Conduct and Ethics as its “code of ethics” as defined in Item 406 of Regulation S-K, which applies to all of our directors, officers, employees and consultants, including our Chief Executive Officer, or our “CEO,” Chief Financial Officer, or our “CFO,” principal accounting officer or controller or persons performing similar functions. A copy of our Code of Business Conduct and Ethics is available at the “Corporate Governance” section of our website, http://www.pennvirginia.com. We intend to satisfy the disclosure requirements for any future amendments to, or waivers of, our Code of Business Conduct and Ethics by posting such information on our website.
Committees of the Board
The Board has a Nominating and Governance Committee, a Compensation and Benefits Committee and an Audit Committee. Each of the Board’s committees acts under a written charter, which was adopted and approved by the Board. Copies of the committees’ charters are available at the “Corporate Governance” section of our website, http://www.pennvirginia.com.
Nominating and Governance Committee. Messrs. Pottow, Holderness and Schuyler are the members of the Nominating and Governance Committee, or the “N&G Committee,” and each is an “Independent Director” as defined by Nasdaq listing standards. Mr. Pottow is the chairman of the N&G Committee. The N&G Committee (i) seeks, identifies and evaluates individuals who are qualified to become members of the Board, (ii) recommends to the Board candidates to fill vacancies on the Board, as such vacancies occur and (iii) recommends to the Board the slate of nominees for election as directors by our shareholders at each Annual Meeting of Shareholders. The N&G Committee will consider nominees recommended by shareholders. Shareholder recommendations for director nominees will receive the same consideration by the N&G Committee that other nominations receive. The N&G Committee recommends individuals as director nominees based on professional, business and industry experience, ability to contribute to some aspect of our business and willingness to commit the time and effort required of a director. The N&G Committee may also consider whether and how a director candidate’s views, experience, skill, education or other attributes may contribute to the Board’s diversity. While the N&G
Committee does not require that each individual director candidate contribute to the Board’s diversity, the N&G Committee in general strives to ensure that the Board, as a group, is comprised of individuals with diverse backgrounds and experience conducive to understanding and being able to contribute to all financial, operational, strategic and other aspects of our business. Furthermore, the N&G Committee seeks to include highly qualified women and individuals from minority groups in the pool from which Board nominees are selected. Director nominees must possess good judgment, strength of character, a reputation for integrity and personal and professional ethics and an ability to think independently while contributing to a group process. The N&G Committee also recommends to the Board the individual(s) to serve as Chairman of the Board. Additionally, the N&G Committee assists the Board in implementing our Corporate Governance Principles, confirms that the Compensation and Benefits Committee evaluates senior management, oversees Board self-evaluation through an annual review of Board and committee performance and assists the Independent Directors in establishing succession policies in the event of an emergency or retirement of our CEO. The N&G Committee may obtain advice and assistance from outside director search firms as it deems necessary to carry out its duties.
Compensation and Benefits Committee. Messrs. Holderness, Schuyler and Hanna are the members of the C&B Committee, and each is an Independent Director under applicable Nasdaq listing standards and SECenvironment. 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 compensation committee independence. Mr. Schuyler is the chairman of the C&B Committee. The C&B Committee is responsible for determining the compensation of our executive officers. The C&B Committee also periodically reviews and makes recommendations or decisions regarding our incentive compensation and equity-based plans, provides oversight with respectfailure to our other employee benefit plans and reports its decisions and recommendations with respect to such plans to the Board. The C&B Committee also reviews and makes recommendations to the Board regarding our director compensation policy. The C&B Committee may obtain advice and assistance from outside compensation consultants and other advisors as it deems necessary to carry out its duties.
Audit Committee. Messrs. Holderness, Pottow and Schuyler are the members of the Audit Committee, and each is an Independent Director under applicable Nasdaq listing standards and SECcomply. Some laws, rules and regulations for audit committee independence. Mr. Holderness is the chairmanrelating to protection of the Audit Committeeenvironment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and an “audit committee financial expert”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 definedplugging of abandoned wells. As of December 31, 2019, we have recorded AROs of $4.9 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 Item 407(d)(5) of Regulation S-K. The Audit Committee is responsible for the appointment, compensation, evaluation and termination of our independent registered public accounting firm, and oversees the work, internal quality-control procedures and independence of our independent registered public accounting firm. The Audit Committee discusses with management and our independent registered public accounting firm our annual audited and quarterly unaudited financial statements and recommends to the Boardgeneral. We believe that our annual audited financial statements be includedwe are in our Annual Report on Form 10-K. The Audit Committee also discusses with management earnings press releases, earnings presentations and any financial guidance provided to analysts. The Audit Committee appoints, replaces, dismisses and, after consulting with management, approves the compensation of our outside internal audit firm. The Audit Committee also provides oversight with respect to business risk matters, reserves,substantial compliance with ethics policiescurrent applicable environmental laws, rules and regulations and that continued compliance with legal and regulatory requirements. The Audit Committee has established procedures forexisting requirements will not have a material impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or the receipt, retention and treatmentadoption of complaints regarding accounting, internal accounting controls, auditing and other matters andnew environmental laws, including any significant limitation on the confidential anonymous submission by employeesuse of concerns regarding questionable accounting, auditing and other matters. The Audit Committee may obtain advice and assistance from outside legal, accounting or other advisors as it deems necessaryhydraulic fracturing, have the potential to carry out its duties.adversely affect our operations.
Compensation of Directors
The following table sets forth the aggregate compensation paid to our non-employee directors during 2018:
|
| | | | | | | | | |
| 2018 Director Compensation |
| Name | | Fees Earned or Paid in Cash ($) | | Stock Awards ($)(1) | | Total ($) |
David Geenberg(2) | | — |
| | — |
| | — |
|
Michael Hanna(2) | | — |
| | — |
| | — |
|
| Darin G. Holderness | | 172,208 |
| | — |
| | 172,208 |
|
Marc McCarthy(3) | | 13,062 |
| | — |
| | 13,062 |
|
| V. Frank Pottow | | 21,346 |
| | 156,000 |
| | 177,346 |
|
| Jerry Schuyler | | 85,250 |
| | — |
| | 85,250 |
|
| |
(1)15. | No equity awards were granted to our non-employee directors during 2018 except for 1,898 restricted stock units granted to Mr. Pottow in connection with his appointment to the Board in September 2018. As of December 31, 2018, Messrs. Holderness and Schuyler each had 2,781 restricted stock units outstanding and Mr. Pottow had 949 restricted stock units outstanding.Shareholders’ Equity |
Preferred Stock
As of December 31, 2019 and December 31, 2018, there were 5,000,000 shares of preferred stock authorized with NaN issued or outstanding.
Common Stock
As of December 31, 2019 and December 31, 2018, there were 15,135,598 and 15,080,594 shares of Common Stock outstanding, respectively, with a par value of $0.01 per share. We have a total of 45,000,000 shares authorized. We have not paid any cash dividends on our common stock. In addition, our Credit Facility and Second Lien Facility have restrictive covenants that limit our ability to pay dividends.
Paid-in Capital
Represents the value of consideration we received in excess of par value for the original issuance of our common stock net of costs directly attributable to the issuance transactions. In addition, paid-in capital includes amounts attributable to the amortized cost of share-based awards that have been granted to our employees and directors, net of any adjustments with the ultimate vesting of such awards.
Accumulated Other Comprehensive Income (Loss)
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.
| |
(2)16. | Messrs. GeenbergShare-Based Compensation and Hanna, who were appointed to our Board in January 2018, agreed to waive all compensation, including equity compensation, in exchange for their service on the Board and committees of the Board.Other Benefit Plans |
Accordingly,We reserved 1,424,600 shares of Common Stock for issuance under the Penn Virginia Corporation Management Incentive Plan for future share-based compensation awards. A total of 360,615 time-vested restricted stock units (“RSUs”) and 113,592 performance restricted stock units (“PRSUs”) have been granted as of December 31, 2019.
We recognized $4.1 million, $4.6 million and $3.8 million of share-based compensation expense for the years ended December 31, 2019, 2018 and 2017, respectively. All of our share-based compensation awards are classified as equity instruments because they receivedresult 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.
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:
|
| | | | | | |
| | Restricted Stock Units | | Weighted-Average Grant Date Fair Value |
| Balance at beginning of year | 208,040 |
| | $ | 47.35 |
|
| Granted | 13,175 |
| | $ | 30.35 |
|
| Vested | (74,888 | ) | | $ | 39.40 |
|
| Forfeited | (9,451 | ) | | $ | 51.71 |
|
| Balance at end of year | 136,876 |
| | $ | 49.76 |
|
As of December 31, 2019, we had $5.0 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.1 years. The total grant-date fair values of RSUs that vested in 2019, 2018 and 2017 was $3.0 million, $3.3 million and $0.8 million, respectively.
Performance Restricted Stock Units
In the years ended December 31, 2019 and December 31, 2017, we granted 15,066 and 98,526 PRSUs, respectively to members of our management. There were no compensationPRSUs granted for the year ended December 31, 2018. The PRSUs were issued collectively in one to three separate tranches with individual three-year performance periods beginning in January 2017, 2018, 2019 and 2020, respectively. Vesting of the PRSUs can range from 0 to 200% of the original grant based on the performance of our common stock relative to an industry index or for those granted in 2019, a peer group of companies. Due to their servicesmarket 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 for the 2017 grants and $34.02 for the 2019 grant.
The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2018.2019 and 2017 are presented as follows:
|
| | | | |
| | 2019 | | 2017 |
| Expected volatility | 49.9 | % | | 59.63% to 62.18% |
| Dividend yield | 0.0% |
| | 0.0% |
| Risk-free interest rate | 1.66 | % | | 1.44% to 1.51% |
The following table summarizes activity for our most recent fiscal year with respect to PRSUs:
|
| | | | | | |
| | Performance Restricted Stock Units | | Weighted-Average Grant Date Fair Value |
| Balance at beginning of year | 89,071 |
| | $ | 58.69 |
|
| Granted | 15,066 |
| | $ | 34.02 |
|
| Vested | (3,917 | ) | | $ | 63.25 |
|
| Forfeited | (1,083 | ) | | $ | 63.25 |
|
| Expired | (19,223 | ) | | $ | 62.92 |
|
| Balance at end of year | 79,914 |
| | $ | 52.73 |
|
Executive Transition and Retirement
Effective December 2, 2019, Mr. Geenberg resignedSteven A. Hartman separated from the Board in April 2019.
| |
(3) | Mr. McCarthy is a Senior Managing Director at Wexford Capital LP (“Wexford”). WeCompany. In accordance with his separation and transition agreement (“Hartman Separation Agreement”), we recorded a charge of $0.5 million for severance and other cash benefits that were paid the compensation owed to Mr. McCarthy for his services as a director directly to Wexford Capital LP. Mr. McCarthy resigned from the Board in March 2018. |
In 2018, after considering director compensation paid by companies included in our Peer Group, as described under “Executive Compensation-Compensation Discussion and Analysis-How Compensation Is Determined-Peer Group” below, our C&B Committee recommended and our Board of Directors approved a $10,000 increase in our annual cash retainer for each non-employee director and a $3,500 increase in the annual retainer for the Chairmanfirst quarter of the Audit Committee. Accordingly, our director compensation package2020. The Hartman Separation Agreement also provided for the followingaccelerated vesting of certain share-based compensation awards for 2018:
an annual cash retainerwhich we recognized accelerated expense of $70,000 to each non-employee director, payable quarterly in arrears and pro-rated for any periods of partial service;
annual cash retainers of $18,500, $15,000 and $10,000 for$0.2 million during the Chairman of the Audit, C&B and N&G Committees, respectively, payable quarterly in arrears and pro-rated for any periods of partial service; and
an additional annual cash retainer of $100,000 for the Chairman of the Board, payable quarterly in arrears and pro-rated for any periods of partial service.
Messrs. Hanna and Steck, who joined the Board in January 2018 and April 2019, respectively, agreed to waive all compensation in exchange for their service on the Board and committees of the Board.
In addition, inyear ended December 2016, following our emergence from bankruptcy, we made a one-time grant of $360,000 (or $120,000 annually) in restricted stock units to each non-employee director serving on the Board at such time in lieu of annual grants over a three year period. Such awards vest in 1/3 increments on the first, second and third anniversaries of the grant date. Mr. Pottow received a grant of 1,898 shares, valued at $156,000 on appointment to the Board that vests in equal installments on December 19, 2018 and December 19, 2019, which ties to the remaining vesting dates for the post-emergence director grants. Accordingly, 2,781 restricted stock units vested for Messrs. Holderness and Schuyler and 949 restricted stock units vested for Mr. Pottow on December 19, 2018.
Non-Employee Director Stock Ownership Guidelines
We maintain stock ownership guidelines which require our non-employee directors to own shares of our Common Stock or restricted stock units having a value equal to three times the annual cash retainer payable by us for serving on the Board (excluding any chair premium). Our non-employee directors are not required to meet these ownership thresholds until the date that is five years from the later of (i) adoption of the guidelines or (ii) the commencement of such director’s service on the Board.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our officers, directors and beneficial owners of more than 10% of our Common Stock to file, by a specified date, reports of beneficial ownership and changes in beneficial ownership with the SEC and to furnish copies of such reports to us. We believe that all such filings were made on a timely basis in 2018.
Item 11 EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
For 2018 our named executive officers, or “NEOs,” consist of the following persons:
Harry Quarls, our former Executive Chairman who retired effective February 28, 2018;
John A. Brooks, our President and Chief Executive Officer;
Steven A. Hartman, our Senior Vice President, Chief Financial Officer and Treasurer; and
Benjamin A. Mathis, our Senior Vice President, Operations and Engineering.
Set forth below is a discussion and analysis of our compensation policies and practices regarding our NEOs.
Mr. Quarls’ Retirement
31, 2019. Effective February 28, 2018, Mr. Harry Quarls resignedretired from his position as a director and Executive Chairman of the Company. In connection with Mr. Quarls’ resignation, he and the Companyhis retirement, we entered into a separation and consulting agreement dated January 18, 2018 (the “Separation(“Quarls Separation Agreement”). Pursuant to the Separation Agreement, whereby Mr. Quarls agreed to provide transition and support services to the Company as reasonably requested by the Boardus through
December 31, 2018. The CompanyWe paid Mr. Quarls a consulting fee of $250,000 for consulting services.$0.3 million under the Quarls Separation Agreement. The Quarls Separation Agreement includesincluded a general release of claims and provided for the vesting of certain equity awards that he held as of his separation. For more information, see “—Employment Contracts-Separation and Consulting Agreement.”
Chapter 11 Proceedings; Cancellation of Equity; Post-Emergence Equity Awards
We emerged from bankruptcy on September 12, 2016. Most of our compensation plans, programs and agreements were terminated or expunged as part of the Company’s restructuring process under the bankruptcy proceedings. In addition, all Common Stock and awards of the Company that were outstanding prior to the emergence date, were cancelled on emergence from bankruptcy. To the extent any of our NEOs held stock of the Company as of that date, it was cancelled, and no consideration was provided for this lost value. Following our emergence from bankruptcy, in January 2017, our NEOs and other key employees were granted long-term, multi-year equity incentives that were intended to replace annual equity grants for a three-year period under our Penn Virginia 2016 Management Incentive Plan, or the “Incentive Plan.” These equity awards included a grant of both time-vested and performance-based restricted stock units intended to immediately align executive and shareholder interests. In addition, our C&B Committee adopted new Annual Incentive Award Guidelines for the payment of annual cash bonuses. These compensation programs are discussed in further detail below.
Objectives of Our Compensation Program
Our compensation program is based on the following objectives:
Accountability—Executives should be held accountable for our annual performance and the achievement of our longer-term strategic goals as well as their own individual performance over both the short and long-term. We satisfy this objective by tying compensation to the achievement of financial, strategic and operational goals based on both short and long-term corporate performance measures. See “2018 Annual Incentive Cash Bonuses” and “Long-Term Equity Compensation” below.
Drive Desired Behaviors—Our compensation program, particularly regarding incentive compensation, should be designed to drive desired behaviors consistent with our values and to achieve stated goals. We satisfy this objective by setting performance metrics for us and our executives that we believe will drive these behaviors and help us achieve our goals.
Align Interests of Executives and Shareholders—Executive compensation should align the interests of our executives with those of our shareholders. We maintain executive stock ownership guidelines which require executives to hold a meaningful amount of stock. Additionally, our compensation program aligns pay to performance by making a substantial portion of total executive compensation variable, or “at-risk,” through an annual bonus program based on our performance goals and the granting of long-term incentive equity awards, which include time-vested restricted stock units and performance-based restricted stock units. As performance goals are met, not met or exceeded, executives are rewarded commensurately.
Flexible Enough to Respond to Changing Circumstances—We are in a cyclical and volatile business, so we should have a flexible compensation program that is responsive to different circumstances at various points in time. To meet this objective, the C&B Committee retains discretion to award higher or lower compensation than performance metrics would indicate if circumstances so warrant.
Industry Competitive—Total executive compensation should be industry-competitive so that we can attract, retain and motivate talented executives with the experience and skills necessary for our success. We satisfy this objective by staying apprised, through our own research and with the assistance of the C&B Committee’s independent compensation consultant, of the amounts and types of executive compensation that our peers pay as well as general industry trends.
Internally Consistent and Equitable—Executive compensation should be internally consistent and equitable. We satisfy this objective by considering not only peer benchmarks, but also our NEOs’ capabilities, levels of experience, tenures, positions, responsibilities and contributions when setting their compensation. Additionally, senior executives should have more of their incentive compensation at risk and tied to corporate performance because they are typically in a position to have a larger impact on our overall performance. Our post-emergence, multi-year equity awards granted to the NEOs in 2017 were comprised of 50% time-vested restricted stock units and 50% performance-based restricted stock units, each payable in stock, and our other employees received either 100% time-vested restricted stock unit awards, or no long-term compensation, depending on their positions. For 2018, we did not make any grants of long-term equity, except to newly hired key employees or in connection with a promotion.
How Compensation Is Determined
Committee Process. The C&B Committee annually reviews and discusses with our CEO his evaluation of the performance of each of our other officers, including Messrs. Hartman and Mathis, and gives considerable weight to our CEO’s evaluations when assessing our other officers’ performance and determining their compensation. The C&B Committee bases its independent evaluation of our CEO, and our CEO bases his evaluation of each of our other officers, primarily on whether we met or exceeded certain quantitative corporate performance metrics and the officer’s individual performance for such year. Those achievement levels are considered in the context of any other factors the C&B Committee deems appropriate including retention needs, internal pay equity and market competitiveness.
Independent Compensation Consultant. In 2018, the C&B Committee engaged Longnecker & Associates, or L&A, as its independent compensation consultant to assist in a general review of the compensation packages for our NEOs. The C&B Committee has assessed the independence of L&A and has reviewed its relationship with L&A and considered all relevant factors, including those set forth in Rule 10C-1(b)(4)(i) through (vi) under the Exchange Act. Based on this review, the C&B Committee concluded that L&A is independent and there are no conflicts of interest raised by the work performed by L&A . L&A provided the C&B Committee with competitive industry and general market-related analyses and trends for executive base salary, short-term incentives and long-term incentives. Specifically, L&A’s approach was to gather compensation data from (a) public peer companies and (b) published salary surveys and to conduct a market comparison analysis of the gathered data.
Peer Group. Set forth below is a list of the companies comprising our peer group for purposes of 2018 compensation, which is referred to in this report as our Peer Group. The Peer Group companies were selected based on revenues, assets, market cap and enterprise value, among other things. The Company was at the 52.7 percentile among this new Peer Group in terms of revenue, at the 35.2 percentile in terms of assets, at the 66.6 percentile in terms of market cap and at the 62.6 percentile in terms of enterprise value. Compensation data for the Peer Group was presented to the C&B Committee and used by the C&B Committee to help direct its compensation decisions for NEOs in early 2018.
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| |
Wildhorse Resource Development Corporation
Midstates Petroleum Company, Inc.
Jagged Peak Energy Inc.
SilverBow Resources, Inc.
Abraxas Petroleum Corporation
Earthstone Energy, Inc.
| Gastar Exploration Inc.
PrimeEnergy Corporation
Callon Petroleum Company
Resolute Energy Corporation
Approach Resources, Inc.
Lonestar Resources US Inc.
|
Elements of Our Compensation Program |
| | |
Element | Characteristics
| Primary Objective
|
Base Salary | Cash | Attract and retain highly talented individuals |
Short-Term Incentives | Cash bonus | Reward individual and corporate performance |
Long-Term Incentives | Time and service-based equity awards | Align the interests of our employees and shareholders by providing employees with incentives to perform in a manner that promotes share price appreciation and achieves corporate objectives |
Other Benefits | Participation in broad based 401(k) and employee health benefit plans | Provide competitive benefits that promote employee health and support employees in attaining financial security |
Base Salaries
Base salary is the principal fixed component of our compensation program, and has historically been reviewed in the first quarter of each year. It is intended to provide our NEOs with a regular source of income to compensate them for their day-to-day efforts in managing the Company. Base salary is primarily used to attract and retain highly talented individuals. Base salary levels vary depending on the NEO’s experience, responsibilities, education, professional standing in the industry, changes in the competitive marketplace and the importance of the position to the Company. The annual base salaries payable to our NEOs as of the end of 2018 and 2017 were as follows:
|
| | | | | | |
| | | Salary ($) |
| Name and Principal Position | | 2018 | | 2017 |
| | | | | |
| Harry Quarls | | — |
| | 250,000 |
|
| Former Executive Chairman | | | | |
| | | | | |
| John A. Brooks | | 437,750 |
| | 425,000 |
|
| President and Chief Executive Officer | | | | |
| | | | | |
| Steven A. Hartman | | 283,250 |
| | 275,000 |
|
| Senior Vice President, Chief Financial Officer and Treasurer | | | | |
| | | | | |
| Benjamin A. Mathis | | 330,000 |
| | 300,000 |
|
| Senior Vice President, Operations and Engineering | | | | |
Harry Quarls. Mr. Quarls retired effective February 2018 and his base salary remained unchanged from the level initially established upon his appointment to the Executive Chairman position in August 2017.
John A. Brooks. Mr. Brooks’ annual base salary was increased to $425,000 in connection with his promotion to President and Chief Executive Officer in August 2017 and was subsequently increased by 3% to $437,750 at the beginning of 2018 as a cost-of living adjustment. In early 2018, L&A provided an analysis of compensation for similar positions utilizing Peer Group data as well as published survey data as discussed above under “How Compensation is Determined-Peer Group.” The C&B Committee targeted the 25th percentile of base salary levels from such data due to Mr. Brooks’ relative inexperience in such role.
Steven A. Hartman. In 2018, Mr. Hartman’s annual base salary was increased by 3% from $275,000 to $283,250 as a cost-of living adjustment. In early 2018, L&A provided an analysis of compensation for similar positions utilizing Peer Group data as well as published survey data as discussed above under “How Compensation is Determined-Peer Group.” The C&B Committee targeted the 25th percentile of base salary levels from such data in part due to the fact that Mr. Hartman had been granted a significant number of shares of restricted stock units in the Company upon the Company’s emergence from bankruptcy.
Benjamin A. Mathis. Mr. Mathis was appointed as the Company’s Vice President, Operations in September 2017, with an initial annual base salary of $300,000. In August 2018, Mr. Mathis was promoted to Senior Vice President, Operations &
Engineering. In connection with such promotion, Mr. Mathis’ annual base salary was increased to $330,000 to compensate him for his additional responsibilities.
2018 Annual Incentive Cash Bonuses
The opportunity to earn an annual cash bonus creates a strong financial incentive for our NEOs to achieve or exceed a combination of near-term corporate and individual goals, which typically are set by the C&B Committee during the first quarter of each year.
Company-Wide Cash Bonus Pool
Our NEOs’ annual incentive cash bonuses are paid out of a cash bonus pool the size of which is determined based on our level of achievement, as compared to our annual budget, of several quantitative Company financial and operational performance metrics, which the C&B Committee typically sets early in the year. The cash bonus pool metrics applicable to 2018 are described below under “—NEO Cash Bonus Criteria-Size of the Cash Bonus Pool.”
The size of the cash bonus pool is generally computed such that, if we meet our target goal exactly with respect to every performance metric, the pool will fund at 100% and will be in an amount sufficient to pay all of our participating employees, including our NEOs, their target annual incentive cash bonuses, which we refer to as the Target Amount. Under the Annual Incentive Award Guidelines established by our C&B Committee to govern our annual incentive cash bonus program, in any given year, the C&B Committee may increase or decrease the cash bonus pool if circumstances warrant. Subject to the C&B Committee’s discretion to increase the cash bonus pool, the aggregate annual incentive cash bonuses paid to all of our employees, including our NEOs, cannot exceed the amount of the cash bonus pool. The flexibility the C&B Committee retains with respect to the size of the cash bonus pool and the cash bonus pool performance metrics is consistent with our belief that our cyclical and volatile business requires that we have a flexible compensation program responsive to different circumstances and different requirements at various points in time.
Size of the Cash Bonus Pool. Our 2018 cash bonus pool was funded at 94% of the Target Amount based on the level of our achievement of the 2018 cash bonus pool performance metrics, which were set by the C&B Committee in February 2018 and are shown in the chart below. The C&B Committee chose these particular metrics because the C&B Committee believed that these metrics would drive our near-term success and, therefore, our stock price over the long-term. L&A advised the C&B Committee that these metrics are commonly used by our Peer Group, and by the oil and gas industry generally, to measure success.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Performance Metric | | Weighting Factor | | Threshold Performance 35% | | Target Performance 100% (1) | | Maximum 200% | | Actual Performance | | Payout | | Payout Level Percent (2) |
| Production (MBOE) | | 20 | % | | (20 | )% | | 8,404 |
| | 20 | % | | 7,944 |
| | 82.2 | % | | 16.4 | % |
Drilling Capital Efficiency per BOE (3) | | 20 | % | | 20 | % | | $ | 14.34 |
| | (20 | )% | | $ | 17.90 |
| | — |
| | — |
|
Adjusted EBITDAX per BOE (4) | | 20 | % | | (20 | )% | | $ | 33.61 |
| | 20 | % | | $ | 37.70 |
| | 160.8 | % | | 32.2 | % |
LOE per BOE (5) | | 5 | % | | 20 | % | | $ | 4.97 |
| | (20 | )% | | $ | 4.52 |
| | 145.3 | % | | 7.3 | % |
Cash G&A ($MM) (6) | | 5 | % | | 20 | % | | $ | 19.70 |
| | (20 | )% | | $ | 17.20 |
| | 164.0 | % | | 8.2 | % |
| Discretionary | | 30 | % | | | | | | | | | | 100 | % | | 30 | % |
| Total Payout Level | | | | | | | | | | | | | | 94 | % |
__________
| |
(1) | Reflects the Company’s budget as approved by the Board in February 2018. With respect to the Drilling Capital Efficiency per BOE metric, target performance reflects actual authorizations for expenditures. |
| |
(2) | Represents the bonus pool payout percentage based on the percent of target achieved. |
| |
(3) | Drilling Capital Efficiency is defined as (A) the total well cost, net to the Company’s working interest, with respect to wells turned in-line during the twelve-month period ending on the last day of the applicable year, divided by (B) the Company’s technical estimated ultimate recovery, net to the Company’s working interests (as |
determined by Degolyer & McNaughton or another independent reserve engineering firm) as of the last day of the applicable plan year with respect to such wells, net of royalties.
| |
(4) | Adjusted EBITDAX is as defined in the Company’s Credit Agreement dated September 12, 2016; provided however, that for purposes of determining the Consolidated Net Income of the Company under such definition, non-recurring general and administrative expenses and share-based compensation expenses are excluded. |
| |
(5) | LOE means the Company’s lease operating expense, as set forth in the financial statements for the applicable plan year. |
| |
(6) | Cash G&A means the Company’s recurring general and administrative expenses less equity classified share-based compensation expense, in each case as set forth in the financial statements for the applicable plan year. |
Other Criteria and Considerations. In determining to award 100% on the discretionary performance metric, the C&B Committee considered the following accomplishments in 2018, among other things:
total shareholder returns that were the highest among the peer group;
production and adjusted EBITDAX increase of over 110% and 194%, respectively;
substantial growth in proved reserves for year-end 2018 as compared to 2017;
successful consummation of one acquisition, the sale of the Company’s non-core Oklahoma assets and the entry into the merger agreement with Denbury Resources Inc., all of which required significant Company resources; and
the Company’s total recordable incident rate as compared to the industry average.
NEO Cash Bonus Criteria
The cash bonus pool defines the total amount of cash available to pay annual incentive cash bonuses, but not the allocation of actual bonus awards. After the cash bonus pool has been computed, the C&B Committee determines the actual amount of our officers’ annual incentive cash bonuses, if any, as described below.
Our NEOs’ Annual Incentive Cash Bonus Target Amounts—The Annual Incentive Plan Guidelines provide for annual incentive cash bonus targets for our NEOs. The table below shows our NEOs’ Target Amounts, which remain unchanged from 2017 levels for continuing executive officers.
|
| | | |
NEOs' Target Amounts |
Name | | 2018 Target
(% of Base Salary)
|
| | |
John. A. Brooks | | 100 |
|
Steven A. Hartman | | 85 |
|
Benjamin A. Mathis | | 85 |
|
Mr. Quarls did not participate in our 2018 Annual Incentive Cash Bonus program in light of his retirement on February 28, 2018.
Peer Comparison Data. The cash bonus targets shown above are intended to result in our NEOs receiving annual cash bonuses in amounts that are competitive with our Peer Group when target performance goals are met and which constitute a reasonable and Peer Group-comparable portion of our NEOs’ total compensation.
Individual Performance and Determinations
The Annual Incentive Award Guidelines provide that each officer's individual bonus award be subject to adjustment based on their individual performance during the period. The C&B Committee believed that our NEOs generally performed well in 2018 and did not make any adjustments, either upward or downward, to any of the NEOs bonus payouts. Because Mr. Quarls retired in 2018, he did not receive a bonus for such year. Below are the final bonus payouts received by each of our NEOs.
|
| | | | | | | | | |
| Name | | 2018 Target
($) | | 2018 Payout
(as a % of Target) | | 2018 Payout
($) |
| | | | | | | |
| John A. Brooks | | 437,750 |
| | 94 | % | | 411,485 |
|
| Steven A. Hartman | | 240,763 |
| | 94 | % | | 226,317 |
|
| Benjamin A. Mathis | | 280,500 |
| | 94 | % | | 263,670 |
|
Long-Term Equity Compensation
Long-term equity awards align the interests of our NEOs with those of our shareholders by creating a strong financial incentive for our NEOs to promote our long-term financial and operational success and, along with our executive stock ownership guidelines, encourage NEO stock ownership. Long-term equity compensation awards are expressed in dollar values at grant, and we generally pay those awards to officers 50% in the form of performance-based restricted stock units and 50% in the form of time-vested restricted stock units. The actual number of restricted stock units awarded is based on the volume-weighted average price per share for the 10-trading days preceding the grant date.
As a result of the Company’s recent emergence from bankruptcy and for the purpose of immediately aligning executives’ and other key employees’ interests with those of the Company’s new shareholders and incentivizing and supporting the retention of key personnel, awards granted in 2017 represented an accelerated one-time award in lieu of annual grants over a three-year period. For that reason, the Company did not make any grants of restricted stock units in 2018, except to newly hired key employees or in connection with a promotion. The C&B Committee continuously monitors its NEOs and other key employees’ stockholdings to ensure consistency with the C&B Committee’s overall compensation philosophy and competitiveness when compared with peer companies and although it does not currently anticipate granting equity compensation awards in 2019, it retains the discretion to do so as necessary to adapt to changing circumstances.
Mr. Quarls. Upon his appointment as Executive Chairman of the Company in August 2017, Mr. Quarls was granted 18,910 restricted stock units, 50% in time-vested restricted stock units and 50% in performance-based restricted stock units. The C&B Committee set the target value of this officer equity grant at 250% of his base salary level, which was approximately the 50th percentile compared to market data provided by L&A, and then reduced this amount by 60% as Mr. Quarls was expected to devote only 60% of an average work week to Company matters. Prior to his appointment as Executive Chairman, Mr. Quarls received a grant of 18,772 restricted stock units for his service as a director of the Company. Certain of Mr. Quarls’ equity awards vested pursuant to the terms of his Separation Agreement. Please see “—Employment Contracts-Separation and Consulting Agreement”.
Mr. Brooks. In January 2017, Mr. Brooks was granted 55,840 restricted stock units, 50% in time-vested restricted stock units and 50% in performance-based restricted stock units, based on an incentive target of 250% of his base salary, which was just below the 50th percentile compared to similar positions based on market data provided by L&A. Upon Mr. Brooks’ promotion to President and Chief Executive Officer in August 2017, Mr. Brooks was granted an additional award of 26,670 restricted stock units, 50% in time-vested restricted stock units and 50% in performance-based restricted stock units, based on an incentive target of 375% of his base salary. Mr. Brooks’ aggregate incentive award placed him between the 25th and 50th percentile of CEOs within our Peer Group based on market data provided by L&A. The C&B Committee determined that this amount was appropriate given Mr. Brooks’ relative inexperience in the Chief Executive Officer role.
Mr. Hartman. In January 2017, Mr. Hartman was granted 10,000 restricted stock units, 50% in time-vested restricted stock units and 50% in performance-based restricted stock units. Mr. Hartman’s grant was relatively modest in comparison to his position as he had previously been granted 63,762 time-vested restricted stock units in 2016 upon the Company’s emergence from bankruptcy pursuant to his employment agreement and the C&B Committee determined that his equity holdings were competitive with peer companies and consistent with the C&B Committee’s compensation philosophy of incentivizing long-term performance.
Mr. Mathis. In September 2017 upon his appointment as Vice President, Operations, Mr. Mathis was granted 26,122 restricted stock units, 50% in time-vested restricted stock units and 50% in performance-based restricted stock units, based on an incentive target of 125% of his base salary, which was prorated for his start date. Upon Mr. Mathis’ promotion to Senior Vice President, Operations and Engineering in July of 2018, Mr. Mathis was granted an additional award of 5,007 time-vested restricted stock units, based on an incentive target of 200% of his base salary. These were the only equity awards granted to our NEOs in 2018.
For more information on the terms of these time- and performance-based restricted stock units, see the “Narrative Discussion of Equity Awards” that follows the Grants of Plan-Based Awards table.
Compensation Risk Assessment
We believe that any risks associated with our compensation policies and practices are mitigated in large part by the following factors and, therefore, that no such risks are likely to have a material adverse effect on us:
We pay a mix of compensation which includes near-term cash and long-term equity-based compensation.
We base our annual incentive cash bonus and long-term equity compensation awards on several different performance metrics, which discourages our employees from placing undue emphasis on any one metric or aspect of our business at the expense of others.
We believe that our performance metrics are reasonably challenging, yet should not require undue risk-taking to achieve.
Our performance metrics include quantitative financial and operational metrics as well as qualitative metrics related to our operations, strategy and other aspects of our business.
The performance periods under our performance-based restricted stock units overlap, and our time-vested restricted stock units generally vest over a five-year period. This mitigates the motivation to maximize performance in any one period at the expense of others.
Our NEOs are required to own our stock as provided in our Executive Stock Ownership Guidelines.
We believe that we have an effective management process for developing and executing our short and long-term business plans.
Our compensation policies and programs are overseen by the C&B Committee.
The C&B Committee retains an independent compensation consultant.
Policy Prohibiting Hedging
We believe that derivative transactions, including puts, calls and options, for our securities carry a high risk of inadvertent securities laws violations and also could afford the opportunity for our employees and directors to profit from a market view that is adverse to us. For these reasons, we prohibit our employees and directors from engaging in any type of derivative transaction in respect of our securities.
Tax Implications
Section 162(m) of the Internal Revenue Code generally precludes a publicly held company from taking a federal income tax deduction for compensation paid in excess of $1 million per year to certain covered employees, which include our NEOs. There was an exception to the $1 million limitation for performance-based compensation meeting certain requirements. For taxable years beginning after December 31, 2017, this exemption has been repealed for all but certain grandfathered compensation arrangements that were in effect as of November 2, 2017. As such, there can be no assurance that any compensation awarded or paid in prior years will be fully tax deductible. In addition, to maintain flexibility in compensating the Company’s executive officers in a manner designed to promote varying corporate goals, the C&B Committee has not adopted a policy requiring all compensation to be tax deductible and expects that the deductibility of certain compensation paid will be limited by Code Section 162(m).
Our 2018 Say-on-Pay Vote
At our 2018 Annual Meeting of Shareholders, approximately 99.1% of our shareholders voting on our “say-on-pay” proposal voted FOR the compensation paid to our NEOs as set forth in the “Executive Compensation” section of our 2018 Proxy Statement (excluding abstentions and broker non-votes). The C&B Committee considered the outcome of this vote generally, and did not make any changes to our compensation programs as a result of this vote.
Compensation and Benefits Committee Report
The Compensation and Benefits Committee has reviewed the information contained above under the heading “Compensation Discussion and Analysis” and has discussed the Compensation Discussion and Analysis with management. Based upon its review and discussions with management, the Compensation and Benefits Committee recommended to the Board that the Compensation Discussion and Analysis be included in our Annual Report on Form 10-K.
Compensation and Benefits Committee
Jerry Schuyler (Chairman)
Michael Hanna
Darin Holderness
Summary Compensation Table
The following table sets forth the compensation paid, during or with respect to the years ended December 31, 2018, 2017 and 2016, to our NEOs for services rendered to us: |
| | | | | | | | | | | | | | | | | |
| Name and Principal Position | | Year | | Salary ($) | | Bonus ($) | | Stock Awards ($) (1)(2) | | All Other Compensation ($) (3) | | Total ($) |
| | | | | | | | | | | | | |
Harry Quarls(4) | | 2018 | | 41,346 |
| | — |
| | — |
| | 250,000 |
| | 291,346 |
|
| Former Executive Chairman | | 2017 | | 95,192 |
| | — |
| | 840,644 |
| | 37,500 |
| | 973,336 |
|
| | | | | | | | | | | | | |
| John A. Brooks | | 2018 | | 437,500 |
| | 411,485 |
| | — |
| | 19,000 |
| | 867,985 |
|
| President and | | 2017 | | 400,231 |
| | 300,944 |
| | 4,386,084 |
| | 38,800 |
| | 5,126,059 |
|
| Chief Executive Officer | | 2016 | | 385,000 |
| | 777,200 |
| (5) | — |
| | 38,800 |
| | 1,201,000 |
|
| | | | | | | | | | | | | |
| Steven A. Hartman | | 2018 | | 283,500 |
| | 226,317 |
| | — |
| | 19,000 |
| | 528,817 |
|
| Senior Vice President and | | 2017 | | 275,000 |
| | 187,000 |
| | 573,150 |
| | 18,400 |
| | 1,053,550 |
|
| Chief Financial Officer | | 2016 | | 285,621 |
| | 170,000 |
| | 600,000 |
| | 31,000 |
| | 1,086,621 |
|
| | | | | | | | | | | | | |
Benjamin A. Mathis (6) | | 2018 | | 312,512 |
| | 263,670 |
| | 440,115 |
| | 19,000 |
| | 1,035,297 |
|
| Senior Vice President, Operations and Engineering | |
| |
|
| |
|
| |
|
| |
|
| |
|
|
__________ | |
(1) | Represents the aggregate grant date fair value of time-vested restricted stock units and performance-based restricted stock units granted by the C&B Committee to each NEO in consideration for services rendered to us. These amounts were computed in accordance with FASB ASC Topic 718 and were based on the closing prices of our Common Stock on the dates of grant, in the case of the time-vested restricted stock units, and a Monte Carlo simulation of potential outcomes, in the case of the performance-based restricted stock units. See Note 17 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2018. |
| |
(2) | Performance-based restricted stock units granted in 2017 are reported in this column based on target level achievement, which was the probable outcome of such conditions on the dates of grant. No performance-based restricted stock units were granted to our NEOs in 2016 or 2018. The grant date values of the performance-based restricted stock units assuming that the highest level of performance conditions will be achieved was as follows: |
|
| | | | |
| Name | | 2017 |
| Quarls | | $ | 937,180 |
|
| Brooks | | $ | 4,835,218 |
|
| Hartman | | $ | 629,200 |
|
| |
(3) | Includes our matching and other contributions to our NEOs’ 401(k) plan accounts. Additionally, we paid $37,500 in annual retainers to Mr. Quarls in 2017 for his service on our Board prior to his appointment as Executive Chairman in August 2017 and $250,000 to Mr. Quarls in 2018 in consulting fees. Please see “—Employment Contracts-Separation and Consulting Agreement”. We contributed the following amounts to the 401(k) plan accounts of our NEOs in 2018: |
|
| | | | |
| Name | | 2018 |
| Quarls | | $ | — |
|
| Brooks | | $ | 19,000 |
|
| Hartman | | $ | 19,000 |
|
| Mathis | | $ | 19,000 |
|
| |
(4) | Mr. Quarls was elected Executive Chairman effective August 15, 2017 and retired from employment with the Company on February 28, 2018. The amounts shown above for Mr. Quarls for 2017 reflect amounts paid to him from and after August 15, 2017 in his capacity as Executive Chairman, and prior to such date, in his capacity as a non-employee director of the Company. Amounts shown for 2018 reflect his base salary received for services prior to his retirement and consulting fees paid to him pursuant to his Separation and Consulting Agreement. |
| |
(5) | Includes a $500,000 retention bonus paid to Mr. Brooks upon the Company’s emergence from bankruptcy on September 12, 2016. |
| |
(6) | Mr. Mathis joined the Company as Vice President, Operations in September 2017 and was promoted to Senior Vice President, Operations and Engineering in August 2018. |
Grants of Plan-Based Awards
The following table sets forth information concerning the time-vested restricted stock units granted to Mr. Mathis in 2018 by the C&B Committee. None of our other NEOs received any other grants of plan based awards in 2018. |
| | | | | | | | | |
| Name | | Grant Date | | All Other Stock Awards: Number of Shares of Stock or Units (#) (1) | | Grant Date Fair Value of Stock Awards ($) (2) |
| | | | | | | |
| Benjamin A. Mathis | | 7/24/2018 | | 5,007 |
| | $ | 440,115 |
|
__________
| |
(1) | These are awards of time-vested restricted stock units granted under the Incentive Plan. |
| |
(2) | The grant date fair value of the time-vested units was calculated using a per share price of $87.90, which was the closing price of our Common Stock on the grant date. |
Narrative Discussion of Equity Awards
Time-Vested Restricted Stock Units
We granted time-vested and performance-based restricted stock units to all of our NEOs in 2017. Because these awards represented an accelerated one-time award in lieu of annual grants over a three-year period, we did not make any grants to our NEOs in 2018, except to Mr. Mathis in connection with his promotion to Senior Vice President, Operations and Engineering. In determining the number of units to provide to Mr. Mathis, we considered the volume weighted average price per share of our Common Stock on Nasdaq for the ten trading days preceding the date of grant. These time-vested restricted stock units vest over a four-year period, with one-fourth of each award vesting each January 26 of 2019, 2020, 2021 and 2022, subject to Mr. Mathis’ continuous service with the Company through the applicable vesting date. All time-vested restricted stock units granted to our NEOs provide that payments on such restricted stock units will be made in shares. Upon the occurrence of a change of control, all unvested time-vested restricted stock units will vest as of the date of the change of control. Upon a termination of service by the Company without cause (as defined in the award agreement) or by the officer for good reason (as defined in the award agreement), the next tranche of restricted stock units scheduled to vest will vest as of the date of such termination. Upon an officer’s termination of service by the Company due to the officer’s death or disability (as defined in the award agreement), a pro-rated portion of the restricted stock units will vest as of the date of such termination.
Performance-Based Restricted Stock Units
We granted performance-based restricted stock units to all of our NEOs in 2017. Because these awards represented an accelerated one-time award in lieu of annual grants over a three-year period, we did not make any grants to our NEOs in 2018. The performance-based units vest (if at all) in 1/3 increments ranging from 0% to 200% of the target amount based on the Company’s share price appreciation relative to the share price appreciation of the Dow Jones iShares U.S. Oil & Gas Exploration & Production ETF (the “IEO ETF”) for, with respect to the grants in January of 2017, each of three separate three-year performance periods ended December 31, 2019, December 31, 2020 and December 31, 2021, or with respect to grants in August 2017, 1/2 increments at the end of each of two separate three-year performance periods ending December 31, 2020 and December 31, 2021, subject to the officer’s continuous service with the Company through the end of each performance period. Upon the occurrence of a change of control, unvested restricted stock units will vest as of the date of the change of control based on the Company’s share price appreciation relative to the IEO ETF for the applicable performance period ending as of the date of the change of control. Upon an NEO’s termination of service by the Company without cause (as defined in the award agreement) or by the officer for good reason (as defined in the award agreement), or due to such NEO’s death or disability (as defined in the award agreement), a pro-rated portion of the restricted stock units will vest as of
the date of such termination. For information on the accelerated vesting of certain performance-based restricted stock units granted to Mr. Quarls, see “—Employment Contracts-Separation and Consulting Agreement” below.
The following table sets forth the performance criteria applicable to the performance-based restricted stock units: |
| | | | | |
Performance Delta(1) | | Positive Share Price Appreciation | | Negative Share Price Appreciation |
| 30 or Greater | | 200% | | 100% |
| 25 | | 180% | | 90% |
| 20 | | 160% | | 80% |
| 15 | | 140% | | 70% |
| 10 | | 120% | | 60% |
| 0 | | 100% | | 50% |
| -5 | | 75% | | 38% |
| -10 | | 50% | | 25% |
| Less than -10.01 | | 0% | | 0% |
| | |
| (1) | Equal to the difference between the share price appreciation of the Company and the share price appreciation of the peer group index for the period beginning on the first day of the performance period and ending on the last day of the applicable performance period. |
Employment Contracts
The Company currently maintains no employment agreements with anyshare-based compensation awards for which we recognized accelerated expense of its executive officers; however, the Company entered into the Separation Agreement with Mr. Quarls in connection with his retirement from the Company in early 2018.
Separation and Consulting Agreement
Mr. Quarls retired from his positions as Executive Chairman and as a director of the Company, effective as of February 28, 2018. In connection therewith, Mr. Quarls entered into the Separation Agreement with the Company pursuant to which Mr. Quarls agreed to provide through the remainder of 2018 certain transition and support services to the Company as reasonably requested by the Board. The Company paid Mr. Quarls a consulting fee of $250,000 for consulting services. Under the Separation Agreement, Mr. Quarls vested in (i) 12,515 restricted stock units previously granted to him as Chairman of our Board in connection with our emergence from bankruptcy in December of 2016, (ii) 1,891 time-vested restricted stock units previously granted to him in connection with his appointment as our Executive Chairman in August of 2017, and (iii) 1,968 performance-based restricted stock units previously granted to him in connection with his appointment as our Executive Chairman in August of 2017. All other unvested restricted stock units held by Mr. Quarls were forfeited as of February 28, 2018.
Outstanding Equity Awards at Fiscal Year-End
The following table sets forth, for each of our NEOs, information regarding outstanding equity awards as of December 31, 2018:
|
| | | | | | | | | | | | | | | |
| | | Stock Awards | |
| Name | | Number of Shares or Units of Stock That Have Not Vested (#) | | Market Value of Shares or Units of Stock That Have Not Vested (1) | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested (1) | |
| | | | | | | | | | |
| Harry Quarls | | — |
|
| — |
| | — |
|
| — |
|
|
| | | | | | | | | | |
| John A. Brooks | | 22,336 |
| (2) | $ | 1,207,484 |
| | 27,920 |
| (3) | $ | 1,509,355 |
|
|
| | | 10,668 |
| (4) | $ | 576,712 |
| | 13,335 |
| (5) | $ | 720,890 |
|
|
| | | | | | | | | | |
| Steven A. Hartman | | 21,254 |
| (6) | $ | 1,148,991 |
| |
|
|
|
|
|
|
| | | 4,000 |
| (7) | $ | 216,240 |
| | 5,000 |
| (3) | $ | 270,300 |
|
|
| | | | | | | | | | |
| Benjamin A. Mathis | | 10,448 |
| (8) | $ | 564,819 |
| | 13,061 |
| (5) | $ | 706,077 |
|
|
| | | 5,007 |
| (9) | $ | 270,678 |
| |
|
|
|
|
|
|
__________
| |
(1) | The value of these awards is based on the number of shares reported multiplied by $54.06, the closing price of our Common Stock on December 31, 2018, the last trading day of our fiscal year. |
| |
(2) | Of these time-vested restricted stock units, 5,584 vested on January 26, 2019 and 5,584 will vest on January 26 of each of 2020, 2021 and 2022. |
| |
(3) | The performance period for one-third of these performance-based restricted stock units will expire on each of December 31, 2019, December 31, 2020 and December 31, 2021. The market value of these performance-based restricted stock units reflect an assumed payout percentage of 100%. |
| |
(4) | Of these time-vested restricted stock units, 2,667 vested on January 26, 2019 and 2,667 will vest on January 26 of each of 2020, 2021 and 2022. |
| |
(5) | The performance period for one-half of these performance-based restricted stock units will expire on each of December 31, 2020 and December 31, 2021. The market value of these performance-based restricted stock units reflect an assumed payout percentage of 100%. |
| |
(6) | All 21,254 restricted stock units will vest on September 12, 2019. |
| |
(7) | Of these time-vested restricted stock units, 1,000 vested on January 26, 2019 and 1,000 will vest on January 26 of each of 2020, 2021 and 2022. |
| |
(8) | Of these time-vested restricted stock units, 2,612 vested on January 26, 2019 and 2,612 will vest on January 26 of each of 2020, 2021 and 2022. |
| |
(9) | Of these time-vested restricted stock units, 1,252 vested on January 26, 2019 and 1,252 will vest on January 26 of each of 2020, 2021 and 2022. |
Stock Vested in 2018
The following table sets forth the number of shares of our Common Stock acquired, and the values realized, by our NEOs upon the vesting of time-vested restricted stock units$0.6 million during 2018: |
| | | | | | | |
| | | Stock Awards |
| Name | | Number of Shares Acquired on Vesting (#) | | Value Realized on Vesting (1) |
| Harry Quarls | | 18,265 |
| | $ | 697,169 |
|
| John A. Brooks | | 8,251 |
| | $ | 377,071 |
|
| Steven A. Hartman | | 22,254 |
| | $ | 1,637,412 |
|
| Benjamin A. Mathis | | 2,612 |
| | $ | 119,368 |
|
__________
| |
(1) | Amount is based on the number of shares of restricted stock units vested multiplied by the market value of the underlying shares on the vesting date. |
2016 Management Incentive Plan
On October 4, 2016, we adopted the Incentive Plan. The purpose of the Incentive Plan is to assist the Company in attracting and retaining qualified employees, directors and consultants and to align their financial interests with the financial interests of the Company’s shareholders. The selection of participants in the Incentive Plan, the awards granted to those participants, and the vesting and other terms of the awards granted is determined by the C&B Committee and/or the Board. The Incentive Plan provides for the following types of awards: options; restricted stock; restricted stock units; and other stock awards.
The aggregate number of shares of Common Stock reserved for issuance pursuant to the Incentive Plan is 749,600. The Incentive Plan expires on, and no new awards may be granted after, October 4, 2026, unless earlier terminated by the Board. The Incentive Plan contemplates that any award granted under the plan may provide for the earlier termination of restrictions and acceleration of vesting in the event of a Qualified Liquidity Event (as defined in the Incentive Plan), as may be described in the particular award.
Potential Payments upon Termination or a Change in Control
Our NEOs do not currently have individual agreements providing for severance payments or benefits. Instead, such NEOs participate in the Penn Virginia Corporation 2017 Special Severance Plan (as amended and restated effective July 18, 2018) (the “Severance Plan”). The Severance Plan provides for the following payments and benefits in the event of a termination of employment without “Cause” or resignation for “Good Reason” (each as defined in the Severance Plan) within the six-month period following a “Qualified Liquidity Event”:
A lump-sum cash payment in an amount equal to a specified number of weeks of “Base Pay” with Mr. Brooks eligible to receive 130 weeks of Base Pay and the other NEOs eligible to receive 78 weeks of Base Pay. “Base Pay” refers to the base salary or base wages that the executive officer earns during a week, based upon rate of pay in effect for the participant immediately before the participant’s termination of employment, excluding overtime, bonuses, incentive compensation or any other special payments.
If the NEO elects continuation coverage under COBRA, continued coverage at the same contribution rate paid by Penn Virginia for active employees for the executive officer and his or her covered dependents following the NEO’s date of termination for the number of weeks indicated above (or such shorter period during which the executive is eligible to receive COBRA coverage).
Additionally, under the Incentive Plan and related award agreements, upon a “Qualified Liquidity Event,” all time-vested restricted stock units issued automatically vest in full and all performance-based restricted stock units will vest anywhere from 0-200% based on the Company’s achievement of the performance criteria through the date of the Qualified Liquidity Event.
A “Qualified Liquidity Event” under our award agreements and the Severance Agreement are generally defined as a sale of at least 40% in total gross fair market value of our assets, the acquisition by a person or group of more than 50%, or 30% under our Severance Agreement, of the voting power of our stock, or certain changes in the composition of our Board.
In addition, under such award agreements, upon an NEO’s termination of employment without Cause (as defined in the Incentive Plan) or resignation for Good Reason (as defined in the Incentive Plan), the executive will vest in the next tranche of time-vested restricted stock units scheduled to vest under the applicable award agreement. Upon an NEO’s termination due to the individual’s death or disability, the executive is to vest in a pro-rated number of time-vested restricted stock units based on the individual’s period of service with the Company during the applicable vesting period.
Under our performance-based restricted stock units, upon an NEO’s termination of employment without Cause, resignation for Good Reason, or due to the individual’s death or disability, the executive will vest in a pro-rata portion of the target number of restricted stock units granted based on the individual’s period of service with the Company during the applicable performance periods.
Estimated Payments
The table below and the discussion that follows reflect the amount of compensation payable to each NEO, other than Mr. Quarls, upon termination from the Company under several scenarios assuming such termination was effective
December 31, 2018. For information on the payments actually received by Mr. Quarls in connection with his February 2018 termination, please see “Executive Compensation-Employment Contracts-Separation and Consulting Agreement” above.
|
| | | | | | | | | | | | |
| Name of Executive Officer | | Cash Severance ($) | | Accelerated Vesting of Restricted Stock Units (#) | | Total Estimated Value of Accelerated Vesting ($) (1) | | Other Benefits ($) (2) |
| | | | | | | | | |
| John A. Brooks | | | | | | | | |
| Death or Disability | | — |
| | 26,028 |
| | 1,407,054 |
| | — |
|
| Change in Control | | 1,094,375 |
| | 74,259 |
| | 4,014,442 |
| | 36,000 |
|
Termination by Employee Without Good Reason or by Company for Cause | | — |
| | — |
| | — |
| | — |
|
Termination for Good Reason or by Company Without Cause | | — |
| | 27,647 |
| | 1,494,577 |
| | — |
|
| | | | | | | | | |
| Steven A. Hartman | | | | | | | | |
| Death or Disability | | — |
| | 3,540 |
| | 191,366 |
| | — |
|
| Change in Control | | 424,875 |
| | 30,254 |
| | 1,635,531 |
| | 36,000 |
|
Termination by Employee Without Good Reason or by Company for Cause | | — |
| | — |
| | — |
| | — |
|
Termination for Good Reason or by Company Without Cause | | — |
| | 24,865 |
| | 1,344,208 |
| | — |
|
| | | | | | | | | |
| Benjamin A. Mathis | | | | | | | | |
| Death or Disability | | — |
| | 6,456 |
| | 349,025 |
| | — |
|
| Change in Control | | 495,000 |
| | 28,517 |
| | 1,541,629 |
| | 36,000 |
|
Termination by Employee Without Good Reason or by Company for Cause | | — |
| | — |
| | — |
| | — |
|
Termination for Good Reason or by Company Without Cause | | — |
| | 8,417 |
| | 455,000 |
| | — |
|
__________
| |
(1) | Reflects value of accelerated vesting of equity grants at $54.06 per share (closing price on December 31, 2018, the last trading day of the fiscal year). |
| |
(2) | Includes estimated cost of COBRA continuation coverage. |
Pay Ratio Disclosure
The 2018 annual total compensation of the median compensated of all our employees who were employed as of December 31, 2018, other than our CEO, John A. Brooks, was $100,055; Mr. Brooks’ 2018 annual total compensation was $867,985, and the ratio of these amounts was 1-to-8.7.
We selected December 31, 2018 as the date upon which to identify our median compensated employee. On that date, our employee population consisted of 94 employees excluding the CEO. To identify the median compensated employee, we utilized the annual total compensation as reported in Box 1 of each employee’s Form W-2 for 2018 provided to the Internal Revenue Service. We believe this methodology provides a reasonable basis for determining each employee’s total annual compensation and is an economical way to evaluate our employee population’s total annual compensation and to identify our median employee. For the employees hired during 2018, we utilized the annual total compensation reported on each such employee’s Form W-2 for 2018 without annualization adjustments.Once we identified our median employee, we calculated
that employee’s annual total compensation for 2018 in the same manner that we determined the total compensation of our NEOs for purposes of the Summary Compensation Table set forth above. This resulted in an annual compensation of $100,055 for the identified employee for the year ended December 31, 2018. The calculationcosts associated with the Hartman and Quarls Separation Agreements, including the share-based compensation charges, were included as a component of “G&A expenses” in our Consolidated Statements of Operations for the totalyears ended December 31, 2019 and 2018, respectively.
Defined Contribution Plan
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 6 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 $0.9 million, $0.6 million, $0.5 million for the years ended December 31, 2019, 2018 and 2017, respectively, and is included as a component of “General and administrative expenses” in our CEO isStatements of Operations. Amounts representing accrued obligations to the 401(k) Plan of $0.3 million and $0.3 million are included in the Summary Compensation Table set forth above.
Our pay ratio is a reasonable estimate calculated in a manner consistent with SEC rules based“Accounts payable and accrued expenses” caption on our payroll records. BecauseConsolidated Balance Sheets as of December 31, 2019 and 2018, 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 for each year ended December 31, 2019, 2018 and 2017, and is included as a component of “Other, net” in our Statements of Operations. The combined unfunded benefit obligations under these plans were $1.4 million and are included within the SEC’s rules for identifying the median compensated employee“Accounts payable and calculating the pay ratio basedaccrued expenses” (current portion) and “Other liabilities” (noncurrent portion) captions on that employee’s annual total compensation allow companies to adopt a varietyour Consolidated Balance Sheets as of methodologies, to apply certain exclusions,December 31, 2019 and to make reasonable estimates and assumptions that reflect their compensation practices, the pay ratio reported by other companies may not be comparable to the pay ratio reported above, as other companies have different employment and compensation practices and may utilize different methodologies, exclusions, estimates and assumptions in calculating their own pay ratios.2018.
Item 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Unless otherwise indicated, the following table sets forth, as of April 16, 2019, the amount and percentage of our outstanding shares of Common Stock beneficially owned by (i) each person known by us to beneficially own more than 5% of our outstanding shares of Common Stock, (ii) our directors, (iii) each executive officer named in the Summary Compensation Table under the heading “Executive Compensation-Summary Compensation Table” and (iv) all of our directors and executive officers as a group:
|
| | | | | | |
| Name of Beneficial Owners | | Shares Beneficially Owned (1) | | Percent of Class (2) |
Contrarian Capital Management, L.L.C. (3) | | 788,285 |
| | 5.2 | % |
Mangrove Partners Master Fund, Ltd (4) | | 1,615,497 |
| | 10.7 | % |
Strategic Value Partners, LLC (5) | | 1,540,634 |
| | 10.2% |
|
BlackRock, Inc. (6) | | 1,956,108 |
| | 12.9% |
|
The Vanguard Group (7) | | 809,738 |
| | 5.4% |
|
| Directors/Executive Officers | |
|
| |
|
|
| Darin G. Holderness | | 5,562 |
| | * |
|
| Jerry R. Schuyler | | 5,562 |
| | * |
|
| Michael Hanna | | — |
| | * |
|
| Brian Steck | | — |
| | * |
|
| V. Frank Pottow | | 949 |
| | * |
|
| John A. Brooks | | 10,435 |
| | * |
|
| Steven A. Hartman | | 27,990 |
| | * |
|
| Benjamin Mathis | | 4,604 |
| | * |
|
| Directors and Executive Officers as a group (8 persons) | | 55,102 |
| | * |
|
_____________________
| |
*17. | Represents less than 1%Interest Expense |
The following table summarizes the components of interest expense for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Interest on borrowings and related fees | $ | 36,593 |
| | $ | 32,164 |
| | $ | 6,995 |
|
Accretion of original issue discount 1 | 743 |
| | 680 |
| | 161 |
|
Amortization of debt issuance costs 2 | 2,611 |
| | 2,736 |
| | 1,961 |
|
| Capitalized interest | (4,136 | ) | | (9,118 | ) | | (2,725 | ) |
| | $ | 35,811 |
| | $ | 26,462 |
| | $ | 6,392 |
|
| |
1 | Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 9). |
| |
(1)2 | Unless otherwise indicated, all shares are owned directly byThe year ended December 31, 2017 includes a total of $0.8 million of write-offs attributable to changes in the named holder and such holder hascomposition of financial institutions comprising the sole powerCredit Facility’s bank group in connection with amendments to vote and dispose of such shares. |
| |
(2) | Based on 15,105,251 shares of our Common Stock issued and outstanding on April 16, 2019. |
| |
(3) | Based solely on a Schedule 13G filed with the SEC on April 5, 2019 by Contrarian Capital Management, L.L.C. The address for Contrarian Capital Management, L.L.C. is 411 West Putnam Avenue, Suite 125, Greenwich, CT 06830. |
| |
(4) | Based on a Schedule 13D/A filed with the SEC on March 28, 2019 by Mangrove Partners Master Fund, Ltd., Mangrove Partners and Nathaniel H. August. Such filing indicated that Mangrove Partners Master Fund, Ltd, Mangrove Partners and Nathanial August had shared voting and dispositive power with respect to all 1,615,497 shares of Penn Virginia Common Stock. The address for Mangrove Partners Master Fund, Ltd is Maples Corp. Svcs, PO Box 309, Ugland House, S. Church Street, George Town E9 KY1-114, and the address for Mangrove Partners and Nathaniel H. August is 645 Madison Avenue, 14th Floor, New York, New York 10022.Credit Facility (see Note 9). |
| |
(5)18. | Based solely on a Schedule 13D/A filed with the SEC on April 16, 2019 by Strategic Value Partners, LLC and several investment manager entities of which Strategic Value Partners, LLC is a managing member. Such filing indicates that Strategic Value Partners, LLC had shared voting and dispositive power with respect to all of the shares of Penn Virginia Common Stock included in the table above. The address for Strategic Value Partners, LLC is 100 West Putnam Avenue, Greenwich, CT 06830.Earnings per Share |
The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Net income – basic and diluted | $ | 70,589 |
| | $ | 224,785 |
| | $ | 32,662 |
|
| | | | | | |
| Weighted-average shares – basic | 15,110 |
| | 15,059 |
| | 14,996 |
|
Effect of dilutive securities 1 | 16 |
| | 233 |
| | 67 |
|
| Weighted-average shares – diluted | 15,126 |
| | 15,292 |
| | 15,063 |
|
| |
(6)1 | Based solely onRepresents a Schedule 13G/A filedcombination of unvested RSUs and PRSUs that are dilutive with the SEC on Januaryexception of December 31, 2019 by BlackRock, Inc. Such filing indicates that BlackRock, Inc. has sole voting power with respectat which time all of our unvested PRSUs were determined to 1,918,993 sharesbe at a zero percent vesting level due to the relative performance of Penn Virginia Common Stock and sole dispositive power with respect to 1,956,108 shares of Penn Virginia Common Stock. The address of BlackRock, Inc. is 55 East 52nd Street, New York, NY 10055.our common stock. |
Supplemental Quarterly Financial Information (Unaudited)
|
| | | | | | | | | | | | | | | | |
| 2019 | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
Revenues 1 | | $ | 105,228 |
| | $ | 122,767 |
| | $ | 119,304 |
| | $ | 123,917 |
|
| Operating income | | $ | 38,668 |
| | $ | 47,888 |
| | $ | 40,040 |
| | $ | 50,225 |
|
| Income (loss) | | $ | (38,697 | ) | | $ | 51,625 |
| | $ | 54,362 |
| | $ | 3,299 |
|
Income (loss) per share – basic 2 | | $ | (2.56 | ) | | $ | 3.42 |
| | $ | 3.60 |
| | $ | 0.22 |
|
Income (loss) per share – diluted 2 | | $ | (2.56 | ) | | $ | 3.40 |
| | $ | 3.59 |
| | $ | 0.22 |
|
| Weighted-average shares outstanding: | | | | | | | | |
| Basic | | 15,098 |
| | 15,106 |
| | 15,110 |
| | 15,126 |
|
| Diluted | | 15,098 |
| | 15,162 |
| | 15,160 |
| | 15,131 |
|
|
| | | | | | | | | | | | | | | | |
| 2018 | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
Revenues 3 | | $ | 77,211 |
| | $ | 111,580 |
| | $ | 127,185 |
| | $ | 124,856 |
|
| Operating income | | $ | 33,912 |
| | $ | 55,886 |
| | $ | 64,036 |
| | $ | 54,921 |
|
Income (loss) 4 | | $ | 10,295 |
| | $ | (2,521 | ) | | $ | 16,276 |
| | $ | 200,735 |
|
Income (loss) per share – basic 2 | | $ | 0.68 |
| | $ | (0.17 | ) | | $ | 1.08 |
| | $ | 13.32 |
|
Income (loss) per share – diluted 2 | | $ | 0.68 |
| | $ | (0.17 | ) | | $ | 1.06 |
| | $ | 13.10 |
|
| Weighted-average shares outstanding: | | | | | | | | |
| Basic | | 15,042 |
| | 15,058 |
| | 15,062 |
| | 15,075 |
|
| Diluted | | 15,081 |
| | 15,058 |
| | 15,344 |
| | 15,328 |
|
| |
(7)1 | Based solelyIncludes gains (losses) on a Schedule 13G filed withsales of assets of less than $0.1 million, less than $0.1 million, less than $0.1 million and $(0.1) million during the SEC on February 11,quarters ended March 31, 2019, by The Vanguard Group. Such filing indicates that The Vanguard Group has sole voting power with respect to 25,284 shares of Penn Virginia Common StockJune 30, 2019, September 30, 2019 and sole dispositive power with respect to 784,608 shares of Penn Virginia Common Stock. Such filing also indicates that The Vanguard Group beneficially owns, in the aggregate, 809,738 shares of Penn Virginia Common Stock. The address of The Vanguard Group is 100 Vanguard Boulevard, Malvern, PA 19355.December 31, 2019, respectively. |
Equity Compensation Plan2 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.
3 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.
| |
4 | The quarter ended December 31, 2018 includes a mark-to-market gain on derivatives of $149.2 million. |
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 certain information asour estimate of December 31, 2018, regardingnet quantities of proved reserves, including changes therein and proved developed and proved undeveloped reserves for the restricted stock units and securities issued and to be issued under our equity compensation plans. We do not have any equity compensation plans which were required to be approved by our shareholders.periods presented:
|
| | | | | | | | | |
| Plan Category | | Number of Securities To Be Issued Upon Vesting of Outstanding Options, Warrants and Rights (a) | | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b) | | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c) |
| Equity compensation plans approved by shareholders | | — |
|
| — |
|
| — |
|
Equity compensation plans not approved by shareholders (1) | | 386,182 |
| (2) | N/A |
| (3) | 275,544 |
|
|
| | | | | | | | | | | |
| | Oil | | NGLs | | Natural Gas | | Total Equivalents |
| Proved Developed and Undeveloped Reserves | (MBbl) | | (MBbl) | | (MMcf) | | (MBOE) |
| December 31, 2016 | 36,611 |
| | 6,765 |
| | 36,682 |
| | 49,490 |
|
| Revisions of previous estimates | (5,735 | ) | | (2,071 | ) | | (10,468 | ) | | (9,550 | ) |
| Extensions and discoveries | 23,850 |
| | 3,571 |
| | 16,840 |
| | 30,228 |
|
| Production | (2,764 | ) | | (523 | ) | | (2,949 | ) | | (3,779 | ) |
| Purchase of reserves | 3,867 |
| | 1,122 |
| | 7,162 |
| | 6,183 |
|
| December 31, 2017 | 55,829 |
| | 8,864 |
| | 47,267 |
| | 72,572 |
|
| Revisions of previous estimates | (19,096 | ) | | (1,789 | ) | | (9,608 | ) | | (22,487 | ) |
| Extensions and discoveries | 48,119 |
| | 11,737 |
| | 59,447 |
| | 69,764 |
|
| Production | (6,077 | ) | | (1,004 | ) | | (5,181 | ) | | (7,944 | ) |
| Purchase of reserves | 11,278 |
| | 969 |
| | 5,827 |
| | 13,218 |
|
| Sale of reserves in place | (397 | ) | | (733 | ) | | (6,259 | ) | | (2,173 | ) |
| December 31, 2018 | 89,656 |
| | 18,044 |
| | 91,493 |
| | 122,950 |
|
| Revisions of previous estimates | (24,709 | ) | | (4,055 | ) | | (25,440 | ) | | (33,006 | ) |
| Extensions and discoveries | 40,190 |
| | 6,575 |
| | 31,045 |
| | 51,939 |
|
| Production | (7,453 | ) | | (1,491 | ) | | (7,067 | ) | | (10,121 | ) |
| Purchase of reserves | 1,212 |
| | 81 |
| | 418 |
| | 1,363 |
|
| December 31, 2019 | 98,896 |
| | 19,154 |
| | 90,449 |
| | 133,125 |
|
| Proved Developed Reserves: | |
| | | | |
| | |
|
| December 31, 2017 | 22,412 |
| | 4,882 |
| | 27,229 |
| | 31,832 |
|
| December 31, 2018 | 35,190 |
| | 6,279 |
| | 31,833 |
| | 46,774 |
|
| December 31, 2019 | 40,641 |
| | 8,846 |
| | 41,808 |
| | 56,455 |
|
| Proved Undeveloped Reserves: | |
| | | | |
| | |
|
| December 31, 2017 | 33,417 |
| | 3,982 |
| | 20,038 |
| | 40,740 |
|
| December 31, 2018 | 54,466 |
| | 11,765 |
| | 59,660 |
| | 76,176 |
|
| December 31, 2019 | 58,255 |
| | 10,308 |
| | 48,641 |
| | 76,670 |
|
__________
| |
(1) | In accordance with our Plan of Reorganization which was supported by our prior creditors and current equityholders and confirmed by the Bankruptcy Court, we reserved for issuance 5% of our outstanding Common Stock for issuance under the Incentive Plan, which is described further below. |
| |
(2) | This amount consists of outstanding time- and performance-based restricted stock units and includes the maximum number of shares that may be issued upon settlement of outstanding performance-based restricted stock units granted under the Incentive Plan. |
| |
(3) | Restricted stock units do not have an exercise price and thus are not reflected here. |
Item 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Policies and Procedures Regarding Transactions with Related Persons
Under our Corporate Governance Principles, all directors must recuse themselves from any decision affecting their personal, business or professional interests. In addition, as a general matter, our practice is that any transaction with a related person is approved by disinterested directors. Our Chief Legal Counsel advises the Board as to which transactions, if any, involve related persons and which directors are prohibited from voting on a particular transaction. We have not entered into any transaction with a related person within the scope of Item 404(a) of Regulation S‑K since January 1, 2018.
Director Independence
The Nominating and Governance Committee of the Board has determined that each of Messrs. Holderness, Schuyler, Hanna, Steck and Pottow are, and prior to their respective resignations, each of Messrs. McCarthy and Geenberg were, “independent directors”, as defined by Nasdaq listing standards and applicable SEC rules and regulations. We refer to those current directors as “Independent Directors.” The Board has determined that none of the Independent Directors has any
direct or indirect material relationship with the Company other than as a director of the Company. In making this determination, the Board took into account the affiliation of Messrs. Steck, Hanna, Geenberg and McCarthy with certain shareholders of the Company and determined that these transactions did not result in a relationship that interferes with the exercise of their independent judgment in carrying out the responsibilities of a director of the Company and therefore did not preclude a finding of independence.
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Audit Fees
Grant Thornton was our independent registered public accounting firm to audit our financial statements for the fiscal year ending December 31, 2018. The following is a summarydiscussion and descriptionanalysis of feesthe significant changes in our proved reserve estimates for services providedthe periods presented:
Year Ended December 31, 2019
In 2019, our proved reserves increased by Grant Thornton10.2 MMBOE. due primarily to substantial changes in our development plans from the southeast portion of our acreage position in the Eagle Ford to the central region. The overall shift to this region will allow us to develop wells with a lower gas content than what we were experienced in the southeast region through the first half of 2019. After achieving more favorable results with certain wells in the central region, we proceeded to drill a total of 11 gross wells, or approximately 23 percent of our total wells drilled in 2019, in the central region that were not considered proved undeveloped locations at the end of 2018. Accordingly, we have prioritized our drilling schedule to exploit these more favorable opportunities. While we still believe that the southeastern sites have economic merit, despite a higher gas content, we have deferred drilling them beyond the five-year window which results in revisions due to timing. Accordingly, our five-year drilling plan is heavily weighted to the lower gas content central region.
We had downward revisions of 33.0 MMBOE including: (i) 32.1 MMBOE due to a change in timing beyond five years attributable to our development plans as discussed above, as well as a reduction of drilling rigs from three to two, combining certain wells into extended reach lateral locations and KPMGother reductions due to changes in the plan of development, (ii) 2.7 MMBOE due to 15 percent lower crude oil pricing from $65.56 per barrel to $55.67 per barrel and (iii) 1.6 MMBOE due to reductions in lateral length and net revenue interests partially offset by (iv) 3.4 MMBOE due to improved performance of certain proved undeveloped wells and proved undeveloped wells transferred to proved developed net of lower performance associated with certain existing proved developed wells including those reclassified to proved non-producing. Extensions and discoveries of 51.9 MMBOE are substantially attributable to geographical shift in our development plan, greater utilization of extended reach laterals, increasing the length of such laterals, higher estimated ultimate reserves (“EUR”) per lateral foot as well the addition of certain non-operated royalty wells. We acquired 1.4 MMBOE in connection with the acquisition of certain non-operating partners working interests in locations in which we are the operator.
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.
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:
|
| | | | | | | | | | | |
| | December 31, |
| | 2019 | | 2018 | | 2016 |
| Oil and gas properties: | | | | | |
| Proved | $ | 1,409,219 |
| | $ | 1,037,993 |
| | $ | 460,029 |
|
| Unproved | 53,200 |
| | 63,484 |
| | 117,634 |
|
| Total oil and gas properties | 1,462,419 |
| | 1,101,477 |
| | 577,663 |
|
| Other property and equipment | 21,317 |
| | 16,462 |
| | 10,057 |
|
| Total capitalized costs relating to oil and gas producing activities | 1,483,736 |
| | 1,117,939 |
| | 587,720 |
|
| Accumulated depreciation and depletion | (364,716 | ) | | (191,802 | ) | | (60,247 | ) |
Net capitalized costs relating to oil and gas producing activities 1 | $ | 1,119,020 |
| | $ | 926,137 |
| | $ | 527,473 |
|
_____________________________________________
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.
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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
Development costs 1 | $ | 355,925 |
| | $ | 416,037 |
| | $ | 135,360 |
|
Proved property acquisition costs 2 | 6,051 |
| | 86,514 |
| | 43,151 |
|
Unproved property acquisition costs 3 | 7,570 |
| | 30,637 |
| | 153,905 |
|
Exploration costs 4 | 363 |
| | 377 |
| | 696 |
|
| | $ | 369,909 |
| | $ | 533,565 |
| | $ | 333,112 |
|
_____________________________________________
1 Includes plugging and abandonment asset additions of $0.3 million, $0.7 million and $0.3 million and capitalized internal costs of $3.6 million, $3.3 million and $2.1 million for the years ended December 31, 2019, 2018 and 2017, respectively.
2 Includes plugging and abandonment assets acquired of $0.1 million in the year ended December 31, 2019 and $0.4 million and $0.5 million acquired in the Hunt and Devon Acquisitions during the years ended December 31, 2018 and 2017, respectively. Also includes capitalized internal costs of $0.5 million, $0.4 million and $0.3 million for the years ended December 31, 2019, 2018 and 2017, respectively.
3 Includes capitalized interest of $4.1 million, $9.1 million and $2.7 million for the years ended December 31, 2019, 2018 and 2017, respectively as well as 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.
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 below do not necessarily represent the economic reality of such transactions.
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:
|
| | | | | | | |
| | 2018 | | 2017 |
Audit Fees (1) | $ | 659,500 |
| | $ | 661,267 |
|
| Audit-Related Fees | — |
| | — |
|
| Tax Fees | — |
| | — |
|
| All Other Fees | — |
| | — |
|
| Total Fees | $ | 659,500 |
| | $ | 661,267 |
|
|
| | | | | | | | | | | |
| | Crude Oil | | NGLs | | Natural Gas |
| | $ per Bbl | | $ per Bbl | | $ per MMBtu |
| December 31, 2017 | $ | 51.34 |
| | $ | 18.48 |
| | $ | 2.98 |
|
| December 31, 2018 | $ | 65.56 |
| | $ | 23.60 |
| | $ | 3.10 |
|
| December 31, 2019 | $ | 55.67 |
| | $ | 13.36 |
| | $ | 2.58 |
|
_________________
The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved reserves for the periods presented:
|
| | | | | | | | | | | |
| | December 31, |
| | 2019 | | 2018 | | 2017 |
| Future cash inflows | $ | 6,260,292 |
| | $ | 6,719,145 |
| | $ | 3,091,366 |
|
| Future production costs | (1,792,891 | ) | | (1,852,168 | ) | | (1,069,910 | ) |
| Future development costs | (1,174,215 | ) | | (1,208,815 | ) | | (689,998 | ) |
| Future net cash flows before income tax | 3,293,186 |
| | 3,658,162 |
| | 1,331,458 |
|
| Future income tax expense | (334,451 | ) | | (413,137 | ) | | (84,350 | ) |
| Future net cash flows | 2,958,735 |
| | 3,245,025 |
| | 1,247,108 |
|
| 10% annual discount for estimated timing of cash flows | (1,469,853 | ) | | (1,621,135 | ) | | (656,624 | ) |
| Standardized measure of discounted future net cash flows | $ | 1,488,882 |
| | $ | 1,623,890 |
| | $ | 590,484 |
|
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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Sales of oil and gas, net of production costs | $ | (374,694 | ) | | $ | (361,478 | ) | | $ | (118,137 | ) |
| Net changes in prices and production costs | (402,616 | ) | | 585,737 |
| | 170,488 |
|
| Changes in future development costs | 415,193 |
| | 206,901 |
| | 30,692 |
|
| Extensions and discoveries | 459,501 |
| | 809,880 |
| | 131,060 |
|
| Development costs incurred during the period | 253,982 |
| | 204,160 |
| | 74,880 |
|
| Revisions of previous quantity estimates | (515,345 | ) | | (483,091 | ) | | (122,357 | ) |
| Purchases of reserves-in-place | 12,241 |
| | 86,128 |
| | 80,878 |
|
| Sale of reserves-in-place | — |
| | (8,912 | ) | | — |
|
| Changes in production rates and all other | (194,453 | ) | | 60,160 |
| | 12,161 |
|
| Accretion of discount | 176,935 |
| | 60,897 |
| | 31,755 |
|
| Net change in income taxes | 34,248 |
| | (126,976 | ) | | (18,486 | ) |
| Net increase (decrease) | (135,008 | ) | | 1,033,406 |
| | 272,934 |
|
| Beginning of year | 1,623,890 |
| | 590,484 |
| | 317,550 |
|
| End of year | $ | 1,488,882 |
| | $ | 1,623,890 |
| | $ | 590,484 |
|
| |
(1)Item 9 | Audit fees consist of fees for the audit of our consolidated financial statements, reviews of interim financial statements, the audit of our internal control over financial reporting, consents for registration statementsChanges in and reviews of acquisition financials.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, 2019. 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 Auditthat evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of December 31, 2019, 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, 2019. This evaluation was completed based on the framework established in Internal Control—Integrated Framework(2013) issued by the Committee Pre-Approval of Audit and Permissible Non-Audit ServicesSponsoring Organizations of Independentthe Treadway Commission.
Based on that assessment, our management has concluded that, as of December 31, 2019, our internal control over financial reporting was effective.
(c) Attestation Report of the Registered Public Accounting Firm
The Audit Committee’s policy is to pre-approve all audit, audit-related and non-audit services provided by ourGrant Thornton LLP, the independent registered public accounting firm. These services may include audit services, audit-related services, tax servicesfirm that audited and other services. The Audit Committee may also pre-approve particular servicesreported on a case-by-case basis. The Audit Committee may also delegate pre-approval authoritythe 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, 2019, 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 one or more of its members. Such member(s) must report any decisionsmaterially affect, our internal control over financial reporting.
None.
Part III
| |
| Item 10 | Directors, Executive Officers and Corporate Governance |
In accordance with General Instruction G(3), reference is hereby made to the Audit CommitteeCompany’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
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 next scheduled meeting. All services rendered for us by Grant Thornton in 2018 were pre-approved byCode of Business Conduct and Ethics, and waivers of the Audit Committee.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 |
In accordance with General Instruction G(3), reference is hereby made to the Company’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
In accordance with General Instruction G(3), reference is hereby made to the Company’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
| |
| Item 13 | Certain Relationships and Related Transactions, and Director Independence |
In accordance with General Instruction G(3), reference is hereby made to the Company’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
| |
Item 14 | Principal Accountant Fees and Services |
In accordance with General Instruction G(3), reference is hereby made to the Company’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
Part IV
Item 15 Exhibits and Financial Statement Schedules
The financial statements filed herewith are listed in the Index to Consolidated Financial Statements on page 58 of this Annual Report on Form 10-K.
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.
|
| |
| 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). |
| |
| Fourth Amended and Restated Bylaws of Penn Virginia Corporation effective as of December 20, 2019 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on December 27, 2019). |
| |
| Description of Common Stock. |
| |
| Master Agreement, Borrowing Base Increase Agreement, and Amendment No. 6 to Credit Agreement, dated as of May 7, 2019, 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 May 8, 2019). |
| |
| 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). |
| |
| 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). |
| |
| 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. (incorporated by reference to Exhibit 10.9.3 to Registrant’s Annual Report on Form 10-K filed on February 27, 2019). |
| |
| 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 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). |
| |
| Penn Virginia Corporation 2019 Management Incentive Plan (incorporated by reference to Appendix A to Company’s Definitive Proxy Statement for its 2019 Annual General Meeting of Shareholders filed on July 1, 2019). |
| |
| Form of Officer Restricted Stock Unit Award Agreement under 2019 Management Incentive Plan. |
| |
| Form of Performance Restricted Stock Unit Award Agreement under 2019 Management Incentive Plan. |
| |
| Form of Director Restricted Stock Award Agreement under 2019 Management Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on September 6, 2019). |
| |
| Separation and Transition Agreement, entered into as of July 1, 2019, between Penn Virginia Corporation and Steven A. Hartman (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on July 8, 2019). |
| |
| 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). |
| |
| 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. |
| |
| Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302906 of the Sarbanes-Oxley Act of 2002. |
| |
| Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302906 of the Sarbanes-Oxley Act of 2002. |
| |
| Report of DeGolyer and MacNaughton dated February 19, 2020 concerning evaluation of oil and gas reserves. |
| |
| (101.INS)# | Inline XBRL Instance Document |
| |
| (101.SCH)# | Inline XBRL Taxonomy Extension Schema Document |
| |
| (101.CAL)# | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
| |
| (101.DEF)# | Inline XBRL Taxonomy Extension Definition Linkbase Document |
| |
| (101.LAB)# | Inline XBRL Taxonomy Extension Label Linkbase Document |
| |
| (101.PRE)# | Inline XBRL Taxonomy Extension Presentation Linkbase Document |
| |
| (104)# | The cover page of Penn Virginia Corporation's Annual Report on Form 10-K for the year ended December 31, 2019, formatted in Inline XBRL (included within the Exhibit 101 attachments). |
____________________
| |
| * | Management contract or compensatory plan or arrangement. |
| |
| † | Confidential treatment has been requested for this exhibit and confidential portions have been filed separately with the Securities and Exchange Commission. |
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | |
| | PENN VIRGINIA CORPORATION |
| | |
April 29, 2019 | By: | /s/ STEVEN A. HARTMANRUSSELL T KELLEY, JR. |
| | | Steven A. Hartman Russell T Kelley, Jr. |
| | | Senior Vice President and Chief Financial Officer and Treasurer |
| | (Principal Financial Officer) |
| | | |
April 29, 2019February 28, 2020 | By: | /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 | | Chief Executive Officer and Director | | February 28, 2020 |
| John A. Brooks | | (Principal Executive Officer) | | |
| | | | |
| /s/ RUSSELL T KELLEY, JR. | | Senior Vice President and Chief Financial Officer | | February 28, 2020 |
| Russell T Kelley, Jr. | | (Principal Financial Officer) | | |
| | | | |
| /s/ TAMMY L. HINKLE | | Vice President and Controller | | February 28, 2020 |
| Tammy L. Hinkle | | (Principal Accounting Officer) | | |
| | | | |
| /s/ TIFFANY THOM CEPAK | | Director | | February 28, 2020 |
| Tiffany Thom Cepak | | | | |
| | | | |
| /s/ DARIN G. HOLDERNESS | | Chairman of the Board | | February 28, 2020 |
| Darin G. Holderness | | | | |
| | | | |
| /s/ V. FRANK POTTOW | | Director | | February 28, 2020 |
| V. Frank Pottow | | | | |
| | | | |
/s/ JERRY R. SCHUYLER
| | Director | | February 28, 2020 |
Jerry R. Schuyler
| | | | |
| | | | |
/s/ BRIAN STECK
| | Director | | February 28, 2020 |
Brian Steck
| | | | |
| | | | |
/s/ JEFFREY WOJAHN
| | Director | | February 28, 2020 |
| Jeffrey Wojahn | | | | |
