UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

For the fiscal year ended December 31, 2018

or

For the transition period from                                           to                                          

 

Commission file number: 1-33615

 

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Securities Registered Pursuant to Section 12(g) of the Act:  None 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes ☑ No ☐

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes ☐ No ☑  

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes ☑  No ☐

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes ☑ No ☐  

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ☑

 

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

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   ☐

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes ☐  No ☑

 

 

Documents Incorporated by Reference:

 

Portions of the registrant’s definitive proxy statement for its 2019 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2018, are incorporated by reference into Part III of this Form 10-K for the year ended December 31, 2018.

 

TABLE OF CONTENTS

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements and information contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our future financial position, operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims, disputes and derivative activities. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “will,” “goal” or other words that convey future events, expectations or possible outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events and their potential effect on us. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by any forward-looking statements. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, whether as a result of new information, future events or otherwise, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Item 1A. Risk Factors” in this report, as well as those factors summarized below:

·           declines in, the sustained depression of, or increased volatility in the prices we receive for our oil and natural gas, or increases in the differential between index oil or natural gas prices and prices received;

·           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;

·           the effects of government regulation, permitting and other legal requirements, including new legislation or regulation related to hydraulic fracturing, climate change or derivatives reform;

·           disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil and natural gas and other processing and transportation considerations;

·           risks related to ongoing expansion of our business, including the recruitment and retention of qualified personnel in the Permian Basin;

·           competition in the oil and natural gas industry;

·           risks related to the concentration of our operations in the Permian Basin of Southeast New Mexico and West Texas;

·           the costs and availability of equipment, resources, services and qualified personnel required to perform our drilling, completion and operating activities;

·           environmental hazards, such as uncontrollable flows of oil, natural gas, saltwater, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

·           uncertainties about the estimated quantities of oil and natural gas reserves;

·           risks associated with acquisitions such as increased expenses and integration efforts, failure to realize the expected benefits of the transaction and liabilities associated with acquired properties or businesses;

·           evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;

·           the impact of current and potential changes to federal or state tax rules and regulations;

·           potential financial losses or earnings reductions from our commodity price risk-management program;

·           difficult and adverse conditions in the domestic and global capital and credit markets;

·           the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our Credit Facility, as defined herein;

·           the impact of potential changes in our credit ratings;

·           uncertainties about our ability to successfully execute our business and financial plans and strategies;

·           uncertainties about our ability to replace reserves and economically develop our current reserves;

·           general economic and business conditions, either internationally or domestically; and

·           uncertainty concerning our assumed or possible future results of operations.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and the price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

PART I

 

Item 1. Business

 

General

 

Concho Resources Inc., a Delaware corporation (“Concho,” the “Company,” “we,” “us” and “our”) formed in February 2006, is an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas properties. Our operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. The Permian Basin is one of the most prolific oil and natural gas producing regions in the United States and is characterized by an extensive production history, long reserve life, multiple producing horizons and recovery potential. Concho’s legacy in the Permian Basin provides us a deep understanding of operating and geological trends, and we are actively developing our resource base utilizing large-scale development projects, which include long-lateral wells and multi-well pad locations, throughout our operating areas. Our strategy remains focused on development and exploration activities on our multi-year project inventory, and pursuing acquisitions that meet our strategic and financial objectives.

 

Business and Properties

 

Our operations are focused in the Permian Basin, which underlies an area of Southeast New Mexico and West Texas approximately 250 miles wide and 300 miles long. Commercial accumulations of hydrocarbons occur in multiple stratigraphic horizons, at depths ranging from less than 1,000 feet to over 25,000 feet. At December 31, 2018, our 1,187 MMBoe total estimated proved reserves consisted of approximately 63 percent oil and 37 percent natural gas. We have assembled a multi-year inventory of horizontal development and exploration projects across our operating areas.

 

We have one operating segment and one reporting unit, which is oil and natural gas development, exploration and production. All of our operations are conducted in one geographic area of the United States.

 

On July 19, 2018, we completed the acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”). RSP was an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas reserves in the Permian Basin. The vast majority of RSP’s acreage was located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin. The acquisition added approximately 92,000 net acres to our asset portfolio.

 

Following the RSP Acquisition, we simplified our asset structure, changing from four operating areas to two – comprising the Midland Basin and the Delaware Basin, which includes our assets in the Northern Delaware Basin, Southern Delaware Basin and New Mexico Shelf.

 

The following table summarizes our drilling activity during the periods indicated:

 

Summary of Operating Areas

 

The following is a summary of information regarding our operating areas:

 

 

Operating areas

 

Our operations are focused in the Delaware Basin and the Midland Basin, within the greater Permian Basin. In both areas, we are transitioning our development to large-scale manufacturing mode, which includes leveraging our experience and expertise to maximize resource recovery and program economics while optimizing well spacing, landing intervals, lateral length and completion techniques.

 

Delaware Basin. At December 31, 2018, we had estimated proved reserves in this area of 674 MMBoe, representing  57 percent of our total proved reserves. During the year ended December 31, 2018, we commenced drilling or participated in the drilling of 281 (171 net) wells in this area, and we completed 239 (136 net) wells that are producing.

 

The Delaware Basin is characterized by a thick, resource-rich hydrocarbon column that lends itself to multi-zone development. We leverage leading-edge horizontal drilling and completion technologies, utilizing multi-well pad sites and extended lateral lengths to develop multiple producing formations. Our current activity is focused primarily on the Avalon, Bone Spring and Wolfcamp formations, which generally range from 6,500 feet to 13,500 feet.

 

Midland Basin. At December 31, 2018, we had estimated proved reserves in this area of 513 MMBoe, representing 43 percent of our total proved reserves. During the year ended December 31, 2018, we commenced drilling or participated in the drilling of 147 (95 net) wells in this area, and we completed 111 (68 net) wells that are producing.

 

Our primary objectives in the Midland Basin area are the Spraberry and Wolfcamp formations, which generally range from 7,500 feet to 11,500 feet. We are developing these formations with horizontal drilling, utilizing multi-well pad sites and extended lateral development.

Drilling Activities

 

The following table sets forth information with respect to (i) wells drilled and completed during the periods indicated and (ii) wells drilled in a prior period but completed in the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

 

 

Present activities. The following table sets forth information about wells for which drilling was in-progress or are pending completion at December 31, 2018, which are not included in the above table:

 

Our Production, Prices and Expenses

 

The following table sets forth a summary of our production and operating data for the years ended December 31, 2018, 2017 and 2016. The actual historical data in this table excludes results from the RSP Acquisition for periods prior to July 19, 2018 and our acquisition of certain assets of Reliance Energy, Inc. (the “Reliance Acquisition”) for periods prior to October 2016. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

 

Productive Wells

 

The following table sets forth the number of productive oil and natural gas wells on our properties at December 31, 2018, 2017 and 2016. As of December 31, 2018, we did not have any wells with multiple completions. This table does not include wells in which we own a royalty interest only.

 

 

Marketing Arrangements

 

General. We market our oil and natural gas in accordance with standard energy industry practices. The marketing effort endeavors to obtain the combined highest netback and most secure market available at that time. In addition, marketing supports our operations group as it relates to the planning and preparation of future development activity so that available markets can be assessed and secured. This planning also involves the coordination of access to the physical facilities necessary to connect forthcoming wells as timely and efficiently as possible.

 

Oil. We generally sell production at the lease to third-party purchasers. We generally do not transport, refine or process the oil we produce. Most of our Delaware Basin production in New Mexico is connected to the Alpha Crude Connector, LLC (“ACC”) pipeline system. This production is then primarily purchased by five different purchasers.

 

Most of our Delaware Basin production in Texas is connected to one of five different gathering systems. One of these systems is a crude oil gathering and transportation system operated by a subsidiary of Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity in which we own a 23.75 percent membership interest. A significant portion of our Midland Basin production is on one of seven different gathering systems. The remaining portion of our production is sold via truck transport. We sell our produced oil under contracts using market-based pricing, which is adjusted for differentials based upon delivery location and oil quality.

 

Natural Gas. We consider all natural gas gathering, treating and processing service providers in the areas of our production and evaluate market options to obtain the best price reasonably available given the necessary operating conditions. We sell the majority of our natural gas under individually negotiated natural gas purchase contracts using market-based pricing. The majority of our natural gas is subject to long-term agreements that generally extend five to ten years from the effective date of the subject contract.

  

The majority of our natural gas is casinghead gas, which is sold at the lease location under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. The

purchaser gathers our casinghead natural gas in the field where it is produced and transports it via pipeline to natural gas processing plants where natural gas liquid products are extracted and sold by the processors. The portion of natural gas remaining after liquid extraction is residue gas, which is placed on residue pipeline systems downstream of the processing plant. Under our percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, we receive a percentage of the value for the extracted liquids and the residue gas. Under our fee-based contracts, we receive natural gas liquids and residue gas value, less the fee component thereof, or are invoiced the fee component of the purchaser’s service.

 

Our Principal Customers

 

We sell our oil and natural gas production principally to marketers and other purchasers that have access to pipeline facilities. In areas where there is no practical access to pipelines, oil is transported to storage facilities by trucks owned or otherwise arranged by the marketers or purchasers. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

 

For 2018, revenues from oil and natural gas sales to Plains Marketing and Transportation, Inc. accounted for approximately 18 percent of our total operating revenues. While the loss of this purchaser may result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss of this purchaser would not have a material adverse effect on our operations, as there are alternative purchasers in our producing regions. See Note 13 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

 

Competition

 

The oil and natural gas industry in the areas in which we operate is highly competitive. We encounter strong competition from numerous parties, ranging generally from small independent producers to major integrated companies. We primarily encounter significant competition in acquiring properties. At higher commodity prices, we also face competition in contracting for drilling, pressure pumping and workover equipment and securing trained personnel. Many of these competitors have financial, technical and personnel resources substantially larger than ours. As a result, our competitors may be able to pay more for desirable properties, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

 

In addition to competition for drilling, pressure pumping and workover equipment, we are also affected by the availability of related equipment and materials. The oil and natural gas industry periodically experiences shortages of drilling and workover rigs, equipment, pipe, materials and personnel, which can delay drilling, workover and exploration activities and cause significant price increases. We are unable to predict the timing or duration of any such shortages.

Working Capital

 

Based on current market conditions, we have maintained a stable liquidity position. Our principal source of liquidity is available borrowing capacity under our credit facility, as amended and restated (the “Credit Facility”). At December 31, 2018, we had $242 million of debt outstanding and $1,756 million of unused commitments under our Credit Facility, net of letters of credit. Our primary needs for cash are development, exploration and acquisitions of oil and natural gas assets, payment of contractual obligations and working capital obligations. However, additional borrowings under our Credit Facility or the issuance of additional debt securities will require a greater portion of our cash flow from operations to 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.

 

Applicable Laws and Regulations

 

Regulation of Production

 

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and the plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

 

Environmental, Health and Safety Matters

 

General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into 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 natural 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.

 

These laws, rules and regulations may also restrict the production rate of oil and natural gas below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil or criminal penalties, 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 leasehold acreage. Additionally, environmental laws and regulations are revised frequently, and any changes, including changes in implementation or interpretation, that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

 

The following is a summary of some of the existing laws, rules and regulations to which our business is subject.

 

Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to regulatory guidance issued by the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural

gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and certain environmental organizations entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

 

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for 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. Under CERCLA, such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Each state, including Texas, also has environmental cleanup laws analogous to CERCLA.

 

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose storage, treatment and disposal of hazardous substances, wastes or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination.

 

Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including dredge and fill activities in regulated wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA, or, in some circumstances, the U.S. Army Corps of Engineers (the “Corps”), or an analogous state agency. In addition, spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Further, 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.

 

In September 2015, new EPA and Corps rules to revise the definition of “waters of the United States” (“WOTUS”) for all Clean Water Act programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. To the extent the rule expands the scope of jurisdiction of the Clean Water Act, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” Those regulations will be implemented as they were prior to the effective date of the new WOTUS rule. In January 2017, the U.S. Supreme Court accepted review of the WOTUS rule to determine whether jurisdiction to hear challenges to the rule rests with the federal district or appellate courts. 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 “waters of the United States.” Under the proposal, the first step would be to rescind the May 2015 final rule and put back into effect the narrower language defining “waters of the United States” 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 “waters of the United States.” In January 2018, the Supreme Court ruled that the WOTUS rule must first be reviewed in federal district courts, remanding the case at issue to the district level and putting the status of the Sixth Circuit’s stay of the new rule into question. Citing uncertainty caused by litigation, the EPA subsequently announced a two year stay of the application of the rule as it undertakes its own review of the rule. Federal district court decisions have preserved the stay of the 2015 Clean Water Rule in Texas and New Mexico, which remain subject to pre-2015 WOTUS regulations. Litigation surrounding this rule is ongoing. More recently, on December 11, 2018, the EPA and the Corps released a proposal to revise the 2015 Clean Water Rule so as to narrow the regulatory definition of waters of the U.S., with a

60-day comment period to follow. The scope of the jurisdictional reach of the Clean Water Act will likely remain uncertain for several years.

 

Safe Drinking Water Act. Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations. The drilling and operation of these injection wells are regulated by the federal Safe Drinking Water Act (the “SDWA”). The Underground Injection Well Program under the SDWA 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. Any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and would ultimately increase the cost of our operations, which costs could be significant. For example, in 2014 the Railroad Commission of Texas (the “RRC”) adopted additional permit rules for injection wells to address seismic activity concerns within the state. Among other things, the 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 RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Furthermore, in response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. For example, in 2016, the Oklahoma Corporation Commission issued various orders and regulations applicable to disposal operations in specific counties in Oklahoma. These rules require that disposal well operators, among other things, conduct additional mechanical integrity testing, make sure that their wells are not injecting wastes into targeted formations, and/or reduce the volumes of wastes disposed in such wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase, and our ability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.

 

Air emissions. The federal Clean Air Act (the “CAA”), and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. These and other laws and regulations may increase the costs of compliance for some facilities where we operate. Obtaining or renewing permits also has the potential to delay the development of our projects. 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.

 

For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. By July 2018, the EPA finished issuing area designations with respect to ground-level ozone for U.S. counties as either "attainment/unclassifiable" or "unclassifiable." Reclassification of areas of state implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, in June 2016, the EPA finalized rules under the CAA regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. In a separate rulemaking in June 2016, the EPA finalized new air emission control requirements for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The final rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, and also imposes leak detection and repair requirements on operators. In addition, the rule package extends existing volatile organic compound (“VOC”) standards under the EPA’s Subpart OOOO of the New Source Performance Standards to include previously unregulated equipment within the oil and natural gas source category. However, 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 New Source Performance Standards rule for the oil and gas industry while it reconsiders these aspects of the rule. On September 11, 2018, the EPA proposed targeted improvements to the rule, including amendments to the rule’s fugitive emissions monitoring requirements, and expects to “significantly reduce” the regulatory burden of the rule in doing so. The U.S. Bureau of Land Management (the “BLM”) finalized similar rules in November 2016 that limit methane emissions from new and existing oil and natural 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 to come into compliance with the rule’s requirements. However, in December 2017, the BLM temporarily suspended or delayed certain of these requirements set forth in its Venting and Flaring Rule until January 2019, and in September 2018 the BLM proposed a revised rule which scaled 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 air emission rules have the potential to increase our compliance costs.

 

Climate change. In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases” (“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. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis, including GHG emissions resulting from the completion and workover operations of hydraulically fractured oil wells. Recent federal regulatory action with respect to climate change has focused on methane emissions. As noted above, both the EPA and the BLM finalized rules in 2016 that limit methane emissions from upstream oil and natural gas exploration and production operations. Increased regulation of methane and other GHGs have the potential to result in increased compliance costs and, consequently, adversely affect our operations.

 

On August 3, 2015, the EPA also issued new regulations limiting carbon dioxide emissions from existing power generation facilities. Under these regulations, nationwide carbon dioxide emissions would be reduced by approximately 30 percent from 2005 levels by 2030 with a flexible interim goal. Several industry groups and states challenged the rule. On February 9, 2016, the U.S. Supreme Court stayed the implementation of this rule pending judicial review. On March 28, 2017, President Trump signed an Executive Order directing the EPA to review the regulations, and on April 4, 2017, the EPA announced that it was reviewing the 2015 carbon dioxide regulations. On April 28, 2017, the U.S. Court of Appeals for the District of Columbia stayed the litigation pending the current administration’s review. That stay was extended for another 60 days on August 8, 2017. On October 10, 2017, the EPA initiated the formal rulemaking process to repeal the regulations. In August 2018, the EPA proposed the Affordable Clean Energy rule as a replacement to the 2015 regulations. The EPA’s proposals are subject to public comment and likely legal challenge, and as such, we cannot predict at this time what impact the rulemaking will have on the demand for oil and natural gas production and our operations.

 

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 addition, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

 

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 natural gas we produce. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. It should also be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits 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, 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.

 

Hydraulic fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing as part of our operations. The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel and issued guidance in February 2014 governing such activities. 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 (although the EPA has temporarily suspended or delayed compliance with certain of these standards as they undergo an administrative review); 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 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Moreover, in March 2015, the BLM issued a final rule that imposes requirements on hydraulic fracturing activities on federal and Indian lands, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water. However, the BLM lacked authority to promulgate the rule. While that decision was on appeal, the BLM rescinded this rule in December 2017. In January 2018, the state of California and a coalition of environmental groups filed a lawsuits in the Northern District of California to challenge the BLM’s rescission of the 2015 rule. This litigation is ongoing and future implementation of the rule is uncertain at this time.

 

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, New Mexico and Texas have adopted hydraulic fracturing fluid disclosure requirements, 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. In addition, local governments have also taken steps to regulate hydraulic fracturing, including imposing restrictions or moratoria on oil and natural gas activities occurring within their boundaries. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

 

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

 

We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our well control, general liability and excess liability insurance policies may cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies. If new laws or regulations significantly restrict hydraulic fracturing activities or impose burdens on new permitting or operating requirements, our ability to utilize hydraulic fracturing may be curtailed, and this may in turn reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

 

Operations on Federal Lands.  We currently operate on federal lands under the jurisdiction of the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the state permitting process. Delays in obtaining permits necessary can disrupt our operations and have an adverse effect on our business. As noted above, in November 2016, the BLM finalized rules that restrict methane emissions from oil and natural gas activities on federal lands by limiting venting and flaring of natural gas from wells and other equipment. The final rule also requires operators to pay royalties to the BLM on flared gas from wells already connected to gas capture infrastructure, and allows the agency to set royalty rates at or above 12.5 percent of the value of production. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations.

 

Endangered species.  The federal Endangered Species Act (the “ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete drilling and developmental operations and could adversely affect our future production from those areas. The designation of previously unprotected species as threatened or endangered in areas where we or our oil and natural gas exploration and production customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our midstream services.

 

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the 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 that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and

development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or even halt development of some of our oil and natural gas projects.

 

OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety.

 

We are not aware of any existing environmental issues, claims or regulations that will require us to incur material capital expenditures during 2019, and we did not incur material capital expenditures relating to environmental issues, claims or regulations during 2018. However, we cannot assure that the passage or application of more stringent laws or regulations or the application of existing laws in the future will not require us to incur material capital expenditures or have a material adverse effect on our financial position or results of operations.

 

Our Employees

 

Our corporate headquarters are located at One Concho Center, 600 West Illinois Avenue, Midland, Texas 79701. We also maintain various field offices in Texas and New Mexico. At December 31, 2018, we had 1,503 employees, 569 of whom were employed in field operations. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be good.

 

Available Information

 

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the U.S. Securities and Exchange Commission (the “SEC”) under the Exchange Act. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge through our website, www.concho.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

Non-GAAP Financial Measures and Reconciliations

 

Reconciliation of Standardized Measure to PV-10

 

PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

 

The following table provides a reconciliation of the GAAP standardized measure of discounted future net cash flows to PV-10 (non-GAAP) at December 31, 2018, 2017 and 2016: