PROPERTIES

Overview

As of December 31, 2017 , we have one key area of production: the Denver-Julesburg Basin ("DJ Basin").

The Company's acreage positions in the DJ Basin are predominantly located in Colorado's eastern plains and parts of southeastern Wyoming.

Key Statistics

 

The DJ Basin is a high growth oil development area where operators are targeting the Niobrara and Codell formations and employing new technologies to optimize oil recoveries and economic returns. We believe that the DJ Basin offers us significant growth opportunities with potential acreage additions to our current leasehold position, possible development of additional formations, increased utilization of extended reach (long lateral) horizontal wells, well completion optimization and ongoing cost reduction.

The DJ Basin is a core area of operation where we drilled 69 gross (56.1 net) operated wells and placed 54 gross (44.0 net) operated wells on initial flowback in 2017. The Company had one rig operating at the beginning of 2017 and added an additional rig in July of 2017 for a total of two rigs for the remainder of the year. In 2017, we focused on drilling extended reach horizontal wells in the Niobrara formation across the Northeast Wattenberg area of the DJ Basin, continuing to optimize our completion technology and establishing a scalable development program. The combination of this development along with nearby competitor activity continued to de-risk our acreage in the area.

Currently, we are utilizing two rigs in the DJ Basin; however, we expect to add a third rig after closing the Merger. We may elect to accelerate or delay drilling throughout 2018 as business conditions and operating results warrant. The 2018 operated drilling program will focus on drilling extended reach wells (9,200 foot laterals). In addition, we anticipate minimal participation in non-operated wells.

Our oil production from the DJ Basin is sold at the lease and trucked to markets. Our gas production from the DJ Basin is gathered and processed by third parties and we receive residue gas and NGL revenue under percentage of proceeds contracts.

 

Oil and Gas Data

Proved Reserves

The following table presents our estimated net proved oil, natural gas and NGL reserves at each of December 31, 2017 , 2016 and 2015 based on reserve reports prepared by us and audited by independent third party petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our reserve estimates independently audited, such an audit is required under our Amended Credit Facility. All of our proved reserves included in our reserve reports are located in North America. Netherland, Sewell & Associates, Inc. ("NSAI") audited all of our reserves estimates at December 31, 2017 , 2016 and 2015 . NSAI is retained by and reports to the Reserves and EHS Committee of our Board of Directors, which is comprised of independent directors. When compared on a well-by-well or lease-by-lease basis, some of our internal estimates of net proved reserves are greater and some are less than NSAI's estimates. However, in the aggregate, NSAI's estimates of total net proved reserves are within 10% of our internal estimates. In addition to a third party audit, our reserves are reviewed by our Reserves and EHS Committee. The Reserves and EHS Committee reviews the final reserves estimates in conjunction with NSAI's audit letter and meets with the key representative of NSAI to discuss NSAI's review process and findings.

The data in the above table represent estimates only. Oil, natural gas and NGLs reserve engineering is an estimation of accumulations of oil, natural gas and NGLs that cannot be measured exactly. The accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary from the quantities of oil, natural gas and NGLs that are ultimately recovered. See "Item 1A. Risk Factors".

The following tables illustrate the history of our proved undeveloped reserves from December 31, 2015 through December 31, 2017 :

over the next three years. However, the timing of such drilling is subject to change based on a number of factors, many of which are unpredictable and beyond our control, such as changes in commodity prices, anticipated cash flows and projected rate of return, access to capital, new opportunities with better returns on investment that were not known at the time of the reserve report, asset acquisitions and/or sales and actions or inactions of other co-owners or industry operators. As such, the relative proportion of total proved undeveloped locations that we develop may not necessarily be uniform from year to year, but could vary by year based upon the foregoing factors. We attempt to maximize the rate of return on capital deployed, which requires that we continually review all investment options available. As a result, at times we may delay or remove the drilling of certain projects, including scheduled proved undeveloped locations, in favor of projects with more attractive rates of return, leading us to deviate from our original development plan.

    

At December 31, 2017 , our proved undeveloped reserves were 44.3 MMBoe. At December 31, 2016 , our proved undeveloped reserves were 18.5 MMBoe. During 2017 , 13.0 MMBoe, or 70% of our December 31, 2016 proved undeveloped reserves ( 51 wells), were converted into proved developed reserves and required $136.8 million of drilling and completion capital and $11.9 million of facilities capital. These wells produced 2.2 MMBoe in 2017 . During 2017 , we added 31.7 MMBoe of proved undeveloped reserves due to drilling programs in our core development area. Positive engineering revisions increased proved undeveloped reserves by 10.8 MMBoe. During 2017 , 3.9 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans within the five year development window allowed at the time the applicable proved undeveloped reserves were booked. Positive pricing revisions increased proved undeveloped reserves by 0.2 MMBoe. The proved undeveloped reserves from December 31, 2016 that remained in the proved undeveloped reserves category at December 31, 2017 were 1.6 MMBoe.

At December 31, 2016, our proved undeveloped reserves were 18.5 MMBoe. At December 31, 2015, our proved undeveloped reserves were 43.9 MMBoe. During 2016, 8.5 MMBoe, or 19% of our December 31, 2015 proved undeveloped reserves (21 wells), were converted into proved developed reserves and required $55.3 million of drilling and completion capital and $5.3 million of facilities capital. These wells produced 1.3 MMBoe in 2016. During 2016, we added 8.4 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. Negative engineering revisions decreased proved undeveloped reserves by 0.7 MMBoe. During 2016, 24.3 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans within the five year development window allowed at the time the applicable proved undeveloped reserves were booked. Negative pricing revisions decreased proved undeveloped reserves by 0.3 MMBoe. The proved undeveloped reserves from December 31, 2015 that remained in the proved undeveloped reserves category at December 31, 2016 were 9.6 MMBoe.

At December 31, 2015, our proved undeveloped reserves were 43.9 MMBoe. At December 31, 2014, our proved undeveloped reserves were 80.8 MMBoe. During 2015, 8.1 MMBoe, or 10% of our December 31, 2014 proved undeveloped reserves (35 wells), were converted into proved developed reserves and required $165.3 million of drilling and completion capital and $5.0 million of facilities capital. These wells produced 0.9 MMBoe in 2015. During 2015, we added 2.6 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. Positive engineering revisions increased proved undeveloped reserves by 1.3 MMBoe. During 2015, 14.7 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans and were either traded, sold or removed. This volume includes 12.2 MMBoe of proved undeveloped reserves sold in the divestiture of our non-core DJ and Uinta Basin properties. Negative pricing revisions decreased proved undeveloped reserves by 18.0 MMBoe. The proved undeveloped reserves from December 31, 2014 that remained in the proved undeveloped reserves category at December 31, 2015 were 40.8 MMBoe.

We use our internal reserves estimates rather than the estimates of an independent third party engineering firm because we

believe that our reservoir and operations engineers are more knowledgeable about the wells due to our continual analysis throughout the year as compared to the relatively short term analysis performed by third party engineers. We use our internal reserves estimates on all properties regardless of the positive or negative variance relative to the estimates of third party engineers. If a variance greater than 10% occurs at the field level, it may suggest that a difference in methodology or evaluation techniques exists between us and the third party engineers. We investigate any such differences and discuss the differences with the third party engineers to confirm that we used the proper methodologies and techniques in estimating reserves for the relevant field. These variances also are reviewed with our Reserves and EHS Committee. These differences are not resolved to a specified tolerance at the field or property level. In the aggregate, the third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates.

The internal review process of our wells and the related reserves estimates, and the related internal controls we utilize, include but are not limited to the following:

Within our Company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is William K. Stenzel. Mr. Stenzel is our Senior Vice President of Corporate Development and Planning and became responsible for our reserves estimates starting in September 2014. Mr. Stenzel earned a Bachelor of Science degree in Civil Engineering from Colorado State University in 1977. Mr. Stenzel has over 40 years of experience in reserves and economic evaluations, as well as a broad experience in production, completions, reservoir analysis and planning and development.

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader in petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Benjamin W. Johnson and Mr. John G. Hattner. Mr. Johnson, a Licensed Professional Engineer in the State of Texas (No. 124738), has has been practicing consulting petroleum engineering at NSAI since 2007 and has over two years of prior industry experience. He graduated from Texas Tech University in 2005 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 559), has been practicing consulting petroleum geoscience at NSAI since 1991, and has over 11 years of prior industry experience. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of

Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

NSAI performed a well-by-well audit of all of our properties and of our estimates of proved reserves and then provided us with its audit report concerning our estimates. The audit completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These audit procedures may be the same as or different from audit procedures performed by other independent third party engineering firms for other oil and gas companies. NSAI's audit report does not state the degree of its concurrence with the accuracy of our estimate of the proved reserves attributable to our interest in any specific basin, property or well.

The NSAI audit process is intended to determine the percentage difference, in the aggregate, of our internal net proved reserves estimate and future net revenue (discounted at 10%) and the reserves estimate and net revenue as determined by NSAI. The audit process includes the following:

The reserves audit letter provided by NSAI states that "in our opinion the estimates shown herein of Bill Barrett's reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards." The audit letter also includes a statement of dates pertaining to the NSAI work performed, the methodology used, the assumptions made and a discussion of uncertainties that they believe are inherent in reserves estimates.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown in the Financial Statements should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board pronouncements ("FASB"), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage NSAI to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. NSAI and its employees have no interest in those properties, and the compensation for these engagements is not contingent on NSAI's estimates of reserves and future cash inflows for the subject properties. During 2017 and 2016 , we paid NSAI approximately $202,000 and $150,000, respectively, for auditing our reserves estimates.

Production and Cost History

The following table sets forth information regarding net production of oil, natural gas and NGLs and certain cost

information for each of the periods indicated:

Substantially all of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth, as of December 31, 2017 , the expiration periods of the net undeveloped acres by area that are subject to leases summarized in the above table of undeveloped acreage.

Drilling Results

The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities or value of reserves found.

Operations

General

In general, we serve as operator of wells in which we have a greater than 50% working interest. In addition, we seek to be the operator of wells in which we have lesser interests. As operator, we obtain regulatory authorizations, design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or the majority of the other oil field service equipment used for drilling or maintaining wells on the properties we operate. Independent contractors engaged by us provide the majority of the equipment and personnel associated with these activities. We construct, operate and maintain gas gathering and water facilities associated with our operations. We employ drilling, production and reservoir engineers and geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Marketing and Customers

We market all of the oil production from our operated properties. Our natural gas and related NGLs are generally marketed by third parties under percentage of proceeds ("POP") contracts. We sell our oil production to a variety of purchasers under contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. Purchasers include pipelines, processors, refineries, marketing companies and end users. We normally sell production to a relatively small number of customers, as is customary in the development and production business. Our natural gas and related NGLs are sold primarily to two gas gathering and processing companies. Based on where we operate and the availability of other purchasers and markets, we believe that our production could be sold in the market in the event that it is not sold to our existing customers. However, in some circumstances, a change in customers may entail significant transition costs. From a larger perspective, a reduction in market demand, such as a possible shift to electric vehicles, represents an additional risk factor.

During 2017 , three customers individually accounted for over 10% of the Company's oil, gas and NGL production revenues. During 2016 , three customers individually accounted for over 10% of the Company's oil, gas and NGL production revenues. During 2015 , four customers individually accounted for over 10% of the Company's oil, gas and NGL production revenues.

We enter into hedging transactions with unaffiliated third parties for portions of our production to achieve more predictable cash flows and to reduce our exposure to fluctuations in commodities prices. For a more detailed discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk".

Our oil production is collected in tanks on location and sold to third parties that collect the oil in trucks and transport it to pipelines, rail terminals and refiners. We sell our oil production to a variety of purchasers under monthly, annual or multi-year terms. Our oil contracts are priced off of New York Mercantile Exchange ("NYMEX") with quality, location or transportation

differentials.

The following table sets forth information about material long-term firm natural gas pipeline transportation contracts, which entail a demand charge for reservation of capacity. These contracts were initiated to provide a guaranteed outlet for company marketed production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. These transportation costs are included in unused commitments expense in the Consolidated Statements of Operations.

Hedging Activities

Our hedging program is intended to mitigate the risks of volatile prices of oil, natural gas, and NGLs. Our strategic objective is to hedge 50%-70% of our anticipated production on a forward 12-month to 18-month basis. As of February 6, 2018 , we have hedged 3,674,500 barrels of oil and 1,825,000 MMbtu of natural gas and 1,914,750 barrels of oil for our 2019 production at price levels that provide some economic certainty to our cash flows. Currently, seven of our 13 lenders (or affiliates of lenders) under our credit facility are also hedging counterparties. We are not required to post collateral for these hedges other than the security for our credit facility. For additional information on our hedging activities, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk".

Competition

The oil and gas industry is intensely competitive, and we compete with a large number of other companies, some of which have greater resources. See the risk discussed below in "Item 1A. Risk Factors" under the caption " Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed" .

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved developed reserves. Prior to the commencement of drilling operations on those properties, we typically conduct a title examination and perform curative work for significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing such defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we utilize methods consistent with practices customary in the oil and gas industry and that our practices are adequately designed to enable us to acquire satisfactory title to our producing properties. Prior to completing an acquisition of producing oil and gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil, natural gas and NGL producing properties are subject to customary royalty and other interests, liens for current taxes, liens under our Amended Credit Facility and other burdens that we believe do not materially interfere with the use of our properties.

Environmental Matters and Regulation

General . Our operations are subject to comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment, management of E&P waste, or otherwise relating to environmental protection and minimization of aesthetic impacts. Our operations are generally subject to the same environmental laws and regulations as other companies in the oil and gas exploration and production industry. These laws and regulations:

These laws, rules and regulations may also restrict the rate of oil, natural gas and NGLs production below the rate that would otherwise be possible, for example, by limiting the flaring of associated natural gas from an oil well while awaiting a pipeline connection. The regulatory burden on the oil and gas industry increases the cost and delays the timing of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs.

We have made and will continue to make expenditures in our efforts to comply with all environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and not extraordinary. We believe that our compliance with existing requirements has been accounted for and will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of any more stringent future laws and regulations. For the year ended December 31, 2017 , we did not incur any material capital expenditures for remediation of well sites or production facilities or to retrofit emission control equipment at any of our facilities. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and regulations, including organized, well-funded "keep it in the ground" efforts to turn public opinion against the use of fossil fuels.

The environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business are as follows:

National Environmental Policy Act . Oil, natural gas and NGLs exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Departments of the Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project and project alternatives. If impacts are considered significant, the agency will prepare a more detailed Environmental Impact Statement. These environmental analyses are 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 trigger the requirements of NEPA. Certain federal permits on non-federal lands may also trigger NEPA requirements. This process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Waste Handling . The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes affect oil and gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of "hazardous wastes" and on the disposal of non-hazardous wastes. Under the oversight of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms for non-compliance with RCRA or corresponding state programs. RCRA also imposes cleanup liability related to the mismanagement of regulated wastes. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil, natural gas, or geothermal energy are currently exempt from regulation under the hazardous waste provisions of RCRA, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation, and legislation has been proposed from time to time in Congress to reverse the exemption. In addition, certain environmental groups have petitioned and sued the EPA to reverse the exemption. The EPA has entered into a consent decree with these environmental groups that commits the EPA to deciding whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector by March 2019.

Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our

budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act . The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, imposes strict, joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be potentially responsible for a release or threatened release of a "hazardous substance" (generally excluding petroleum) into the environment. These persons may include current and past owners or operators of a disposal site, or site where the release or threatened release of a "hazardous substance" occurred, and companies that disposed of or arranged for the disposal of the hazardous substance at such sites. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims under CERCLA and/or state common law for cleanup costs, personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, could be subject to CERCLA. Governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such "hazardous substances" have been released.

Water Discharges . The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced water, storm water drainage and other oil and gas wastes, into Waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws also prohibit the discharge of dredge and fill material in regulated waters, including jurisdictional wetlands, unless authorized under a permit issued by the U.S. Army Corps of Engineers ("Corps"). Federal and state regulatory agencies can impose administrative penalties, civil and criminal penalties, and take judicial action for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs may also limit the total volume of water or fill material that can be discharged, hence limiting the rate of development. The EPA and the Corps finalized a federal rulemaking to revise the jurisdictional definition of "Waters of the United States" in June 2015. The final rule currently is stayed and not effective pending ongoing litigation. In January 2018, the EPA signed a final rule delaying the applicability date of the "Waters of the United States" rule for several years while the EPA continues to conduct a substantive re-evaluation of the definition of "Waters of the United States." The final rule, if and when effective, may expand the definition of "Waters of the United States" to include wetlands, tributaries and other waters that are not currently regulated. This definition would subject certain activities in those waters to permitting under the Clean Water Act, including permitting under Section 404 of the Clean Water Act for various activities, including wetlands development. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs may also limit the total volume of water or fill material that can be discharged, hence limiting the rate of development.

Air Emissions. The Federal Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits, emission reporting, and the imposition of emission control requirements. Most of our facilities are now required to obtain permits before work can begin, and existing facilities are often required to incur additional capital costs in order to maintain compliance with laws and regulations. In 2012, the EPA issued new New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) specific to the oil and gas industry, including air standards for natural gas wells that are hydraulically fractured, and issued several amendments to the NSPS rules in 2013 and 2014, respectively. In addition, the EPA has deemed carbon dioxide ("CO2") and other greenhouse gases, including methane, to be a danger to public health, which is leading to regulation of greenhouse gases in a manner similar to other pollutants. For example, the EPA finalized new regulations focused on methane emissions from the oil and gas industry in June 2016. Although the EPA has proposed a two-year stay of the effective dates of several requirements of these regulations, they are currently in effect. The Bureau of Land Management also finalized similar methane and gas-capture rules for oil and gas operations on federal and tribal leases and certain committed state or private tracts in a federally approved unit or communitized agreement. These rules are subject to ongoing litigation. In December 2017, the BLM published a rule to temporarily suspend or delay certain rule requirements until January 2019; that rule is also the subject of litigation in federal court. The EPA already requires reporting of greenhouse gases, such as CO2 and methane, from operations. In 2014 and 2017, Colorado expanded its oil and gas air regulations, including the adoption of new and additional fugitive methane emission control regulations. In addition, the EPA has lowered the national ambient air quality standard ("NAAQS") for ozone pollution, which may require the oil and gas industry to further reduce emissions of volatile organic compounds and nitrogen oxides. Further, Colorado's ozone non-attainment status was bumped-up from "marginal" to "moderate," which triggered significant additional obligations for the State under the Clean Air Act and resulted in additional regulatory requirements for the oil and gas industry. The Denver Metro/North Front Range NAA is at risk of being reclassified again to "serious" if it does not meet the 2008 NAAQS by 2018 or obtain an extension of the deadline from the EPA. A "serious" classification would trigger significant

additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements becoming applicable to our operations and significant costs and delays in obtaining necessary permits. This process could result in new or more stringent air quality control requirements applicable to our operations. These state and federal regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations.

Hydraulic Fracturing. Our completion operations are subject to regulation, which may increase in the short or long-term. The well completion technique known as hydraulic fracturing is used to stimulate production of natural gas and oil and has come under increased scrutiny by the environmental community, as well as local, state and federal jurisdictions. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into prospective rock formations at depth to stimulate oil and natural gas production. We use this completion technique on substantially all of our wells to obtain commercial production.

Under the direction of Congress, the EPA has undertaken a study of the effect, if any, of hydraulic fracturing on drinking water and groundwater and released its preliminary report in 2015, finding no systematic impact on groundwater resources. In its final report, issued in late 2016, EPA removed the conclusion of no systemic impact from the executive summary of the report, although it cited no new evidence to the contrary. In April 2015, EPA has also published proposed pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations. Congress may consider legislation to amend the Federal Safe Drinking Water Act or the Toxic Substances Control Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, have already issued such disclosure rules. Several environmental groups have also petitioned the EPA to extend release reporting requirements under the Emergency Planning Community Right-to-Know Act to the oil and gas extraction industry and in 2015, EPA granted, in part, one of these petitions to add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under the Toxic Release Inventory ("TRI"). On January 6, 2017, EPA issued a proposed rule to include natural gas processing facilities within the TRI program. In addition, the Department of the Interior finalized expanded or new regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes some of the lands on which we conduct or plan to conduct operations. The BLM rescinded the rule in December 2017; however, the BLM's rescission has been challenged by several states in the United States District Court of the District of Northern California. In Colorado, certain local jurisdictions imposed moratoria or bans on hydraulic fracturing, all of which have been invalidated, including on appeal to the Colorado Supreme Court. In 2016, citizen initiatives to empower local governments to regulate or prohibit oil and gas development, and to impose a 2,500' statewide setback from occupied buildings and a variety of water ways and other natural resource areas failed to attract enough signatures to be certified for the ballot. On the other hand, another ballot initiative, supported by the industry and business community, as well as a number of elected officials made the ballot and was approved by the electorate. This "Raise the Bar" initiative was designed to make it much more difficult to qualify ballot initiatives to amend the state constitution, and raised the vote threshold to enact such measures into law. However, the more stringent ballot qualification standard has come under judicial review and may be stricken. Disputes at the local level regarding high-intensity oil and gas development in proximity to residential areas have not subsided and local ordinances or state legislation may be proposed that could result in additional restrictions on oil and gas development in some areas of Colorado. The Company participates in industry organizations mobilized to combat such measures, including by litigation where necessary.

Climate Change. In June 2014, the U.S. Supreme Court upheld a portion of the EPA's greenhouse gas regulatory program for certain major sources in the Utility Air Regulatory Group v. EPA case. The EPA has finalized significant new rules to curb carbon emissions from power plants and other industrial activities, known as the Clean Power Plan, which in February 2016 was stayed by the U.S. Supreme Court. In March 2017, President Trump signed the Executive Order on Energy Independence which, among other things, called for a review of the Clean Power Plan. The EPA subsequently published a proposed rule to repeal the Clean Power Plan in October 2017. A final rule is expected following a comment period. Certain environmental groups are agitating for scaling back, or eliminating, fossil fuel extraction and use, including efforts to convince policy-makers that the majority of known oil and gas reserves must never leave the ground. These groups are mobilizing around a movement for global divestment from fossil fuel companies, which, if effective, could affect the market for our securities. Recently, the University of Colorado and the University of Denver have rejected proposed divestment measures. In addition, in December 2015 the United States reached agreement during the United Nations climate change conference in Paris to make a 26-28% reduction in its greenhouse gas emissions by 2025 against a 2005 baseline. In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement. Potential future laws, regulations or even litigation addressing greenhouse gas emissions could impact our business by limiting emissions of methane, restricting the flaring or venting of natural gas, or by reducing demand for oil or natural gas.

Homeland Security . Legislation continues to be introduced in Congress, and development of regulations continues in the

Department of Homeland Security and other agencies, concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations but cost of compliance cannot be accurately estimated at this time. Cybersecurity has been a topic of increased focus, and we have implemented several cybersecurity measures, including an emergency response plan, annual employee training, penetration tests, Supervisory Control and Data Acquisition ("SCADA") protection and firewall upgrades. We have installed a comprehensive software package to track and document our cybersecurity initiatives which are reviewed by the Executive Committee and Board on a regular basis. Our cybersecurity initiatives are an increasingly important function of our Information Technology and Legal Departments. Presently, it is not possible to accurately estimate the costs we could incur to respond to a cyber attack, but such expenditures could be substantial.

Other Regulation of the Oil and Gas Industry

Our operations are subject to other types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, bonds securing plugging, abandonment and reclamation obligations, and reports concerning our operations. Most states, and some counties and municipalities also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing well density and location, as well as the pooling of oil and natural gas properties. Some states provide statutory mechanisms for compulsory pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, compulsory pooling or unitization may be implemented by third parties and subject our interest to third party operations. While not currently an issue in Colorado, other states establish maximum rates of production from oil and natural gas wells and impose requirements regarding ratable takes by purchasers of production. Such laws and regulations, if adopted in Colorado, might limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, our production is generally subject to multiple layers of severance and/or ad valorem taxation by states, counties and special taxing districts.

Natural Gas Sales and Transportation . Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission ("FERC") has jurisdiction over the transportation and sale or resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for "first sales" of domestic natural gas, which include all sales of our own production.

FERC also regulates interstate natural gas transportation rates and service conditions pursuant to the Natural Gas Act, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Interstate gas pipeline companies are required to provide nondiscriminatory, non-preferential transportation services to producers, marketers and other shippers regardless of whether such shippers are affiliated with an interstate pipeline company, and pursuant to such orders, regulations, and rules, interstate gas pipeline companies are required to file the tariff rates and other terms and conditions of such services with FERC.

The Energy Policy Act of 2005 (the "EPAct 2005") was signed into law in August 2005. The EPAct 2005 amends the Natural Gas Act to make it unlawful for "any entity", including otherwise non-jurisdictional producers, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. The EPAct 2005 also gives FERC authority to impose civil penalties for violations of the Natural Gas Act or Natural Gas Policy Act up to $1 million per day per violation. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the

activities are conducted "in connection with" natural gas sales, purchases or transportation subject to FERC jurisdiction, thus reflecting a significant expansion of FERC's enforcement authority.

FERC's initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach pursued by FERC and Congress over the past few decades will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes may have on our natural gas-related activities.

Employees

As of February 6, 2018 , we had 110 employees of whom 81 work in our Denver office and 29 work in our field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are good.

Offices

As of December 31, 2017 , we leased approximately 81,833 square feet of office space in Denver, Colorado at 1099 18th Street, where our principal offices are located. The lease for our Denver office expires in March 2019. We also own a field office in Greeley, Colorado. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.